SEPCo 20Hole Cleaning 20Manual 1

SHELL EXPLORATION AND PRODUCTION COMPANY

HOLE CLEANING BEST PRACTICES QUICK GUIDE

Revision 0

April 2003

SEPCo HOLE CLEANING BEST PRACTICES QUICK GUIDE The concept of “Drilling in the Box” is used to represent the engineering required in the planning and execution stages of a well in order to optimize hole cleaning as part of the entire drilling system. The inside of the box represents an environment of “good hole cleaning”, with the sides representing the limits that must be taken into account in order to remain in the box. Throughout the planning and execution phases of a well, it must be remembered that changes to one parameter will impact others, and a systems approach must be applied to all decisions, to remain within “the box”.

The “PLANNING BOX”

Rig Capability

Mud Selection

Soft Issues

ECD Planning THE SOFT ISSUES s WELL DESIGN (wellpath, casing size and depth, PP/FG window, modeling) ing ice nn ct WELLBORE STABILITY (mud, practices, sag, ECD) u a R Pr g DRILLSTRING DESIGN (pipe size, pipe specifications, fatigue, casing wear, mechanical tools) ion n t i le ipp RIG CAPABILITY (pumps, standpipe, top drive, power, solids control, PM, hoisting) mp Tr o C & MUD SELECTION (mud type, properties, sag) nd ng i a l l i ECD PLANNING (wellpath, casing, mud, drillstring) ing Dr as Drillstring Desig C DIRECTIONAL DRILLING STRATEGIES (Bit & BHA types) n CASING & COMPLETION RUNNING (modeling, surge pressures) DRILLING & TRIPPING PRACTICES (parameters, practices) ie s eg t ra ign St es g D lin ell ril “Good hole cleaning performance W D l na o doesn’t just happen … it must be i ct re engineered into the design” Di Wellbore Stabilit y

The “EXECUTION BOX”

le

me Re Mechanical Tools

Mud Properties

Tripping Practices

Ho

Drilling Parameters and Practices

ECD Managemen t

s

le

C

on iti d on

Mo

o nit

g rin

RTOC

THE SOFT ISSUES DIRECTIONAL DRILLING PRACTICES

(BHA design, strategy,

practices)

Soft Issues

Ho l a di

C

g nin a le

P

e tic c ra

MECHANICAL TOOLS (PBL, jet subs, bladed drillpipe, other) DRILLING PARAMETERS AND PRACTICES (RPM, flowrate, ROP, connection practices, modeling)

MUD PROPERTIES (weight, rheology, PV’s, barite sag, gas cut mud) ECD MANAGEMENT (mud, PWD, procedures, post run analysis) HOLE CONDITION MONITORING (T&D, cuttings load & description, downhole drilling dynamics tools, PP/FG monitoring)

REMEDIAL HOLE CLEANING PRACTICES

re Di

ng illi r D al n o i ct

es tic c a pr

(cleanup cycles, sweeps,

backreaming)

TRIPPING PRACTICES (cleanup cycles, tripping, backreaming) RTOC (Real Time Operations Center)

“Sometimes you have to go slow to go fast”

PROPRIETARY Shell Exploration and Production Company

UNDERSTANDING THE THEORY Understanding the basic theory presented below is necessary prior to considering the hole cleaning guidelines that follow.

What is happening to the cuttings downhole?

There are three distinct inclination ranges where cuttings will behave differently, and thus strategies for hole cleaning will also differ. Note in a high inclination high angle well, all three ranges will be seen in a single wellbore. In wells with inclinations in the range of 35° - 60°, cuttings begin to form “beds”, as the distance for them to fall to bottom is now measured in inches. The cuttings move up the hole mostly on the low side, but can be easily stirred up into the flow regime. The most notable feature of this inclination range is that when the pumps are shut off, the “beds” will begin to slide (or avalanche) downhole. There is an increased risk of pack-offs and stuck pipe occurring in this range.

Hole Cleaning Quick Guide Rev 0

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Apr 2003

PROPRIETARY Shell Exploration and Production Company 35°--35° 0° 60°

In a vertical to 35° degree well, cuttings are brought to the surface by combating cutting slip velocity, where the cutting must fall thousands of feet to reach the bottom of the hole. Hole cleaning is simply provided by the viscosity and flowrate of the drilling fluid. When the pumps are turned off, cuttings are suspended by the thixotropic drilling fluid, although some settling will occur with time.


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Apr 2003


60° - 90+°


Between 60° - 90°, the cuttings fall to the low side of the hole and form a long, continuous cuttings bed.Page Although 5 the challenges associated with an avalanching bed have gone away, hole cleaning in this environment is still difficult, and often more time consuming.

Apr 2003

PROPRIETARY Shell Exploration and Production Company Cuttings Movement With Flow Cuttings Movement Without Flow

What happens to the fluid flow at high inclinations?

Without rotation, the fluid in a high angle wellbore simply flows up the high side, and cuttings transport is very limited. Bed heights can quickly become intolerable in this case. VERTICAL WELLBORE

HIGH ANGLE WELLBORE

What is a clean hole?

“A wellbore with a cuttings bed height and distribution such that operations are trouble free” Based on the definition above, the tolerable cuttings bed height and distribution will not be the same for all operations. Hole cleaning practices should be developed in respect to the following distinct operations:

Drilling - cuttings beds can be higher for drilling because the BHA is not being pulled through them (good clearance). Bed height will be limited by pack-off, ECD and excessive T&D. Fluid and cuttings move uniformly in annulus

High Velocity Fluid

Low Velocity Fluid

Tripping – cuttings beds will need to be lower as the BHA with stabilizers and bit restrictions are pulled back through the cuttings bed (minimal clearance and flowby area). Casing Running – depending on the annular clearance and slack-off weight available, there may be very little tolerance for cuttings beds being pushed in front of the casing (i.e. increased friction). This may require minimal or no cuttings bed remaining in the hole.

Cuttings on the low side will not be disturbed by fluid unless stirred up by pipe rotation


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Apr 2003


How are cuttings removed from the Hole? Resultant Drillpipe Gravity High As Force Drillpipe cuttings velocity from rotation force onare flow pushed turns area up at the top holeof by Cutting the lowside the the on Fluid conveyor high cutting hole of flow velocity hole acts belt like fluid, onaas conveyor gravity acts belt to transporting pull it lifts them theback cuttings theto cuttings the lowside up the ofhole the back hole.onto Eventually the conveyor the cuttings will fall off the belt. conveyor belt due to the summation of these forces. Flowrate governs the speed of the conveyor belt and how long the cuttings stay on it.


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Apr 2003


What parameters are required? DESIRABLE

FOR

GOOD HOLE CLEANING

MINIMAL

FOR

EFFECTIVE HOLE CLEANING

HOLE SIZE

FLOWRATE (gpm)

RPM

FLOWRATE (gpm)

RPM

17½”

900 – 1200

120 – 150

800

120

14½”

850 – 1150

120 – 170

800

120

12¼”

800 – 1100

150 – 180

650 - 700

120

9⅞”

700 – 900

120 – 150

500

100

8½”

450 - 600

70 – 100

350 - 400

60

Note that the values shown in the table above should only be used as a generic guideline. The minimal values are based on the use of good hole cleaning practices in conjunction with these reduced parameters. Caution: vibrations due to bit and BHA excitation (e.g. with bi-center bits, steerable assemblies) should always be considered / monitored with high rpm’s.


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Apr 2003


“PLANNING BOX” HIGH LEVEL GUIDELINES The following high level guidelines should be reviewed in the planning stage of the well design, to ensure that all aspects of the hole cleaning system have been considered. If further details or background are required, refer to the relevant sections in the manual.

THE SOFT ISSUES

WELL DESIGN

WELLBORE STABILITY


•

Commitment and alignment is required at all levels. This should be accomplished through training during the planning phase of the well. Everyone must understand the risks and the “what”, “why”, and “how” of success.

•

There are many design issues that need to be considered, and specific training should be a prerequisite for engineers involved in planning these wells. Note that there is little scope for optimization in the execution phase if the planning has not been successful in designing out the limitations.

•

High angle wells cannot be planned in the same manner as vertical or low angle directional wells. There is generally little margin for error, as well as significant implications when things do go wrong. Adequate time and resources should be allotted to planning high angle wells. It must not be assumed that these wells will drill the same as vertical wells, and detailed offset analysis and modeling will be required.

•

Operations personnel should be involved from the early stages of planning to facilitate ownership in the plans, as well as to highlight significant operational issues that will impact the well design.

•

High angle wells should be planned using a systematic approach that allows the designs to be progressed in a series of steps as the spud date approaches.

•

Logistics are generally more of an issue on high angle wells and need to be planned thoroughly prior to and during the well.

•

Although the wellpath is generally defined by other criteria, when possible, modifications can be applied to the wellpath to optimize hole cleaning directly or indirectly. The impacts of changing the wellpath must be carefully modeled as a small change can have a significant impact on a high angle well. Wells in the range of 35º - 60º generally result in more problems with hole cleaning and tripping when poor practices are used.

•

Again, casing sizes and depths are generally defined by other criteria, but when possible, these should be optimized to aid with hole cleaning. For example, for tight clearance casing programs, having the 30º - 60º build interval cased off with smaller casing can be a significant benefit.

•

The pore pressure, wellbore instability, and fracture gradient profiles need to be well defined, as this will be a significant part of the design basis for the well. Getting either of these wrong can have a significant impact on hole cleaning, and ultimately the feasibility of the entire well.

•

Oversized hole sections may allow greater tolerance for poor hole conditions (i.e. cuttings beds, wellbore instability), but the implications for hole cleaning also need to be considered.

•

Each interval of the well should be modeled using a hole cleaning model to identify potential problems in each section of the wellbore. Care should be exercised with theoretical models as many of the key parameters involve assumptions which may not be true in practice.

•

Wellbore instability can be detrimental to hole cleaning. Low effective mud weight can cause formation collapse increasing the hole size, reducing AV’s and increasing the cuttings load. Excessive downhole mud weight can result in loss circulation and the need for lower pump rate and rpm.

•

Wellbore instability must be solved before hole cleaning can be effective. A wellbore stability study using STABOR will be beneficial in identifying the required mud weight for different well inclinations, and orientations within a field.

•

Consider the challenges of drilling through insitu fractured formations, faults, and rubble zones associated with salt.

•

Solving wellbore instability starts by having the right mud weight to control the formations being drilled.

•

Operational practices must be designed around keeping within the recommended effective downhole mud weight envelope. Page 9

Apr 2003



•

Tripping practices are also critical on a high angle well to avoid inducing wellbore instability (e.g. swabbing, pack-off when backreaming)

• •

Controlling barite sag when the mud weight envelope is narrow is important for avoiding instability. PWD should be run to aid in controlling the effective downhole mud weight within the permissible envelope.

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Apr 2003


DRILLSTRING DESIGN

RIG CAPABILITY


•

Hole cleaning must be taken into account when designing or selecting the drillstring. The optimal drillstring size is likely to change in the different hole sections of a well, and may include tapered drillstrings. When hole cleaning is the priority, the drillstring size should be as large as possible to allow the maximum flowrate to be pumped within the other system limitations (surface system, T&D, pick-up tensions, ECD management, fishability, etc).

•

Comprehensive T&D and hydraulics modeling are required to allow the optimal drillstring size to be selected. Always assume realistic parameters in modeling (benchmark offsets where possible), and perform adequate sensitivity analysis.

•

Pipe specifications will need to account for the maximum modeled pick-up tension (drilling and landing strings), and torque. Note ID and OD of connections on long drillstrings can have a significant impact on flowrates (ID) and ECD (OD). These dimensions need to be optimized within other design limitations (i.e. fishability, T&D). Recognize the implications of using a landing string in drilling the well.

•

For deep high angle wells the combined drillstring loading should be considered with high pressures, rotary speeds, and tensions.

• •

Casing wear should also be considered with high tensions and RPM.

•

The number and type of mud pumps available on the rig can often be a limitation to the hole cleaning. Detailed hydraulics modeling will be required to ensure that the pumps are capable of outputting the required flowrates. The pressure and flowrate limitations of the specific pump liners (with realistic safety factors) will need to be used in the hydraulics modeling. Consider the use of intermediate liner sizes that may provide improved flowrates in specific applications.

•

If pump redundancy is not available, clear guidelines should be in place should a pump not be available for any reason (e.g. can you drill ahead, additional volume from cement pump)

•

In general, a 5000psi standpipe pressure rating will be the minimum required for most high angle wells. The maximum pressure when modeling hydraulics should not be based on the standpipe pressure, but rather the value that the pop-off valves on the mud pumps are actually set at (with an operating margin).

•

Any additional surface limitations need to be evaluated and eliminated where possible. Common examples include limited flowrates due to shakers or flowlines, or pressure limitations due to swivel packing reliability.

•

The top drive must be capable of the maximum torques that will be seen in the well (may not be at TD). Additionally, the maximum continuous torque available at 120rpm is also important, as this rpm will be the minimum required for effective hole cleaning in 12¼" and larger hole size.

•

The maximum rig power available will need to be compared against the worst case power requirement while drilling. This is generally for backreaming at the TD of deep, large OD hole sections (e.g. pumping rotating and picking up)

•

The rig will require adequate solids control to allow the mud system to be processed at the required flowrates and ROP’s. Having a sufficient number of high quality shakers is the main priority (one per 300gpm as a rule-of- thumb).

•

For deepwater applications, the ability to boost the riser to increase AV’s should be considered. Avoid compromises to downhole flowrates to boost the riser (i.e. separate boost pumps may be required).

•

High angle wells generally place higher loads on rig equipment. Preventive maintenance plans should be reviewed in the planning stage, and consideration given to increased maintenance prior to, and during the well (e.g. pumps lines, swivel packings, saver subs).

•

The hoisting capacity of the rig will need to be carefully evaluated if high surface tensions are expected when drilling or running casing.

Consideration should be given to running bladed drillpipe to help stir up cuttings bed through long tangent and build sections. This is particularly true if backreaming is planned (i.e. reduce the risk of pack-off while backreaming).

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Apr 2003


MUD SELECTION

ECD PLANNING


•

In large diameter low angle holes, and environments with reduced drilling margins and high fracturing / lost circulation risks, WBM systems are the preferred mud systems for drilling and hole cleaning. Care should be taken to prevent high annular cuttings loading (resulting in high ECD, pack-off, aggravated BHA balling etc.) due to a combination of high ROP, insufficient flowrates, and insufficient rheology (especially low 6 & 3 rpm’s and YP). High-vis sweeps may need to be programmed to clean the hole properly.

•

Main mud selection criteria for drilling high angle holes are: hole-making ability (i.e. prevention of bitballing), wellbore stability in shales, friction coefficient and fluid loss control (i.e. prevention of differential sticking). In most cases, these criteria strongly favor the use of SBM’s (exceptions are areas with very high fracturing / lost circulation risks).

•

For hole cleaning, it is recommended to formulate the mud with appropriate low-end rheology (i.e. 6 rpm reading preferably at 1 – 1.2 x hole size), provided other system limitations (e.g. restrictions on viscosity due to ECD limitations) are met as well. Note that it is difficult to modify low-end rheology independent from high-end rheology (i.e. 600 rpm & 300 rpm reading that affect PV and YP).

•

Barite sag is an important detrimental phenomenon that must be taken into account in the selection and design of a mud system for high angle wells. Barite sag may adversely affect ECD and surge pressures, wellbore stability, pack-off and lost circulation, and well control. Minimizing barite sag tendency requires dedicated formulation of the mud formulation for sag control (using sag control agents such as organophilic clays), pro-active monitoring (using special sag screening techniques such as the VST test), and maintenance at the rig-site (especially maintaining adequate ultra low-end rheology, i.e. < 3 rpm readings).

•

For deepwater applications, mud rheology should be considered explicitly as a function of temperature and pressure. Hole cleaning and ECD modeling should be conducted using parameter input from Fann 70 (or equivalent) viscometer measurements. Mud checks at the rig site should be conducted at downhole circulating temperature, mud line temperature, and flow line temperature.

•

If narrow allowable mud weight margins dictate the control of ECD as a primary concern, then hole cleaning may become a lower priority, warranting remedial actions (e.g. controlled ROP, cleanup cycles, etc).

•

Detailed ECD modeling will be required early in the planning stages to understand the implications of the well design and equipment being used. Sensitivities to mud weight, rheology, flowrate, rpm, drillstring, and other parameters should be included. ECD’s should not just be calculated and compared to fracture gradient at TD (what PWD will see), but should show the results for the entire openhole interval, as ECD’s are not necessarily the highest on-bottom.

•

For deepwater applications, ECD’s must be modeled with variable downhole rheology that take into account the temperature / pressure profile throughout the wellbore. Fann 70 data should be used.

•

Consider ECD implications when designing the wellpath. For example ECD’s are a function of well length, and the wellpath should be designed (within other constraints) to be as short as possible. Lower inclinations may also require less mud weight and reduce ECD’s.

•

Hole sizes should be optimized to maximize the annular clearance. Drilling oversize openhole sections may yield benefits to ECD, but implications for hole cleaning need to be considered.

•

Casing strings should be designed considering the ECD implications of casing size, weight, connections and centralization. Consider running casing as a liner if ECD’s margins are tight.

•

If managing ECD’s are a higher priority than hole cleaning (generally smaller hole sizes), the mud properties will need to be optimized to meet the requirements of minimum ECD and maximum hole cleaning at the same time. Realize that lowering the mud properties to minimize ECD may compromise the hole cleaning efficiency, and cause barite sag.

•

The drillstring size and connection OD may have a significant impact on ECD’s, and should be optimized as part of the overall drillstring design.

•

Note that ECD’s are not reduced by a single design change, but rather the addition of many small incremental design changes (often requires a lot of work to make margins manageable). Examples may include drillstring and casing design, flowrate and rpm, ROP, mud properties etc. Page 12

Apr 2003


DIRECTIONAL DRILLING STRATEGIES

CASING & COMPLETION RUNNING


•

The Directional Drilling Strategy is an integral part of hole cleaning. For each hole section, the directional strategy should be planned around the key issues in that interval (i.e. directional control, hole cleaning, ECD management, etc).

•

In general, steerable motor assemblies are not ideally suited for good hole cleaning. If possible, alternatives should always be considered if hole cleaning is a priority for an interval. These may include rotary assemblies (with adjustable stabilizers), or rotary Steerable Tools (RSS). If conventional steerable assemblies are run, practices will be all the more critical to ensure the hole is clean and tripping problems are avoided.

•

The maximum flowrate and rpm specifications for all BHA components should be evaluated, and any limitations designed out if possible at the planning stage.

•

If it is known that a section will not be able to be cleaned with the given parameters, consider drilling it as a pilot hole and then opening it up to the required hole size. Alternatively, consider a dedicated cleanout run with an optimized hole cleaning BHA.

•

RSS’s should not be considered the “ultimate” hole cleaning solution. These tools are just one part of the hole cleaning system, and need to be run with appropriate practices to maintain good hole cleaning.

•

Consideration should be given to running various mechanical tools in the BHA such as jet subs or PBL subs. PBL subs can be used for increased flowrates, pumping of aggressive LCM pills, or to allow circulation in casing with bit-centers on a motor or underreamers.

•

Consideration should also be given to the use of electronic tools in the BHA to aid with (and monitor) hole cleaning effectiveness, or other indirect affects (e.g. vibrations, PWD, DWOB/DTOR).

•

Work with the geologists to maximize the target area, to reduce the sliding required if motors are used. Additionally, this may allow rotary assemblies with adjustable stabilizers to be used in the tangent sections.

•

Bits should not be selected based solely on ROP, footage, or cost/ft, but rather need to be matched to objectives of the BHA being run. The bits impact on directional performance, hydraulics, cutting size, and junk slot area are particularly important.

•

Running casing to bottom in a high angle well should not always be taken as a given. Modeling of the casing runs should always be performed to determine the casing slack-off and pick-up weights, as well as the level of exposure to poor hole conditions (i.e. if minimal weight available at TD, or tight clearances, may require a cleaner hole or alternative casing running technique).

•

As inclination and stepout increases, slack-off weights will become an issue, and various design approaches may be pursued to allow the casing to run to bottom. With deep high angle wells, pick-up weights are generally more of an issue. Picking up casing and liner strings with tight clearances can lead to excessive swabbing and wellbore instability.

•

Centralization type and quantity will be critical to reducing drag as casing and liners are run to bottom. Centralizer spacing on the shoe-track will be important to creating limber shoe-tracks to aid in running pipe through build and turn sections.

•

Reamer or asymmetric shoes should be considered for casing and liners to aid in working the pipe through tight spots or cuttings beds left in the hole. Alternatively the use of bits and mud motors on the last casing string / liner can be used to work pipe to bottom.

•

Liner hangers with the ability to circulate and rotate should be considered to facilitate running to bottom.

• •

Long casing strings should be run with a fill-up and circulate tool to facilitate working casing to bottom. ECD’s must be considered when running casing / liners, particularly with tight annular clearances, or if floating casing. Open shoes and fluid diverter systems may be required with tight annular clearance to reduce surge pressures. High weight / grade or high collapse casing may be required with floated casing.

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Apr 2003


DRILLING AND TRIPPING PRACTICES


•

The key parameters for hole cleaning while drilling are rpm, flowrate, mud properties, and ROP. The requirements for each of these needs to be clearly understood in the planning phase to ensure that all limitations are designed out where possible.

•

In the case that the hole cannot be cleaned within the limitations of parameters above, remedial hole cleaning options will need to be available. These may include cleanup cycle, sweeps, backreaming. Again these options need to be thought out and agreed to in the planning stage.

•

Appropriate tripping / backreaming practices also need to be developed and agreed to prior to drilling the well. These practices need to be centered around avoiding stuck pipe, losses (surge, pack-off), or inducing wellbore instability (swab).

•

Trip speeds need to be defined using swab / surge modeling.

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Apr 2003


“EXECUTION BOX” HIGH LEVEL GUIDELINES The following high level guidelines should be reviewed prior to the execution stage of the well, to ensure that all aspects of the hole cleaning system are considered. If further details or background are required, refer to the relevant sections in the manual.

THE SOFT ISSUES

DIRECTIONAL DRILLING PRACTICES


•

Again the commitment and alignment of all personnel is critical in the execution phase. A clear and concise hole cleaning plan should be prepared prior to the well, which is agreed to at all levels. Everyone involved needs to understand the special challenges that are required to drill a high angle well may require a paradigm shift in hole cleaning practices.

•

As with the planning phase, specific and appropriate training (e.g. hole cleaning course, DWOP, prespud, pre-tour) is required to ensure all personnel, from the Rig Superintendent to the shaker hand, are able to understand what is happening downhole, use the appropriate practices, and make the right decisions for the success of the well.

•

Quality control is critical on high angle wells to prevent tool failures in the hole. Fishing and recovering from downhole tool failures, and additional tripping, is time consuming, and often leads to more significant problems with the hole.

•

Contingency plans should be proactively developed for all operations in the initial planning phase (e.g. risk matrix). Reacting to problems often leads to solutions that are not optimal, and result in further compromises and problems.

•

Careful consideration must be given to every BHA component and how it will impact hole cleaning (flowrate and rpm limitations, flow-by area, dimensions, etc). In particular, the OD of all BHA components must be documented to identify areas of minimal clearance (i.e. potential for packing off and tripping problems).

•

A single BHA may have to achieve multiple objectives (e.g. build followed by tangent), which may compromise drilling efficiency, and hole cleaning (e.g. motor bend and rpm limit). Consider a “pit-stop” strategy with multiple BHA’s designed to efficiently drill and clean the different sections of the well (but consider the impact on wellbore stablility). Alternatively, RSS’s should be considered to provide a single trip option.

•

Directional drillers should avoid “chasing the line” which will result in excessive sliding and tortuosity. Similarly, avoid excessive directional work trying to hit the center of the target (i.e. hitting the target involves landing anywhere in the target box).

•

If steerable motors are run, they should be set up to maximize the section drilled in rotary mode. For example, in a build section, the steerable assembly should be set up to build in rotary mode. Additionally, consideration should be given to running adjustable stabilizers behind the motor to provide some added flexibility to rotary build /drop rates (not applicable when drilling oversize hole).

•

In high inclination wells it is likely that much of the drillpipe will be run in compression. Avoid running excessive HWDP and drillcollars for weight in the high angle section of the well, as this will negatively impact both T&D and flowrates. Drillpipe run in compression should be reposition periodically and inspected frequently for fatigue.

•

Roller cone bits require HSI for drilling efficiency, but PDC bits can utilize larger nozzles without compromising performance. This is often important for gaining extra flowrate in pressure limited situations. The junk slot area (JSA) should be maximized for easier tripping through cuttings beds (a natural feature of bi-center bits and oversize hole).

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Apr 2003


MECHANICAL TOOLS

DRILLING PARAMETERS AND PRACTICES


•

PBL subs with multiple open and close cycles can be used to increase flowrates when needed for cleaning up the wellbore (e.g. above liner tops). Additionally, they may be used to pump aggressive LCM pills which cannot pass through downhole tools, allow underreamers to collapse when circulating and rotating in casing, and when backreaming motors with bi-center bits in casing.

•

Bladed drillpipe can be used to stir up cuttings beds in long tangent sections and increase the rate at which the hole is cleaned up. It’s use can also reduce the risk of pack-off while backreaming (i.e. multiple dunes with smaller size).

•

Underreamers and bi-center bits may make hole cleaning more difficult (i.e. larger OD hole), but may allow more tolerance for cuttings in the hole when tripping (i.e. large JSA)

•

Nozzled motors or jet subs should be considered for by-passing flow if a flowrate restriction is seen in the BHA. This may require tri-cone bits to be run as the motors torque output will be impacted by nozzling.

•

In a high angle section (>30º), the key drilling parameters for hole cleaning are rpm, flowrate (AV), and ROP. Along with rheology and cutting size, these parameters need to be optimized to clean the entire wellbore.

•

In 12¼" hole and above, 120 rpm is the minimum rpm required for effective hole cleaning. Smaller hole sizes will require less rpm in the range of 60-120rpm. PWD and vibrations need to be monitored to find the optimum rpm for hole cleaning, vibrations, and ECD management.

•

Drilling should cease if loss of a pump or power results in key drilling parameters (e.g. rpm, flowrate) falling below agreed threshold values.

•

The system should be designed to maximize the flowrate at all times and in all sections, within other limitations (e.g. ECD, standpipe pressure, mud pumps, BHA components, etc).

•

For floater applications, when excess pumping capacity exists, the riser should be boosted to increase AV’s and unload cuttings that may be accumulating.

•

ROP is used as the “control” for hole cleaning. The plan is to maximize the ROP while staying within “the box”. Hole Condition monitoring (HCM) as discussed below, is the means for maximizing the ROP.

•

Initial ROP upon drillout should be controlled at a conservative level while steady state conditions are established (e.g. rheology, T&D, cuttings, ECD, etc).

•

Standard connection practices will need to be developed. The aim of these practices should be to minimize the potential for getting stuck on a connection, aid with hole cleaning, collect consistent T&D data, and minimize the pressure loading on the hole.

•

In the case that the hole cannot be cleaned within the limitations of parameters above, remedial hole cleaning options as discussed below will need to be pursued.

•

Prior to, and while drilling the well, hole cleaning models can be used to give an idea of the parameters that are required for effective hole cleaning at a given ROP. Models should always be calibrated with actual data (generally indirect indicators – T&D, cutting returns).

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Apr 2003


MUD PROPERTIES

•

The mud weight required for both wellbore stability (as determined by STABOR) and well control, should be maintained prior to drilling into problem formations. Field experience shows that it is usually possible to maintain a mud weight of 0.2 – 0.3 ppg below the STABOR mud weight (e.g. to accommodate high ECD’s in small drilling margin environments), without suffering excessive hole problems. However, maintaining even lower mud weights (e.g. ≥ 0.5 ppg below STABOR recommended mud weight) will inevitably lead to wellbore enlargement (with cavings and reduced annular velocities complicating hole cleaning), pack-off problems (with associated fracturing & lost circulation risks), hole collapse, and stuck pipe.

•

The effect of mud compressibility (more pronounced for SBMs than for WBMs) always needs to be taken into account when selecting and maintaining an optimum downhole mud weight.

• •

The use of a pressurized mud balance is recommended to accurately measure surface mud weights.

•

Use actual cuttings size (i.e. monitor shakers, consult with bit experts) to update hole cleaning predictions.

•

It is recommended to maintain the mud with appropriate low-end rheology (i.e. 6 rpm reading preferably at 1 – 1.2 x hole size), provided other system limitations (e.g. restrictions on viscosity due to ECD) are met as well. Note that it is difficult to modify low-end rheology independent from high-end rheology (i.e. 600 rpm & 300 rpm reading that affect PV and YP).

•

Thixotropy (i.e. gellation) allows for cuttings to remain suspended in the mud while static. Gel strengths should be non-progressive (i.e. little difference between 10 min and 30 min gels) but adequate to suspend cuttings (e.g. 10 sec gel: 10 – 18 lbs/100ft2; 10 min & 30 min gels: 16 – 28 lbs/100ft2).

•

Good solids control, preventing cuttings / solids breaking down to colloidal size in the mud, is crucial to minimize PV (thereby minimizing pump pressure / maximizing flow rates), keep YP in check (thereby controlling ECD’s), and prevent gels from becoming progressive (thereby preventing excessive swab & surge pressures). LGS should preferably be < 5%, API SP (measuring solids control efficiency) should preferably be >90% (note that high dilution rates to maintain optimum properties will inflate drilling fluid cost).

•

Running SBMs with higher synthetic-to-water ratio (SWR) will help to thin the fluid, minimizing pump pressures and maximizing flow rates for hole cleaning. Note that higher SWR’s will increase the cost of the mud system.

•

Maintaining good shale inhibition and chemical wellbore stabilization is an important requirement for drilling and cleaning high-deviation wellbores, strongly favoring the use of SBMs. Poor inhibition and chemical stability will complicate hole cleaning by causing wellbore enlargement, higher annular loading, and cuttings beds that are more difficult to remove (due to mutual sticking of cuttings). Note that good shale inhibition may complicate hole cleaning in large diameter vertical hole, as all cuttings are kept intact (i.e. no dispersion occurs) and must be removed from the hole.

•

Sweeps in high angle holes should be avoided, as they tend to be ineffective, make controlling mud properties more difficult, and may increase the chance of pack-offs.

•

Barite sag is aggravated by low shear operations (e.g. slow pump rates and pipe rotation, tripping, logging, small wellbore influx, slow fracture breathing etc.) which should be minimized if possible. Mud treatment recommendations (e.g. maintenance requirements on sag control agents such as organophilic clays in the right ratio’s) should be strictly adhered to. Pro-active sag monitoring using representative tests (e.g. VST) should be practiced. PWD information on static mud weight while tripping yields valuable information on sag tendency, and should be used to optimize pump staging and mud circulation

Mud rheology should be optimized in accordance with hole cleaning simulations (e.g. EzClean / TDClean / Virtual Hydraulics etc.). Simulations need to be carried out using mud properties as a function of temperature and pressure, as determined by Fann 70 (or equivalent) viscometer. It is recommended to obtain Fann 70 measurements of the mud sent out from the plant, and occasionally test mud samples from the rig.

during trips.


Page 17

Apr 2003


ECD MANAGEMENT

HOLE CONDITION MONITORING (HCM)


•

If the drilling envelope (determined by pore pressure, mud weight required for wellbore stability, and fracture gradient) is tight, all measures must be taken to control the effective downhole mud weight. In practice this may compromise hole cleaning (e.g. lower flowrates). However, trying to clean the hole once losses or wellbore instability have started becomes far more difficult.

•

For high angle sections where ECD margins are tight, the mud system will need to be designed with minimal high-end rheology. Additionally, gel strengths (surge) should be as flat as possible, and sweeps (pressure spikes) should be avoided.

•

PWD should be run and used to understand the impact of various parameter while drilling (flowrate, rpm, pipe movement, etc), and also monitor practices when off-bottom (time based logs).

•

Hydraulics models should be calibrated with actual data from the PWD, and used to predict ECD’s throughout the wellbore (might be higher ECD’s further up the hole).

•

Specific procedures need to be followed to minimize ECD cycling on the formations for all operations – drilling, connections, reaming, tripping, breaking circulation, running casing, etc

•

Prior to drilling into a known loss / depleted / weak zone, consider performing a cleanup cycle to minimize the cuttings and ECD loading in the hole. Note that the hole will become more difficult to cleanup once losses begin (e.g. reduced flowrate and rpm).

•

Time based (memory) PWD logs should be reviewed at the end of each run to determine the effectiveness of practices, and analyze problems. RTOC can be a resource for this review.

•

For deepwater applications, cuttings loading in the riser may impact ECD’s. Additionally, thicker mud in the riser (due to low temperatures) may also result in increased ECD’s. Boosting of the riser can be used for controlling cuttings loading and mud viscosity in the riser.

•

Hole Condition Monitoring (HCM) is the real-time collection and interpretation of relevant well data, with the aim of maximizing ROP within the hole cleaning system (“drilling in the box”).

•

It is important to recognize all the methods used to gather data in the HCM process are indirect measurements and require interpretation. Each source of data should not be used in isolation.

•

Real-time monitoring of T&D data verses predicted data is one of the primary means of monitoring hole cleaning effectiveness while drilling. This method is also used as the primary means of monitoring tripping and casing running operations in high angle wells.

•

The cuttings returning across the shakers must be checked at regular intervals. Some qualitative or quantitative means of measuring the cuttings volume will aid in providing a relative measure of how well the hole is being cleaned (e.g. cutting weighing machine, cutting height in auger, timed bucket). The shape and character of the cuttings are also an indicator of what is happening downhole.

•

Drilling parameters and mud properties need to be tracked to provide a relative measure of changes in the hole cleaning system.

•

PWD data (incorporated with drilling parameters) should also be used as another data set to monitor the hole condition. The PWD data should not be monitored in isolation as it may not provide a true indication of hole cleaning effectiveness in high angle tangent sections (i.e. may not show cuttings beds lying on low side of the hole).

•

Some FEWD tools provide a pseudo-caliper (e.g. resistivity / density / neutron), which should be monitored to provide an indication of the hole gauge when drilling and tripping.

Page 18

Apr 2003


REMEDIAL HOLE CLEANING PRACTICES

TRIPPING PRACTICES

RTOC


•

It has been repeatedly demonstrated that it is better to stay on-bottom at an optimized ROP (“drilling in the box”), than it is to drill at ROP’s outside the ability to clean the hole, and then use remedial actions to clean up the hole. It is easier, safer, and more efficient to maintain a clean hole than to clean up a dirty one.

•

If indications are seen that hole cleaning is starting to become a problem (i.e. T&D deviates, ECD increasing, tight hole), the first action should be to ensure that all drilling parameters are optimized for hole cleaning (e.g. increase rpm, flowrate).

•

If cuttings over the shakers, or some other data, indicate a wellbore stability problem, the mud weight should be increased (within the allowable mud weight envelope).

•

If the drilling parameters and mud weight are all optimized, and hole cleaning problems still exists, control drill at a reduced ROP in an attempt to find the optimal ROP to remain on-bottom and “drilling in the box”.

•

If none of the above steps are effective, consider stopping to perform a cleanup cycle. The cleanup cycle should be performed at the maximum allowable flowrate and rpm, until the shakers are clean (e.g. 2-4 x BU). Monitor PWD, cuttings load, and measure the T&D before and after the cleanup cycle.

•

Wiper trips (check trip / short trip) are of limited value in hole cleaning, but may be used to check the condition of the hole.

•

Sweeps in high angle hole should be avoided, as they tend to be ineffective and make controlling mud properties more difficult. Hi-vis sweeps are recommended for cleaning large diameter low angle hole if cuttings removal proves insufficient due to low pump rates / annular velocities and/or insufficient mud rheology. In case riser boost is not available (e.g. on TLP’s and platform rigs), a sweep may also be useful at the tail end of a clean-up cycle to help lift any remaining cuttings to the surface.

•

Backreaming is a high risk and time consuming operation. However, it may be necessary in specific applications (e.g. floating casing, tight annular clearances, running casing / liner with open floats). If backreaming is performed, it should always be preceded by a cleanup cycle, and recommended backreaming procedures should be strictly followed. It is recommended that a tailgate meeting is held prior to backreaming operations due to the increased risk of pack-off and stuck pipe.

•

Tripping out of the hole is where the “rubber meets the road” on high angle wells, as this is the operation where most stuck pipe and borehole problems occur. Effective practices are critical to tripping success.

• •

Regardless of which method is used to trip, the first step should always be to perform a cleanup cycle.

•

Cased hole should not be considered a “safe haven” on high angle wells, as the risks of getting stuck in cuttings beds still exists.

•

Trip speeds need to be optimized using swab / surge modeling. RTOC can be a resource for optimizing tripping speeds.

•

Refer to the manual and sample detailed guidelines for more details of tripping practices.

•

SEPCo’s Real Time Operations Center (RTOC) is designed to improve performance and reduce drilling trouble time/cost for GOM wells, by providing improved operational planning and monitoring, and capture / sharing of learning’s.

•

The RTOC is staffed with skilled Contract and Shell staff working together to monitor planned vs actual operations for all wells drilled realtime. Their objective is to identify deviations and anomalies from planned and then notify offshore / onshore rig team to permit “real time” changes (optimization) in the program and operating practices to be made (e.g. detrimental operating practices, ECD management, hole cleaning, BHI, etc).

As for the remedial hole cleaning practices, backreaming is not recommended unless required in specific applications. Note that backreaming may prevent swab related instability, but if done incorrectly can increase the potential for fractures and loss circulation.

Page 19

Apr 2003


DETAILED GUIDELINE TEMPLATES Following are detailed guidelines for: •

Cleanup Cycles

•

Hole Cleaning While Drilling

•

Connection Practices

•

Standard Tripping Practices

•

Backreaming Practices.

These sample guidelines may be used as templates which should be modified for a specific application. Note that these guidelines will most likely be different for every well and every hole section, as equipment, well designs, and section priorities change. Attached as an example at the end of this section is a single page “Hole Cleaning / Tripping Practices Summary” from the 12¼" interval of an actual well.

CLEANUP CYCLE The following procedure should be used to cleanup the hole prior to tripping or for remedial purposes when drilling. Circulate 2.5 - 3 x BU and until shakers are clean -

Measure the quantity of cuttings coming over the shakers every 15 minutes.

–

Maintain rpm and flowrate at their maximum level.

–

Pull up slowly to avoid washing out the hole, at a rate of one stand every ±60 minutes

–

Monitor relative changes in T&D and PWD compared to both modeled and last observed prior to cleanup cycle. Expect improvement as the hole cleans up.

–

Monitor vibrations to avoid excessive levels.

–

Generally 2 distinct waves of cuttings over the shakers will occur during the cleanup cycle (second generally comes at 1-1.5 x BU after the first peak drops off).


Page 20

Apr 2003


HOLE CLEANING WHILE DRILLING Hole cleaning can be described by the theory of "Drilling in The Box". This is a technique whereby drilling performance (ROP) is optimized to match the hole cleaning ability of the entire drilling system. For successful implementation of this concept it is important that all aspects of the system are considered, as varying one parameter will affect the others. Parameters:

• •

Flowrate –

•

Mud – Establish the optimum mud properties (weight, rheology. gels), and the downhole effective mud weight envelope.

•

ROP – Maximize based on T&D monitoring (divergence of PU and SO weights from theoretical), and PWD. Initial ROP upon drillout should be controlled at a conservative level while steady state conditions are established (e.g. rheology, T&D, cuttings, ECD, etc)

Establish the design and minimum flowrate, and what defines each.

RPM – Establish the minimum and maximum rpm based on various limitations (surface limitations, vibrations, ECD, downhole tools, etc).

Hole Condition Monitoring and Reporting:

•

T&D - ensure pick-up weight, slack-off weight, rotating off-bottom weight, and torque are recorded each stand in a consistent manner (refer to connection practices). If the hole is loading up with cuttings, the pick-up and slack-off weight will diverge from the theoretical trends. Should be interpreted real-time on the rig floor and RTOC.

•

Cuttings Returns – monitor quantity of cutting over the shakers every 30 minutes. Establish a background cuttings level and compare on a regular basis (e.g. % cuttings over shakers, lb/min, etc). Also report size and shape of cuttings.

• •

Parameters – ensure the key parameters above are monitored and recorded. PWD – the PWD should be monitored and any indications of poor hole cleaning noted. Remedial action will need to be based on the PWD as well as other indicators (T&D, cuttings).

Remedial Hole Cleaning Practices: 1.

Change parameters if not optimum for hole cleaning (as detailed above).

2.

Slow and control ROP until hole cleaning improves (e.g. slack-off and pick-up weights return to theoretical curves, PWD shows an improvement in loading, etc).

3.

If the hole still does not appear to be cleaning up, stop drilling and perform a cleanup cycle.

4.

If hole cleaning continues to be a problem, other options may include sweeps, wiper trips or backreaming. Alternatively, hole cleaning may not be the root problem (i.e. borehole instability, differential sticking, formation change, etc).


Page 21

Apr 2003


CONNECTION PRACTICES The aim of these practices are to minimize the potential for getting stuck on a connection, aid with hole cleaning, collect consistent T&D data, and minimize the pressure loading on the hole. 1.

Drill down stand at the required parameters for efficient hole cleaning.

2.

Backream the stand as required.

1.

–

Note backreaming is performed solely to clear cuttings from around and above the BHA so they do not cause problems while the pumps are off and pipe is stationary.

–

Factors to consider are the flowrate, rpm, hole size, hole angle, ROP, and mode of drilling prior to the connection.

–

Depending on hole conditions the stand may be reamed 1 to 2 times. If the ROP is controlled in the last single (with rotary drilling), backreaming the stand may not be required at all.

–

Down-reaming should be controlled or avoided as this can cause excessive surge.

With one single off-bottom, and at consistent pump rate;

–

Record rotating off-bottom torque and string weight

–

Stop the rotary and pick up at 30 ft/min, record pick-up weight

–

Slack off at 30 ft/min, record slack-off weight

1.

Shut down pumps and bleed off pressure

2.

Slack-off and set slips.

3.

Break out top drive.

4. 5.

Pick up new stand, and makeup connections.

6.

Drill ahead as instructed or wait on MWD survey (if required).

Start pumps slowly (stage up the pumps over several minutes), and pick up out of slips. If ECD’s are approaching the fracture gradient, start rotating slowly prior to starting the pumps (break the gels and reduce ECD spikes). Regardless of which is done first, change one parameter at a time awaiting its response.


Page 22

Apr 2003


STANDARD TRIPPING PRACTICES These practices should be used for the majority of trips out of the hole. They may be modified slightly based on whether the trip is for a BHA, logging or casing run. 1.

Perform cleanup cycle.

2.

When shakers are clean, pull 5-10 stands wet to check hole condition.

3.

Pump a slug and POOH on elevators

1.

–

Record pick-up weights on every stand and plot on a theoretical T&D chart in real-time (preferably it should be on the rig floor).

–

Use of analog weight indicators is recommended to better identify fluctuations.

–

Note that if tight hole is likely based on offsets or analog wells, consider pulling wet all the way to the shoe before pumping a slug and POOH on elevators (i.e. limits slugs in the hole).

If a tight spot is encountered (>30kips overpull) assume the tight spot is cuttings. RIH 2-3 stands until the BHA is clear of the obstruction, and circulate for 30 minutes. -

2.

Pull up wet through the tight spot without rotation. If the tight spot has disappeared, then it was caused by a cuttings bed that has now been moved up the hole. Return to step 1 and circulate the cuttings out of the hole. -

6.

The goal here is simply to confirm if it is a cuttings bed, not to circulate BU.

If the tight spot remains in the same place, then it is likely another mechanical process (i.e key seating, ledge). If this is the case, ream through the section and try to eliminate the tight spot. Pull up through the tight spot again without rotation to see if it has been eliminated after reaming. If obstruction has been removed, go to step 2.

Backreaming should be used as a last resort if a cuttings bed cannot be circulated out. If backreaming is started, it should be continued up to 30o inclination. Refer to detailed backreaming procedures.

The primary rules for tripping in high angle wells are:

•

Always assume that any tight hole or over-pull is due to cuttings (i.e. hole cleaning related). However, this assumption needs to be tested to ensure wellbore stability (or another issue) is not the problem.

•

The actual pick-up weights should be plotted against the theoretical weights, to ensure that sections of tight hole and overpull are quickly and clearly identified.

•

Do not assume that cased hole is a safe haven for tripping.

It is not unheard of for stuck pipe to

occur inside casing, either just inside the shoe or many thousands of feet inside casing. •

Note there may be certain applications in which backreaming out of the hole may be required on narrow margin wells in order to prevent wellbore instability.

•

Memory PWD data should be analyzed after a trip to identify problems and modify practices for future trips.

•

Tripping in practices should also be developed to minimize the surge exerted on the formation, and deal with potential barite sag.


Page 23

Apr 2003


BACKREAMING PRACTICES After determining that backreaming is necessary, the following guidelines should be followed closely. Note that the main risk when backreaming is packing off, and the practices should be designed around monitoring and avoiding packing off.

1.

Perform a full cleanup cycle as per the previous guidelines. Do not take a short cut with this step!

2.

Commence backreaming at a maximum of 4-5 stands per hour.

1.

–

If an RSS is included in the BHA, and where applicable, ensure the pads are set in the neutral position.

–

Maintain maximum flowrate and rpm.

–

Monitor PWD and vibrations.

–

Monitor pump pressures, return flow, and torque for signs of packing off and tight hole.

–

Be patient!

Continue to backream to ±30 o inclination (maybe inside casing) before circulating a further 1.5 - 2 x BU and POOH on elevators -

Consider circulating the hole clean prior to backreaming into the casing shoe.

The primary rules for backreaming in high angle wells are:

•

Always perform a cleanup cycle prior to starting backreaming, and after backreaming prior to POOH. Also, consider intermediate clean up sessions while backreaming out of the hole.

•

Backreaming should always be performed at maximum possible flowrate and RPM (within other system limitations).

•

Take special care when backreaming into a casing shoe as the larger diameter rathole below the shoe (or when drilling oversize hole) may be an area where cuttings will accumulate.

Consider extra

circulation with rotation before backreaming into the shoe. •

Sweeps should be avoided while backreaming as they increase the risk of packing off (i.e. can pickup cutting dunes).


Page 24

Apr 2003

12¼” HOLE HOLE CLEANING (While Drilling)

SECTION PRIORITIES:

HOLE CLEANING / TRIPPING PRACTICES SUMMARY CONNECTION PROCEDURE

INTERMEDIATE TRIP

Tangent – Hole Cleaning Build – Hole Cleaning, Directional

FINAL TRIP PRIOR TO CASING

Hole cleaning while drilling will be a function of matching the drilling performance (ROP) to the capability of the “hole cleaning system” (Drilling in the Box). Following are recommendations of the key hole cleaning parameters, monitoring tools, and possible remedial actions if hole cleaning becomes a problem. KEY HOLE CLEANING PARAMETERS:

• • • •

Flowrate – Maximize at all times. With 5.5” liners, should be able to pump >1100gpm to TD (SPP limited at TD).

• • • •

1.

Drill down stand

2.

If the ROP has exceeded 200’/hr, or rpm less than

3.

RPM - Target 150–180rpm (optimize for vibrations) Mud - maintain 6 rpm between 12-16, flat gels, PV and LGS as low as possible (run screens as fine as possible, centrifuge as necessary), minimize mud weight. ROP – Do not exceed 75’/hr for first 1000’, and then optimize based on T&D readings and other limitations.

HOLE CLEANING

•

To minimize the potential for getting stuck on a connection, aid with hole cleaning, collect consistent T&D data, and minimize pressure loading on the formations, the procedure below should be followed at each connection:

MONITORING:

T&D - ensure PU, SO, ROB weight and torque data recorded each stand in a consistent manner Should be interpreted real-time on the rig floor. Cuttings – monitor on a regular basis (volume – lb/min, size and shape). Shakers should stay full while drilling. Parameters – monitor and record key parameters listed above. Look for changes in trends. PWD – The PWD will be of limited value in this interval for hole cleaning and ECD management.

For all intermediate trips out of the hole to replace a Bit / BHA, the following tripping procedure should be followed: 1.

–

120, ream the stand twice, otherwise only ream the stand once. With one single off bottom, and at consistent pump rate; – Record rotating off bottom torque (k ft-lbs) and string weight (k lbs),

–

– –

–

1. 2. 3. 4.

5. 6. 7.

8.

Stop rotary and pick up at 10 m/min, record up weight (k lbs). – Slack off at 10 m/min, record down weight (k lbs). Run back to bottom and set slips. Shut down pumps. Break out top drive, dope pin, unlatch and clean elevators. Switch Power Frame to make up. Pick up new stand, and makeup connections.

1. 2.

1.

Ramp up pumps in 20 stoke intervals over 2-3 minutes. Monitor PWD when flow adequate to turn tool on. Once at maximum flowrate, pick up off of slips. Start rotating once returns established (if survey not required). Drill ahead as instructed, or wait on MWD survey (if required).

1.

EzClean – Model theoretical hole cleaning performance and attempt to calibrate the model.

REMEDIAL 1.

3. 4.

OPTIONS: Change key drilling parameters if not optimum.

HOLE CLEANING

2.

Control ROP until actual T&D measurements return to theoretical curves. Stop drilling, pull off bottom and perform a cleanup cycle (as detailed in tripping column). Consider other alternatives – sweeps (weighted or LCM), backreaming, or a wiper trip.

6.

High Velocity Fluid

Perform a cleanup cycle by pumping 3 – 6 x BU or until the shakers are clean. Maintain rpm and flowrate at the level used when drilling the hole, or greater. Measure the lb/min quantity of cuttings coming over the shakers every 15 min. Pump further 1-2 x BU after the first peek of cuttings drops off. Rack back a stand every 45-60.

The 9⅝” casing will be run with partial flotation and will be critical to the success of the well. For this reason, it is planned to backream the entire openhole interval to maximize the chance of running the casing to bottom. The following guidelines will apply:

1. 2.

Perform cleanup cycle (as per the intermediate trip guidelines). Commence backreaming at a maximum of 5 stands per hour. – Set AutoTrak full gauge (zero force)

–

–

After racking back each stand, start the pumps and rotary slowly, then raise to maximum rpm and flowrate and allow the pressure and torque to stabilize prior to commencing backreaming the stand Monitor PWD and vibrations

–

Monitor pump pressures, return

–

Monitor T&D, PWD and vibrations. When the shakers are clean, pull 5-10 stands wet to check hole condition. Pump a slug and POOH on elevators – Set AutoTrak undergauge (zero force) – Record PU weights on every stand and interpret chart on the drill floor If a tight spot is encountered (> 30 k lbs overpull), assume the tight spot is cuttings. RIH 2-3 stands until the BHA is clear of the obstruction, and circulate and rotate for 30 min. – The goal is simply to confirm if the problem is cuttings, not to circulate BU

Pull up through the tight spot (on elevators with no rotation or circulation). If the tight spot has disappeared, then it was caused by a cuttings bed or dune that has now been moved up the hole. Return to step 1 and circulate the cuttings out of the hole. - If the tight spot remains in the same place, then it is likely another mechanical process (i.e key seating, ledge). Attempt to ream through the obstruction, and go to step 3 once removed. Backreaming should be used as a last resort if a cuttings bed cannot be circulated out. If backreaming is started, it should be continued until ±700m MD (30o inclination).

flow and torque for signs of packing off and tight hole.

1.

Continue to backream to ±700m MD (30o inclination) before circulating ± 2.5 x BU and POOH on elevators – Consider circulating the hole clean at intermediate points.

–

Consider circulating the hole clean prior to backreaming into the 13⅝” casing shoe.

Low Velocity Fluid Standard Backreaming cleanup will completely will leave “safe” remove the cuttings cuttings bed bed and oncreate a dunebottom above the BHA

Cuttings on the low side will not be disturbed by fluid unless stirred up by pipe rotation

g nin ea

o le lH dia e m Re Mechanical Tools

le Ho

Tripping Practices

Mud Properties Drilling Parameters and Practices

ECD Management

s ice

n Co

i dit

on

o nit Mo

g rin

Soft Issues

Cl

t ac Pr

RTOC

c re Di

ng illi Dr l na tio

t ac pr

s ice

Cuttings transport is like a conveyor belt up the high-side of the hole


THE HOLE CLEANING CHECKLISTS The checklists below are based on the quick-guide and can be used as a prompt for personnel involved in both the planning and execution phases of the well. They are also used to link the sections from the quick guide to the relevant sections in the manual.

PLANNING CHECKLIST: SOFT ISSUES:

RIG CAPABILITY:

□

Training for engineers /decision

□

Adequate planning time / resources

□

Operational involvement in planning

□

Systematic planning steps

□

Logistics

makers

(4.1.3, 4.2.1)

(4.1.2) (4.1.2) (4.1.2)

(4.2.2)

DIRECTIONAL DRILLING:

□

Mud pumps / hydraulics modeling

□

SPP rating / pop-off setting

□

Check surface flowrate limitations

□

Top drive torque / rpm output

(7.2, 4.3.4.1) (4.3.4.1) (7.2) (7.3)

□

Power requirements

WELL DESIGN:

□

Adequate Solids control

□

□

Riser boost for deepwater

Wellpath impact on hole cleaning (4.3.1)

□

Casing size / depth

□

PP / FG / BHI Profiles

□

Oversize hole implications

□

Hole cleaning modeling for each interval

(4.3.2) (4.3.3)

□

(4.3.4.4)

STABOR study performed (4.3.3)

□

Hoisting capacity

(4.3.3) Operational practices

□

Tripping practices

□

Barite sag

□

PWD

(4.3.3,

6.1.2, 6.3.4) (10.4)

(5.2.7)

(6.3.1)

DRILLSTRING DESIGN:

□

Optimal Drillstring design

(7.2) (7.3)

□

Mud Type

□

Low End Rheology

□

Barite Sag

□

Downhole rheology

□

T&D and Hydraulics modeling

(6.2.5,

(5.1) (5.2.2)

(5.2.7)

(8.1)

□

Equipment limitations

(8.1.1,

□

Mechanical tools

(8.2)

□

Electronic tools

(10.2.5)

□

Target size

□

Bit design

8.2.1, 8.2.3)

(8.3) (8.1.4)

CASING & COMPLETION RUNNING:

□

Casing runs modeled

(9.1)

□

Running alternatives

(9.1, 9.2)

□

Centralization

□

Shoe track centralization

□

Reamer or asymmetric shoes

□

Liner hangers

□

FAC tool

□

Running ECD’s

(9.2) (9.2)

(9.2) (9.2)

(9.2) (6.2.3, 9.2)

(5.2.2, 4.3.4.1,

4.3.4.2)

DRILLING & TRIPPING PRACTICES:

ECD PLANNING:

□

ECD modeling

□

ECD and wellpath

□

Hole sizes

□

Casing sizes and specifications

□

Mud Properties

□

Drillstring design

(4.3.4.2) (4.3.1, 6.2.1)

□

Planned drilling parameters

(10.1)

□

Planned remedial practices

(10.3)

□

Planned tripping practices

(10.4)

(6.2.2)

(6.2.3) (6.2.4) (6.2.5, 7.1)

7 . 1)


(6.3.3,

MUD SELECTION:

Mud weight window defined

□

(7.2)

(4.3.2)

WELLBORE STABILITY:

□

PM of rig equipment

Key issues considered

(7.4)

7.2)

□

□

Page 28

“Good hole cleaning performance doesn’t just happen … it must be engineered into the design”

Apr 2003

PROPRIETARY Shell Exploration and Production Company (4.3.4) □

Checked combined loading

□

Checked casing wear

□

Bladed drillpipe


(8.2.4)

Page 29

Apr 2003


EXECUTION CHECKLIST: SOFT ISSUES:

MUD PROPERTIES:

□

Training for rig site

□

Quality Control

□

Contingency planning

(4.1.3, 4.2.1)

(4.2.3) (4.2.4)

DIRECTIONAL DRILLING PRACTICES:

□

BHA equip specifications

□

Chasing the curve

(8.3.1, 8.3.2)

□

Hitting the target

(8.3.1, 8.3.2)

□

Maximize rotary

□

Minimal HWDP / DC

□

Bit hydraulics

(8.1,

8 .2 )

(8.1.2, 8.2.3) (8.2.1)

(4.3.4.1, 8.1.4)

MECHNAICAL TOOLS:

□

PBL subs

□

Bladed drillpipe

□

(8.2.5)

Underreamers

(8.2.5)

□

Bi-center bits

□

Motors nozzled

□

Jet subs

DRILLING PARAMETERS

(8.2.5)

(8.2.5) (8.2.5)

(8.2.5)

AND

REMEDIAL HOLE CLEANING PRACTICES:

□

Correct mud weight

(4.3.3, 5.2.1)

□

Hole Condition Monitoring

□

Rheology optimized

(3.6.3, 4.3.4,

□

Optimal Drilling Parameters

□

Gel strengths

(5.2.3)

□

Wellbore instability

□

Solids control

(4.3.4.1, 5.2.5, 7.5)

□

Control drill

□

Synthetic to water ratio

□

Cleanup cycles

□

Chemical Inhibition

□

Wiper trips

□

Impact of sweeps

□

Sweeps

□

Barite sag

□

Backreaming

5.2.2)

(5.2.3)

(4.3.3, 5.2.6) (5.2, 10.3.3)

(4.3.3, 5.2.6)

ECD MANAGEMENT:

□

RPM, flowrate, ROP

□

120rpm

□

Loss of pump

□

Max Flowrate

□

Riser Boost

□

ROP optimization

□


□

Remedial Hole Cleaning Options

□

Calibrate Hole Cleaning models

(10.1)

(3.6.1, 10.1.1) (4.3.4.1, 7.2) (3.6.2, 4.3.4.1, 7.2) (6.3.3, 7.2) (10.1.3, 10.2)

(10.1) (4.3.3)

(10.3) (10.3.1) (10.3.2)

(10.3.3) (10.3.4, 10.4.2)

TRIPPING PRACTICES:

□

Effective downhole mud weight

□

Mud properties

□

PWD data

□

ECD modeling

□

Specific practices

□

Cleanup cycle

□

ECD in riser

(4.3.4.2, 4.3.3, 6.2.4, 6.3.1) (5.2, 6.2.4,

10.2.4) (6.3.1) (4.3.4.2) (6.3.4)

(4.3.4.2, 6.3.3, 7.2)

□

Collection of relevant data

□

T&D Data

□

Cutting returns

□

Drilling Parameters

□

Mud Properties

□

Downhole tools

□

Tripping plan

(10.4)

□

Cleanup cycle

(10.3.1)

□

Backreaming practices

□

Cased hole not safe haven

□

Swab / surge modeling

(10.4.2.3)

(10.4.2.3) (6.3.4)

RTOC:

(10.3.1)

HOLE CONDITION MONITORING:

PRACTICES:

(10.2)

(10.2)

□

Planned vs actual operations

□

Identify deviations from plan

□

Optimize performance

□

Capture leanings

□

Share learnings

(10.2.1) (7.5.1, 10.2.2) (10.1, 10.2.3)

(5.2, 6.2.4,

10.2.4)


(10.2.5)

(10.1.4)

(10.3) (4.3.4.4)


Page 30

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Page 31

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SHELL EXPLORATION AND PRODUCTION COMPANY

HOLE CLEANING BEST PRACTICES MANUAL

Revision 0

April 2003


Table of Contents 1

INTRODUCTION......................................................................................................................................................................5

1.1 PURPOSE................................................................................................................................................................................5 1.2 SCOPE...................................................................................................................................................................................5 1.3 CHANGE PROCEDURES..............................................................................................................................................................6 Cuttings Bed Model

Hole Cleaning Best Practices Manual Rev 0

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1

INTRODUCTION

Hole cleaning is a critical and central design issue for any wellbore drilled above ±30º. If you get hole cleaning “right”, there is a good chance of getting the whole well “right”. However, getting it “wrong” may significantly impact the overall well cost both directly and indirectly (e.g. stuck pipe, losses, excessive torque and drag, poor time performance, etc). As wells become more challenging, and the boundaries are pushed further, the hole cleaning challenges will also continue to grow. However, even short, simple, low angle directional wells are subject to hole cleaning difficulties if attempted with a “vertical hole mentality”. Successful hole cleaning on directional and high angle wells requires a shift away from the “vertical hole mentality”. Several things are required for this to happen: •

A clear understanding of the theory of what is happening downhole, and how things change as the wellbore inclination increases

•

Planning with hole cleaning as the central focus

•

Execution utilizing appropriate practices based on the theory, planning, and relevant operational experience


1.1

PURPOSE

The purpose of this manual is to provide a detailed resource that can be used by Engineering and Operational personnel, to plan and execute directional wells, with an integrated hole cleaning design, to optimize overall well performance and minimize risk.

1.2

SCOPE

There are two main parts to this manual: 1.

THE HOLE CLEANING BEST PRACTICES QUICK GUIDE This brief document is provided as a higher level summary of the key theory, planning and execution issues that need to be understood as part of the hole cleaning design. It is intended that this document will be used as a prompt or checklist for those involved in planning and execution of a directional well.

2.

THE HOLE CLEANING BEST PRACTICES MANUAL This document provides more comprehensive detail to support the summary material in the QUICK GUIDE. It is intended to be available for those requiring more details or background when planning or executing a directional well.


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The appropriate links between the sections are shown in the documents, and if using electronically, hyper-links are available to facilitate navigation (hint: if using the document electronically, ensure the Web browser is turned on to use the “back” function. (i.e. On the menu bar -View / Toolbars / Web)

1.1

CHANGE PROCEDURES

If changes or additions are seen as necessary, the form on the following page should be filled out and sent electronically or as a paper copy, to John Gradishar or Eric van Oort, as per the details below: Email: [email protected] [email protected] Paper Copy: John Gradishar or Eric van Oort Shell Exploration and Production Company PO Box 61933 New Orleans, LA, 70161-1933

Note, if you require further details of any of the material contained within the QUICK GUIDE or MANUAL, contact SEPCo personnel as above (504 728 7490), or K&M Technology Group in Houston (Russell Conwell, 281 298 6900, [email protected]).


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SEPCo HOLE CLEANING BEST PRACTICES MANUAL REVISION REQUEST FORM Name of person requesting revision: __________________________________________________________________ Company:_________________________________________________________________________________________ Title:_____________________________________________________________________________________________ Date:_______________________ Revision to:

URGENT REQUEST

QUICK GUIDE

ROUTINE REQUEST

MANUAL

BOTH

Revision request based on operations from which rig:____________________________________________________ Field ? _________________________________________Well ? _____________________________________________ Topic:____________________________________________________________________________________________ Description of revision:______________________________________________________________________________ __________________________________________________________________________________________________ __________________________________________________________________________________________________ __________________________________________________________________________________________________ __________________________________________________________________________________________________ __________________________________________________________________________________________________ __________________________________________________________________________________________________ __________________________________________________________________________________________________ __________________________________________________________________________________________________ __________________________________________________________________________________________________ __________________________________________________________________________________________________ __________________________________________________________________________________________________ SEND THIS FORM TO:

John Gradishar or Eric van Oort Shell Exploration and Production Company PO Box 61933 New Orleans, LA, 70161-1933

IF ADDITIONAL SPACE IS REQUIRED, PLEASE ATTACH TO THIS FORM


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Apr 2003


2

HOLE CLEANING – THE SYSTEMS APPROACH

Hole cleaning is one of the key challenges in a high angle well. It is directly and indirectly impacted by a wide range of planning and execution issues, and optimizing hole cleaning performance in a specific interval needs to consider all of these issues. This requires hole cleaning to be planned using a “Systems Approach”. Using a systems approach means that all planning decisions and operations and must treat the entire well as a single system. Specifically, the entire well should be viewed as a hole cleaning system. This means that all designs and execution issues must be considered to be inter-related. For example, you cannot simply change the bit or BHA, mud system, or drilling parameters without considering how each of these components affects the others, and the overall impact on hole cleaning efficiency. In an effort to help planning and operational personnel adopt this systems approach to hole cleaning, the concept of “Drilling in the Box” is used. “Drilling in the Box” is used to represent the engineering required in the planning and execution stages of a well in order to optimize hole cleaning as part of the entire drilling system. The inside of the box represents an environment of “good hole cleaning”, with the sides representing the limits that must be taken into account in order to remain in the box. Throughout the planning and execution phases of a well, it must be remembered that changes to one parameter will impact others, and a systems approach must be applied to all decisions, to remain within “the box”. For simplicity, this systems approach to hole cleaning is broken up into “The planning Box” and the “Execution Box” as detailed in the following sections.


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2.1

THE “PLANNING BOX” ECD Planning

r bo e ll W

ell W

s De

ign

Rig Capability

Mud Selection

& g lin l i Dr Drillstring Desig n

c re Di

e

ity bil a St

li ril D l na tio

ng

Soft Issues

ip Tr

g pin

es tic c a Pr

te ra t S

s gie

Casing Running

Figure 1 Hole Cleaning Best Practices Manual Rev 0

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All of the issues shown in the planning box (Figure 1) are critical hole cleaning parameters that must be considered in the early stages of planning the well. The goal is for the Engineers planning the well to evaluate how each of these issues will impact the hole cleaning performance, and attempt to design out any limitations. If the hole cleaning limitations are not removed at this stage, it will become very difficult to optimize hole cleaning performance in the execution phase of the well.



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THE “EXECUTION BOX”

Pr

ac

le Ho

Mechanical Tools

Mud Properties

Tripping Practices

Re

le Ho l dia me

ea Cl

g nin

es tic

Drilling Parameters and Practices

ECD Managemen t

ion d it n Co

c re Di

M

r ito on

Dr al n tio

ing

ng illi

pr

Soft Issues

2.2

t ic ac

es

Figure 2 Hole Cleaning Best Practices Manual Rev 0

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Apr 2003


All of the issues shown in the execution box (Figure 2) are critical hole cleaning parameters that must be considered in the execution stage of the well. The goal is for Operations Personnel to work with the well plans and equipment that have been provided, and optimize the actual hole cleaning and overall performance in each section of the well.



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3

HOLE CLEANING THEORY

The following section presents the fundamental theory of hole cleaning. Hole cleaning is not only one of the most difficult challenges on a high angle well, but is often poorly understood, which can lead to many related hole problems. It is critical to understand what is happening to cuttings that are generated in a high angle well, and the interaction of these cuttings when drilling, tripping and running casing. This is a pre-requisite to “intelligently” managing hole cleaning in both the planning and execution phases of the well.

3.1

SOLIDS IN A WELLBORE

Hole cleaning is fundamentally about the removal of solids from a wellbore. Solids can be made up of several different components:

•

Cuttings – the rock cut away by the bit (see Figure 3). Generally, these are the most significant solids that need to be removed from the wellbore. The longer the cutting stay in the wellbore, the more they will break up into fines. The hole size and the ROP determine the volume of cuttings that are generated and must be removed. An illustration is provided below to give an indication of the relative volume of cuttings that are generated when drilling different hole sizes at a range of ROP.

STANDARD BED FOR FORD F-150 PICK UP TRUCK IS ± 60FT3

HOLE SIZE

17½” 14½” 12¼” 8½”

•

ROP

NUMBER OF BEDS FILLED TO THE

(ft/hr)

TOP IN ONE HOUR

200

5.6

50

1.4

200

3.8

50

1.0

200

2.7

50

0.7

200

1.3

50

0.3

Cavings – rock that was part of the wellbore wall that has broken away. Cavings result when the wellbore becomes unstable (SECTION 4.3.3), and a large volume of cavings can be generated in a very short time. They are often very large and consequently can be more difficult to remove than cuttings (see Figure 3).


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Apr 2003


•

Fines – a mixture of reground cuttings and/or cavings that are difficult to remove from the hole and the mud system. These are also known as low gravity solids and account for a major portion of the drilling fluid maintenance cost and effort (SECTION 5.2.5).

•

Swarf / Junk / Cement – other solids that may have to be removed from the wellbore.

CUTTINGS

PDC “orange peel” cuttings

CAVINGS

Figure 3


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1.1

HOLE

CLEANING REGIMES

Hole cleaning can be divided into 3 different regimes based on the wellbore inclination. As shown in Figure 4 below, the cuttings transport, and therefore hole cleaning strategy, will be quite different for each inclination range.


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Cuttings Cuttings Movement Without With Flow 60°0° 35° - -35° 90° 60°Movement Flow


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Figure 4 In a vertical to 35° degree well, cuttings are brought to the surface by combating cutting slip velocity, where the cutting must fall thousands of feet to reach the bottom of the hole. Hole cleaning is simply provided by the viscosity and flowrate of the drilling fluid. When the pumps are turned off, cuttings are suspended by the thixotropic drilling fluid, although settling will occur with time. In wells with inclinations in the range of 35° - 60°, cuttings begin to form “beds”, as the distance for them to fall to the bottom of the hole is now measured in inches (SECTION 3.3.3). The cuttings move up the hole mostly on the low side, but can be easily stirred up into the flow regime. The most notable feature of this inclination range is that when the pumps are shut off, the “beds” will begin to slide (or avalanche) downhole. This increases the potential for pack-offs and stuck pipe, and significantly changes the hole cleaning strategy with respect to the vertical well scenario. The final inclination range of 60° - 90° presents a different set of operational circumstances. Here, the cuttings fall to the low side of the hole and form a long, continuous cuttings bed. All of the drilling fluid will move above the drillpipe, and mechanical agitation is required to move the cuttings. Although the challenges associated with an avalanching bed have gone away, hole cleaning in this environment is still difficult, and often more time consuming. It should be noted that a high inclination or horizontal well has sections of all three inclination ranges, and all must be considered in the hole cleaning strategy.


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Apr 2003


1.2

WHAT IS HAPPENING DOWNHOLE IN A HIGH ANGLE WELLBORE?

To design an effective hole cleaning system, it is critical to understand what is actually happening in the wellbore. Downhole conditions are often misunderstood in the drilling industry, especially in high angle wellbores.

1.2.1

Fluid Flow

As shown in the Figure 5, fluid flowpaths and velocities are different in a high angle well compared to a vertical well. In a vertical well (and in the vertical portion of a high angle well) the fluid moves freely around the drillpipe. Annular velocity (AV) is a meaningful term since the fluid velocity is essentially uniform. In a high angle wellbore, the term “AV” is less meaningful, since the fluid is essentially only moving above the drillpipe where there are no cuttings (without pipe movement).


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High Fluid Low Cuttings Velocity and cuttings on the move low side will not be High Vertical angle Wellbore Wellbore disturbed Velocity uniformly Fluid by in fluid annulus unless stirred up by pipe Fluid rotation


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Apr 2003


Figure 5


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Apr 2003


1.2.2

Cuttings Transport

A good analogy for cuttings transport in a high angle section of a wellbore is that of a conveyor belt (Figure 6). The high velocity fluid flows up the high side of the hole as the drillpipe lays on the lowside. Without pipe rotation there is no way for the cuttings to get into the high velocity fluid stream and therefore the conveyor belt is basically turned off. Rotation turns the conveyor belt on as it pulls the cuttings up into the high velocity fluid and they are moved up the hole. However, the cutting are acted on by several forces, including gravity, and after a certain distance they will fall off the conveyor belt back to the lowside of the hole. The distance the cuttings will travel on the conveyor belt before falling off is a function of flowrate, rpm and fluid rheology (viscosity). Once the cuttings have fallen off, they are then returned to the conveyor belt by rotation, and the process continues up the hole. Flowrate basically governs the speed of the conveyor belt and how long the cuttings will stay on it. Understanding this analogy has significant consequences for mud rheology, drilling parameters, bit and BHA selection, and general hole cleaning requirements.


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Resultant Force As Cutting Gravity cuttings from force Fluid are on pushed by High Drillpipe Drillpipe velocity on rotation flow areaupatthe thehole top of the high cutting flow velocity fluid, gravity acts lowside the turns hole the of acts hole conveyor like a conveyor belt to pull them back to the lowside the transporting belt on as itthe lifts cuttings the up theofhole hole. Eventually the cuttings will fall cuttings back onto the off the conveyor conveyor belt (referbelt to due to the summation Figure 9) of these forces. Flowrate governs the speed of the conveyor belt and how long the cuttings stay on it.


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Figure 6


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Apr 2003


1.2.3

Cuttings Beds

In a high inclination well, cuttings beds are inevitable for the following reasons: •

Cuttings only have a few inches to fall to the bottom of the hole.

•

Once on the bottom of the hole they are in a region of low flow, from which it is difficult to remove the cuttings without rotation.

•

Even when the cuttings are in the high velocity flow stream, and with rotation, they will eventually fall to the bottom of the hole due to gravity.

Hole cleaning is all about managing the cuttings bed height and distribution such that operational problems are avoided. Refer to SECTION 3.4 for further details of acceptable cuttings bed height and distributions.

1.1.1

Cuttings Dunes

Cuttings dunes are different from cuttings beds as they tend to form localized “mounds” rather than flat beds which are spread out along the wellbore. They are generally formed when the conveyor belt is turned off (i.e no rotation), and cuttings are not being efficiently transported up the hole. The most common example would be slide drilling where rotation is not possible. While slide drilling, the annular velocity (AV) of the fluid around the drill collars will likely keep that region free of cuttings, regardless of the other drilling parameters. However, as the fluid passes the BHA in the annulus, the AV drops considerably. Fluid flow will predominate on the high side of the hole and the cuttings will quickly drop out around the HWDP. The cuttings will form a “dune” that builds towards the surface. As it builds, the height of the dune will grow towards the top of the hole. As the dune grows upwards, the AV above the dune increases, helping to move cuttings to the front of the dune. Once in front of the dune, the AV is again reduced, and the cuttings drop to the bottom of the hole. Thus, the dune will move very slowly up the hole. This is known as Saltation Flow in a high angle or horizontal wellbore (see Figure 7). It is important to understand and to take this phenomenon into account prior to beginning rotation or tripping following a long slide interval, or any other period where there has not been any rotation. If the dune volume has been allowed to grow to a critical height and size, it is possible to pack-off the hole with the cuttings once rotation begins, or when tripping the BHA through the dune. Efforts should be made to prevent the build-up of large dunes by regular periods of rotation (on or off-bottom) during long slide intervals. Refer to EXAMPLE 11.9 for an example of ECD spikes with rotation after sliding. It should also be noted that dunes can be formed at any other point in the well where AV’s are significantly reduced (e.g. washouts, above liner tops, etc). Backreaming with insufficient parameters (e.g. pulling too fast, reduced rpm) will also result in dunes forming and greatly increased risk of packing off and stuck pipe.


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Dunes Cuttings candunes also form form at above otherthe areas BHA where when AV’s sliding. are reduced, As a cutting or when dune backreaming forms, it slowly with insufficient parameters. moves up Tight the hole hole byand a process packing known off can as occur Saltation when Flow. rotation is started or tripping through dunes.

Figure 7 Dependent upon the degree of slide vs. rotary drilling, the inclination (i.e. avalanching), and the length of the hole, multiple “beds” can be moving out of the hole at any one time. As these beds reach the surface, they are often mistaken as the hole “unloading” or the result of a sweep.


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1.2

WHAT IS A CLEAN HOLE

As discussed previously, every high angle wellbore will have a cuttings bed of some thickness and distribution, regardless of how efficient the hole cleaning practices are. Management of the cuttings in the hole is the key to efficient drilling operations. However, a wellbore does not have to be 100% free of cuttings to be considered “clean”. A “clean” hole can be defined as:

“a wellbore with a cuttings bed height and distribution such that operations are trouble free”. Note that a hole that is “clean” for drilling is not necessarily the same as that for tripping a BHA or running casing. This is mainly due to the differences in annular clearance seen in these various operations, and the resulting ability to trip the pipe through the cutting bed. See Figure 8 below. In general, a higher cuttings bed can be tolerated when drilling as the BHA is not being pulled through the cuttings bed. However, when tripping, a cleaner hole will be required (lower cuttings bed) to allow free movement of the BHA through the cuttings bed. An acceptable cuttings bed height will often depend on the bit and stabilizer design (refer to EXAMPLE 11.13).


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Apr 2003


Bits Drillpipe Casing Stabilizers - a“A bit-Clean -with Cuttings Running -acan large bed have casing junk can a slot will bedrilling Hole for significant require area higher willafor trip cleaner drilling impact morehole on freely because how than than clean drilling thea to BHA the avoid hole is heavy not ploughing must being setbe bitto pulled through trip cuttings through it beds


is not the same as a clean hole for tripping”

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Apr 2003


Figure 8 Based on the discussion above, hole cleaning practices need to be developed specifically with respect to the following distinct operations:

•

Drilling – higher cuttings beds can be tolerated as the BHA is not being pulled through them. Bed height will generally be limited by pack-off, ECD and excessive T&D.

•

Tripping – Cuttings beds will need to be reduced in height to allow the BHA (with stabilizer and bit restrictions) to be pulled through them without tight hole and packing off (refer to EXAMPLE 11.13).

•

Casing Running – depending on the annular clearances and slack-off weight available, there may be very little tolerance for cuttings beds being pushed in front of the casing (i.e. increased friction, surge). This may require minimal or no cuttings remaining in the hole.


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Apr 2003


1.1

HOLE CLEANING MECHANISMS

There are two main mechanisms for hole cleaning: Dispersion and Mechanical removal. Dispersion involves the cuttings “disintegrating” into the mud, and being removed from the hole as part of the mud itself. This not only requires a formation which is easily dispersed, but also an uninhibited mud system that will allow the cuttings to disperse into it. Cleaning is primarily a function of dilution of the mud at the surface (i.e. discarding the solids laden mud). In general, dispersion only applies in large diameter top hole sections that drill soft clay or siltstone formations. The mud systems are generally low cost seawater or gel systems (spud muds).

Large washed out hole is an inevitable consequence of the lack of

inhibition in these muds. With Mechanical removal of cuttings, discreet cuttings must be mechanically carried out of the wellbore by the fluid. This requires a combination of appropriate parameters (e.g. flowrate, rpm, viscosity) and practices (e.g ROP, connections, tripping) in order to be effective. The majority of hole cleaning problems encountered in high angle wellbores are related to inadequate mechanical hole cleaning, and the remaining sections of this manual address this hole cleaning mechanism. It should be noted that some hole cleaning documentation recommends that turbulent flow be used in order to improve hole cleaning in the annulus. In practices, turbulent flow is almost impossible to achieve with normal drilling fluids in the annulus. For example, with 5½" drillpipe, flowrates of 3500gpm, 1800gpm and 800gpm would be required in 17½", 12¼" and 8½" hole respectively, in order to generate turbulent flow. Basically, in order to get turbulent flow, very low rheology (e.g. seawater) must be combined with very high flowrates. This is not recommended in practices as the fluid is left with little cuttings carry capacity if the pumps are shut down.


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1.2 1.2.1

HOLE CLEANING PARAMETERS Rotation

Rotation is the key parameter for hole cleaning efficiency in high angle sections, where mechanical removal of cuttings is required (i.e. turns the conveyor belt on). As shown in Figure 9 below, the high velocity flow area is at the top of the hole, above the pipe and cuttings bed. Regardless of the fluid rheology or flowrate, it is almost impossible to move this cuttings bed without mechanical agitation. Rotation provides this agitation, pulling the cuttings up into the active flow area with a mechanical and hydraulic action. The hydraulic action is due to the “viscous coupling” effect, which is a function of the viscosity of the mud.

Low With High Cuttings Velocity rotation Velocity on Fluid ofthe thelow pipe, side cuttings will notwill be be No With Rotation Rotation disturbed pulled Fluid up by into fluidthe unless highstirred velocity up by fluid pipe (mechanically and rotation also due to the viscous coupling effect)


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Figure 9 It is not just pipe rotation, but the speed of rotation that has proven critical for effective hole cleaning. As shown in the Figure 10, operational experience in 9⅞" and larger hole sizes, has consistently shown a step-change in the volume of cuttings coming over the shakers depending on the rpm used. This graph is not based on a theoretical model or laboratory experiments, but rather, on actual operational experience from a broad cross-section of high angle wells around the world. Refer to EXAMPLE 11.5 and EXAMPLE 11.10. In 9⅞" and larger hole sizes, there are at least two distinct hurdle rotary speeds at which step improvements in cuttings return are seen in high angle sections. These occur at 100-120 rpm, and at 150-180 rpm. These speeds have proven to be quite consistent for different hole sizes, drillpipe sizes, and mud types. Note that several operators have experimented with rotary speeds of up to 220rpm in 12¼" hole, but little incremental benefit (cuttings return) has been seen over 180rpm. In large diameter holes such as 16” or 17½", rotation speeds greater than 130-150rpm should be avoided, as some operators have seen significant BHA damage at high rotary speeds in this large hole size. Vibrations monitoring should be an integral part of optimizing the rpm to avoid harmonics, and vibration induced drillstring and downhole tool failures.


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100 150 Fine Pipe Relative – tuning 120 180 rpm of pipe rpm Effectiveness (9⅞" and larger hole sizes) RPM vsrpm Hole Cleaning Cuttings from 60-80rpm Return is generally Volume not meaningful


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Figure 10 For the following reasons, adequate hole cleaning in 8½" and smaller hole sizes is seen with rotary speeds as low as 60-80 rpm:

•

The pipe is better centralized by the tool joints in the smaller hole (less eccentricity)

•

Smaller annular clearance results in increased and better distributed AV’s

•

Viscous coupling more effective

•

Fewer cuttings to remove for the same ROP as larger hole sizes

Refer to SECTION 10.1.1 for the recommended minimum rotary speeds for effective hole cleaning in a range of hole sizes.


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1.1.1

Flowrate

Flowrate is the key parameter to hole cleaning rate. Once the conveyor belt is turned on with adequate rpm, increasing the flowrate simply allows the hole to be cleaned up quicker (i.e. faster speed of the conveyor belt and cuttings stay on longer), or a higher ROP to be sustained while keeping the hole clean. Field experience suggests that a threshold exists on the low side of the flow rate numbers, and that a point of diminishing returns exists on the high side (refer to Figure 11 below). It is important to appreciate the fact that as long as cuttings are coming over the shakers, the hole is being cleaned. Hole cleaning “rate” is then the issue.

Hole Hole Minimum Flowrate Point Relative Cleaning Cleaning of Cuttings rate diminishing flowrate with at 120rpm no Return for rotation benefits returns Volume


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Figure 11 Refer to SECTION 10.1.2 for the recommended minimum flowrates for effective hole cleaning in a range of hole sizes.


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1.1.2

Fluid Rheology

Although not as important as rotation and flowrate, the rheology of the mud also plays a key role in hole cleaning. The rheology is often very difficult to optimize, particularly when also having to consider ECD and barite sag. If the mud is too thick, it will have the following impacts on hole cleaning:

•

Fluid is more prone to channeling up the high side of the hole, with the area of the high velocity flow reducing, and the low velocity “dead zones” increasing in size (see Figure 12). This will make cutting removal slower and more difficult.

•

May increase pumping pressures or ECD’s to the point where flowrate has to be reduced.

If the mud is too thin, it will have the following impacts on hole cleaning:

•

The fluid will lose it’s “viscous coupling” effect and will not be able to move the cuttings as effectively with rotation (i.e. harder to get onto the conveyor belt)

•

Cuttings will drop out of the fluid more easily, making hole cleaning slower (i.e. travel less distance up the conveyor belt)

•

May be some indirect impacts through barite sag, excessive ECD, or wellbore instability.


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Low With High Velocity high Velocity viscosity Fluid fluid, the area of high High Low Viscosity velocity Fluid flow shrinks, and the areas of low velocity flow increase


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Figure 12 Given the drilling fluids that are used for high angle wells, it must be noted that YP is largely a meaningless term for assessing hole cleaning capability. For these wells, shear thinning fluids are generally used for better low-end rheology. The Fann 3 and 6 rpm readings are a better measure of hole cleaning properties in the annulus. A useful rule of thumb for shear thinning fluids is to design the 6 rpm reading to 1.0 – 1.2 x hole size in inches. For SBM systems, the goal is to get the downhole rheologies to these same specifications. Refer to SECTION 5.2.2 for a more detailed discussion of mud rheology and its impact on hole cleaning.

1.1.1

Cleanup Cycles (Time)

As shown in Figure 5, much of the fluid in a high angle wellbore flows up the high side of the hole, bypassing the cuttings beds on the lowside. Thus the term “bottoms-up” (BU) is somewhat meaningless for high angle wells, since the cuttings will move up the hole at a much lower speed than the fluid. Experiments at Tulsa University have confirmed that cuttings move out of the hole up to 3 - 5 times slower than the drilling fluid in a deviated well. A minimum of 2 - 3 x BU (and up to 4 - 6) will be required to cleanup a high angle wellbore. The number of BU required will increase with the following: •

Increased measured depth

•

Higher inclination

•

Larger hole size

•

Reduced parameters (rpm, flowrate, viscosity)

Generally circulation should continue until the volume of cuttings coming over the shakers has reduced to a minimal, or background level. Based on operational experience, it is generally observed that two distinct “waves” of cuttings return over the shakers when performing a cleanup cycle. The exact reason for this phenomena is unknown. However, pumping an additional 1-2 x BU after the first drop off in cuttings should always be considered when performing a cleanup cycle. It is also critical to ensure that the string is rotated at an adequate rpm while performing the cleanup cycle. If for any reason the rpm drops below a critical threshold (e.g. 120rpm in 12¼" hole), this effectively turns off the conveyor belt and the cuttings will not be removed from the lowside of the hole. Flowrates should be maximized to improve the cleanup rate. Hole Cleaning Best Practices Manual Rev 0

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Refer to detailed guidelines for cleanup cycles in SECTION 10.3.1.


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1

OVERALL WELL DESIGN

1.1

PLANNING PROCESS

High angle wells cannot be planned in the same manner as vertical or low angle directional wells. There is generally little margin for error, as well as significant implications when things do go wrong. The following section summarizes some of the key issues that should be considered when planning a high angle well.

1.1.1

General Issues

The following general considerations should apply to the planning process for high angle wells:

•

Adequate time should be allowed for planning. As a general rule-of-thumb, a minimum of 6-12 months lead-time is required for challenging high angle wells. However, the required planning time will vary depending on many different factors (e.g. well design, rig capability and required upgrades, offset experience, location, etc). Needless to say, the longer the planning time allowed, the less chance there will be of critical issues being missed. Do not expect optimal performance from the well if insufficient planning time is allowed. Refer to EXAMPLE 11.3.

•

Along with adequate planning time, adequate resources need to be made available for planning a high angle well. This will include Engineers with experience drilling high angle wells (or Engineers with specific ERD training), relevant service company specialists (e.g. mud, directional, cement, etc), as well as dedicated completions, geology, and reservoir engineering personnel.

•

A Senior Engineer should be dedicated to the planning process to act as a “project manager”. The role of this individual would be to maintain the focus on a system approach to the overall well design.

•

Consistent personnel should be maintained through the planning process to avoid issues being missed or background knowledge being lost.

•

Operations personnel (e.g. Rig Superintendents, Foremen, Toolpushers) should also be included in the planning process from an early stage. This will achieve the following: ○

Pave the way for acceptance of new ideas into the field

○

Provide some ownership of the drilling plan

○ Identify significant operational issues that need to be addressed early in the planning stage.


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1.1.1

Planning Steps

High angle wells should be planned using a systematic approach that allows the designs to be progressed in a series of steps as the spud date approaches. Following these systematic steps will provide a solid engineering basis for the final well design, and ensure that key areas of the design are not missed. Some possible steps in this procedure are presented below. However, the required planning steps for each high angle well will be different based on the time and resources available, the nature of the well, and the anticipated risks. •

Establish team and level of knowledge

•

A quality Offset Well Review (OWR) is an essential first step in the planning process. The OWR will identify the key issues and risks that will need to be the focus of the planning process.

•

A Preliminary Well Design (PWD) should be generated to achieve the following: ○

Establish a pore the pore pressure, fracture gradient and wellbore stability profiles

○

Establish the drilling feasibility and evaluate the risks of a given high angle well. This is achieved with T&D, hydraulics, and hole cleaning modeling (SECTION 4.3.4).

○

Establish the required drilling rig capability, drillsting, drilling fluids, BHA strategies, and power requirements.

○

Develop plans for contracting of rig and third party services.

○

Define the workscope for the following stage of the project.

○

Allow a relatively accurate time and cost estimate to be generated and therefore used for further economic evaluation of the project as a whole.

•

•

A Detailed Well Design (DWD) should be generated to achieve the following: ○

Final drillpipe and casing specifications to allow materials to be ordered.

○

Final confirmation of rig specifications.

○

Tendering and selection of directional drilling, drilling fluids, cementing and other services.

○

Improved time and cost estimates.

Drilling Programs and / or Detailed Hole Section Guidelines should be produced. These are the detailed operational plans that will be used by the field personnel for drilling the well. Sufficient detail should be included to ensure that the all critical planning issues are captured, and adequately translated into operational practices.

•

Training of the relevant personnel in hole cleaning and general high angle drilling practices (SECTION 4.1.3).

•

As a final step in the planning process, the planning and operations team should participate in a “Drill the Well on paper” (DWOP) exercise. This workshop should focus on the actual mechanics of implementing the plan and conducting realistic "what if" exercises. It should also focus on the critical equipment being utilized to ensure that it is fit for purpose.

•

It is also recommended that a comprehensive pre-spud meeting be held with the rig crews to familiarize them with the well plans. This may be before the well, or before the start of each critical hole section.


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1.1.1

Training

When planning high angle wells, there are a significant number of issues that must be considered. A clear understanding of these issues, and their inter-dependence, is critical in developing wells designs for minimal risk and optimal performance. Additionally, if limitations are not designed out of the system in the planning phase of the well, there is little scope for optimization in the execution phase of the well. Specific ERD training should be a pre-requisite for Engineers involved in the planning of high angle wells. Additionally, all office based staff involved in the upfront decision making should have some exposure to ERD specific training to help with the “what”, “why”, and “How” of drilling high angle wells. Specific training is also required in the execution phase to ensure that all onsite personnel are able to understand what is happening downhole, use the appropriate practices, and make the right decisions for the success of the well. This training needs to target the Drilling Foreman and Toolpushers, but will also apply for the entire drilling crew as well as Service Company personnel.

1.2

SOFT ISSUES

Although the following are considered the “soft issues”, in planning and executing high angle wells, these are often some of the more significant issues to be considered.

1.2.1

Commitment to the Process

In both the planning and execution phase of the well, having commitment and alignment at all levels is fundamental to the success of a high angle well. From senior management down to the shaker-hand on the rig, there must be a clear understanding of the risks involved with drilling high angle wells, as well as understanding: •

“what” needs to be done

•

“why” it needs to be done

•

“how” it is going to be done

Without this clear understanding, it is relatively easy for decisions to be made which may seem sound for normal wells, but result in significant impact on performance and cost for a high angle well. Following are some common examples of this: •

Senior management may not approve upgrades to rig equipment if they do not understand “why” it is required.

•

An onsite Foreman, who does not understand “why” it is required, may choose not to perform a cleanup cycle prior to tripping out of the hole as he sees it as non-productive time.

•

A shaker-hand may fail to notice and report that little or no cuttings have been coming over the shakers for the last few hours of drilling, and also for the cleanup cycle prior to tripping.

Training and education is the primary means of gaining this understanding and commitment of all personnel to the process. Having experienced ERD personnel is also beneficial in gaining this commitment. Hole Cleaning Best Practices Manual Rev 0

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1.1.1

Logistics

Particularly in remote and / or offshore locations, logistics can be a significant and complex issue for high angle wells. This is basically due to the requirement for more material, equipment and people. Following are some examples where logistics management may be more difficult with high angle wells:

•

ERD designs often require specialized casing, tubulars and other equipment which may be difficult to find or have long lead-times if manufactured (e.g. high collapse casing, hi-torque connections, specialized rollers, etc). This is another reason why planning for high angle wells requires adequate lead-time to avoid “living with” inadequate off-the-shelf equipment.

•

With longer / deeper hole sections, large volumes of mud will be involved. Additionally, with the use of both WBM and SBM likely, there are other changeover and deliver issues that need to be managed. Detailed pit plans may be required for the following operations: ○

Building / delivering initial mud volumes.

○ Running casing (especially if casing is run empty), where large mud volumes may be recovered and must then be (a) stored or sent away, or (b) stored and pumped down hole for the cement job or casing fill-up. •

Increased volumes of cement, barite and other chemicals.

• •

Well control implications always need to be evaluated (large mud volumes and barite quantities) Drillpipe racking space in the derrick is often insufficient for long high angle wells, especially if tapered or multiple drillstrings are necessary. It is not uncommon for the last portion of a high angle well to require that drillpipe is pickedup/laid-down due to insufficient derrick capacity, or to make room on the floor to run casing.

•

Substructure weight limitations may prevent the combination of a full derrick of drillpipe and casing on the pipe rack. This may be further complicated if mud storage capacity on board must be increased to manage SBM usage.

•

For ultra-long high angle wells, there is often inadequate space available to store casing on the pipe rack and some casing may need to be run off of the boats. Casing stacked very high can create safety and storage problems.

•

Accommodation for personnel is often a key issue for high angle wells. Additional personnel are almost always required for these wells (such as for SBM environmental compliance services, extra solids control equipment, different directional drilling tools, extra rig crews for running casing, etc.).

Unless the onsite Drilling Foreman is given additional logistics management support, they are likely to be overwhelmed by the logistics issues (or at least be completely devoted to them).


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1.1.1

Quality Control

Quality control is an important function on any well. However, it is critical on a high angle well for several reasons:

•

High angle wells tend to push equipment and tools to their limits, and if inherent quality problems exist, the probability of failure is greatly increased.

•

The failure of poor quality or defective equipment and tools can have significant impacts on a high angle well (e.g. collapsed casing, failure to reach well objectives).

•

Trip times for failed tools are significantly longer than conventional wells.

•

Fishing and recovering from downhole tool failures is time consuming, and can also lead to further problems in the hole.

A strict quality control plan should be in place for all equipment which is used on a high angle well. This should include inspection and maintenance plans for equipment before and after being used.

1.1.1

Contingency

As with quality control, contingency planning is an important function on any normal well, but is that much more critical on a high angle well. Contingencies should be planned in detail with the financial and time commitments made to those contingencies that are seen as necessary. For example, if a contingency hole size is planned, a financial commitment may be required to have the casing/liners and directional drilling tools necessary to act on that contingency. The following general contingencies may be considered: •

Loss Circulation

•

Stuck Pipe (while drilling and running casing / liners)

•

Fishing

•

Well Control

•

Wellbore Instability

•

Sidetracking

•

Openhole abandonment

•

Alternate Hole sizes

•

Weather

•

Spills


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1.1

TECHNICAL ISSUES

The overall design for a high angle well is a function of many different technical design requirements. Although hole cleaning may be the key driver in one section, it may not be in the next. Thus the overall well design needs to be evaluated from a “big picture” perspective, as well as looking at each critical section in detail. The following sections address the key technical well design areas, and discusses issues that need to be considered in the planning phase with respect to hole cleaning and other design requirements.

1.1.1

Wellpath

The wellpath design is critical to the success and optimal performance of any high angle directional well. Despite it’s importance, the wellpath design is often given too little thought, or is given a lower than appropriate priority with respect to other key design features. Ultimately, the directional plan affects every aspect of the well design: •

Total depth (MD), tangent angle, casing depths

•

Directional drilling and bit strategy

•

Hydraulics and hole cleaning

•

Mud weight (Wellbore stability, differential sticking, losses)

•

Torque, Drag and Buckling

•

Geological and survey uncertainty

•

BHA tripping difficulties

•

Casing running

•

Rig capability requirements

•

Logging options

•

Completion and workover design and options

There are several main wellpath profiles, with many other variations using a combination of these. These profiles are shown in Figure 13 and detailed in the following section. Note that several design iterations are usually required before an optimal wellpath is decided on. One of the key issues for hole cleaning and the wellpath design is to evaluate the areas of the well in which cuttings are likely to accumulate due to avalanching. This is usually at the base of tangent intervals between 35º - 60º.


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PROPRIETARY

TVD

Shell Exploration and Production Company

CATENERY S-TURN

B&H

COMPLEX HORIZONTAL THROW

Figure 13

1.1.1.1

Build and Hold Profile


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This could be thought of as the conventional design for directional wells. A constant build rate is used to kick the well off from vertical, building to a tangent angle that is held constant all the way to the target. Build and hold profiles minimize the total depth and required directional work, and are a good starting option for a high angle well design. For hole cleaning, the inclination of the tangent section should avoid 35º - 60º if possible, as this will be the most difficult inclination to clean (i.e. good practices will be critical). Hole cleaning at inclinations above 60º will be easier as there will not be any avalanching of cuttings beds in the tangent, but cleaning the hole up will take longer.

1.1.1.2

Catenary Profile

There has been a trend within the industry to use “pseudo-catenary” directional plans for high angle wells. Such designs use low initial build rates (e.g. 0.5-1.0/100’), accelerating to higher build rates as the angle increases (e.g. 4-5/100’).

The main benefit of this design is reduced drilling torque over a conventional build and hold design, which uses faster initial build rates. Likewise, casing wear can also be reduced. However, there are several potential downsides that also need to be considered. For instance, a catenary design considerably increases both the tangent angle and overall total depth. For a well with 6000m (20,000ft) throw at 2500m (8200ft) TVD, a catenary design adds about 10 angle and 1000m (3300 ft) to the total depth (compared to a build and hold design with 2.5/100ft build rates). The extra measured depth may result in reduced flowrates if the rig has a limited hydraulics capability, or increased ECD’s. The increased tangent angle of a catenary design may positively or negatively impact hole cleaning. As discussed in the previous section, an increased tangent angle may move hole cleaning out of the difficult “avalanching” zone. However, the increased angle may also make wellbore stability more difficult to manage, which in turn can make hole cleaning unmanageable. It is also likely that increased mud weights will be required for stability at the higher angle (may impact flowrates). Additionally, a commonly experienced downside of the catenary curve is that the higher angle increases the difficulties associated with running drillpipe, casing/liner, completion, and coiled tubing for workovers. Depending on the drivers for casing setting depths (e.g. tied to a TVD of formation, tied to a measured depth, etc), this well profile may have a significant impact on the required hole and casing lengths. For example, a 13⅜” casing depth tied to TVD would be shallower using a catenary profile, and thus hole cleaning would be improved for this shorter 17½" interval.

1.1.1.3

S-Turn Profile

When a higher tangent angle may be beneficial to avoid the avalanching zone, and other well objectives allow, consideration should be given to an S-turn profile. Advantages include: •

A reduction in the angle-of-attack into the target, thus reducing the TVD survey uncertainty impact (although, the lateral survey uncertainty will still be just as significant).


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•

The effect of geological uncertainty is lessened, again because of the lower angle-of-attack. With the inherent difficulties associated with deep sidetracks in high angle wells, this becomes a worthwhile consideration.

•

It will reduce the drilled interval in (and below) the payzone, which often proves to be the most difficult drilling. Not only can the formation be harder and more abrasive, but also ECD’s and torque will be at their highest. Also, formation instability issues are reduced due to less exposure time.

•

The total depth may be reduced. Although the depth to the target is greater due to the less direct route, the total depth is often less due to the lower angle at TD.

•

Payzone cementing may be made more reliable. If the angle across the pay-zone is kept to less than 45, then the cuttings bed will avalanche to TD. This will reduce the residual cuttings on the low side of the hole where flowrates are poor and actually make hole clean-up somewhat easier.

•

Formation contact may be reduced, resulting e.g. in a lower differential sticking tendency opposite depleted formations.

Design and practices will need to manage the hole cleaning through the tangent as well as the drop section of the well.

1.1.1.1

Complex 3-D Well Designs

For these well design, the hole cleaning will again need to consider the different inclinations sections in the hole. Additionally, the hole may need to be cleaner for casing running due to the azimuth changes that the strings will have to run through (ploughing of the shoetrack).

1.1.2

Hole and casing size

The majority of high angle wells drilled around the world use a combination 17½”, 12¼” and 8½” hole sizes. The reasons for this include the availability of tools and equipment, ability to drill smaller contingency hole sizes, and simply the depth of experience in these sizes. However, for SEPCo Deepwater operations in the GOM, these “standard” hole sizes are not generally used. This is due to the large number of casing strings required, and the resulting minimal clearance casing programs required. These casing programs will have several key impacts on hole cleaning which need to be accounted for in the overall well design:

•

Generally require oversize hole sections to be drilled. Drilling Oversize hole may make hole cleaning more difficult (i.e. lower AV’s), but may also have some advantages: ○

Reduced ECD’s and therefore higher flowrates

○ Larger JSA and annular clearance with bi-center bits or underreamers allows greater tolerance when tripping through cuttings beds (refer to EXAMPLE 11.1 and EXAMPLE 11.2).

•

Liners are generally required for lower intervals, thus leaving larger ID casing / liners exposed while drilling smaller hole sizes with limited flowrates. For example, the last hole interval may be a 6¼" x 7” hole section drilled through a 7⅝" liner, with 9⅝", 11¾” and 13⅜” casing above. Planning needs to account for cleaning these upper large OD hole sections with very low flowrates.


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1.1.1

Wellbore Stability

Wellbore instability and hole cleaning problems are inherently linked by the following mechanisms:

•

Maintaining wellbore stability is generally more difficult for high-deviation wells, meaning that higher mud weights are usually required to stabilize high-deviation wells in normally stressed environments such as the GOM. Such wells are also more difficult to clean. Wellbore instability thus may compound the already significant challenge of hole cleaning on high-deviation wells.

•

Instability will lead to borehole enlargement, resulting in lower AV’s with reduced hole cleaning capacity.

•

Instability will introduce additional solids (e.g. cavings, rubble fragments etc.) into the annulus, which require additional hole cleaning measures;


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The main causes of wellbore instability are the following:

•

Inappropriate effective downhole mud weight. Near-wellbore stresses, governing stability in a newly excavated borehole, are determined by the following factors: (a) the in-situ stress state, determined by the formation stresses and pore pressure; (b) the rock strength and failure parameters, determining the ability of the rock to withstand certain stress loads; (c) the wellbore trajectory (i.e. wellbore deviation and azimuth); (d) the mud weight itself, compensating in-situ stresses and pore-pressure; (e) circulation and pipe movement that affect the dynamic ECD. Non-optimum mud weight / ECD leads to the following problems:

○ Effective mud weight too low. When the effective mud weight / ECD acting on the formation is too low, nearwellbore formation stresses will overcome formation strength and trigger hole enlargement and possibly full-scale collapse. This situation may arise when the mud weight selected is too low for the formations drilled, by swabbing, or if the hydrostatic head has been reduced indirectly by barite sag or excessive downhole mud losses. Note that the optimum mud weight for wellbore stability can be assessed using STABOR.

○ Effective mud weight too high. When effective mud weight / ECD acting on the formation is too high, the nearwellbore formation stresses may be placed in tension, leading to tensile wellbore fracturing or the re-opening of natural fractures, with associated mud losses.

•

Annular pressure fluctuations (e.g. excessive swab & surge). Annular pressure fluctuations are an important, yet underestimated, cause of wellbore instability and stuck pipe problems. Pressure fluctuations will cycle stress on the wellbore wall, giving rise to wellbore “fatigue”, i.e. progressive yielding – and ultimate failure – of the rock in time. Minimizing pressure fluctuations (e.g. by slow mud pump acceleration / deceleration, preventing excessive mud viscosity and progressive gels that may trigger surge and swab, etc.) will deliver a more stable wellbore for a longer period of time.

•

Adverse drilling fluid – formation interactions. Several mechanisms, including mud pressure penetration and clay swelling, may lead to wellbore instability exposed to WBM or OBM/SBM with inappropriate invert salinity. Usually, there is a specific time factor associated with this form of instability, i.e. it takes a specific amount of time before drilling problems become significant / insurmountable.

•

Drill string vibrations / side-cutting action. Besides accelerating failure of drillstring components, adverse drill string vibrations and uncontrolled action of side-cutters may generate high impact forces and shock-loads onto the formation that may cause it to destabilize.

•

Impact of bit nozzles / flow rate. The fact that ordinary annular flow can erode competent rock is a common misconception that pervades a lot of open literature and internal Shell documentation. However, it is certainly true that jet flow from nozzles can readily erode and wash out poorly consolidated formations such as shallow sands. It is therefore never a good idea to leave the string static while circulating.


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Inherent sources of wellbore instability problems include formations in the following categories:

•

Low-strength / poorly consolidated formations. Typically, shales are the weakest formations drilled in any section (although there are exceptions, e.g. coal beds). Mud weight therefore usually have to be tailored such that they are sufficient to stabilize these shales. Note that this may mean that other formations in the same section (e.g. permeable / depleted sands etc.) may have to be drilled at considerable overbalance in order for the shales to remain stable (with associated risks of lower ROP, higher differential sticking and seepage tendencies etc.).

•

Highly stressed formations. Typical examples of such formations can be found in active tectonic environments such as the foothills of the Rocky Mountains and the Andes, and in areas with active salt movement such as near-/sub-salt plays in the Gulf of Mexico. Such environments need to be carefully analyzed for their non-trivial in-situ stress state and its consequences for mud weight programs, wellpath and casing point selection.

•

Naturally fractured or faulted formations, “rubble” zones. In a class all by itself, these formations may be very difficult to stabilize. Focus should be on preventing fluid penetration into the fracture network, which may lubricate fracture surfaces (i.e. reducing friction holding the rubbled fragments together) and equilibrate pore pressure with mud pressure (i.e. no effective pressure holding the fragments in place, which are readily dislodged with any lowering of annular pressure, e.g. while making connections). This is achieved by: ○

Lowering fluid loss to any extent practicable;

○ Improving the plugging of the (micro-) fractures by the mud using LCM materials (e.g. fine fibers, graphites, lignite & gilsonites – be aware that these materials may cause sheening problems when used in SBMs);

○ Apply a resin/monomer borehole strengthening treatment to the troublesome zones; ○

•

Switching over to WBMs, which generally have better fracture sealing and healing capacity than OBMs/SBMs.

Abnormally / geo-pressured formations. Drilling in a hard, brittle formation with discontinuously elevated porepressure may give rise to the sudden appearance of highly characteristic spallings or “pressure-cavings”. The way to control these formations is to elevate the mud weight, i.e. provide more wellbore pressure support.

•

Formations sensitive to drilling fluids. The majority of formation-fluid incompatibilities are due to clay-rich shales or young chalks interacting adversely with WBMs.

The way to prevent such incompatibilities is to switch over to

OBMs/SBMs, or use high-performance WBMs with special additives to control pressure penetration and inhibit hydration and swelling.

Figure 14 gives a comprehensive overview on how hole cleaning problems, borehole instability, lost circulation and barite sag are related. A succinct overview of some useful borehole stability best practices is given below. More details are given in the “Best Practices for borehole stability & stuck pipe”.


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Annular Packoff Cavings Reduced Gain Loss Poor in ofhydrostatic/ECD loading, loading rheology flowrate mud hydrostatic weight (shallow) (deep) POOR EXCESSIVE WELLBORE BARITE HOLE Increased viscous Swab Enlarged Packoff &mud, hole mud viscosity increased Surge Weakened High mud weight formation INSTABILITY CLEANING ECD SAG / flowrate formation Weakened & rpmLOSSES

Figure 14


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BOREHOLE STABILITY BEST PRACTICES PLANNING To prepare for critical wells or well sections, perform an integrated borehole stability (IBS) study including a STABOR mud weight study. DO NOT assume that maintaining a mud weight equal to pore-pressure plus 0.5 ppg for trip margin is enough to guarantee a stable well. Use the expertise of your sub-surface team (petrophysicists, geophysicists & geologists) to identify sub-surface hazards (e.g. faults and fractures, high-pressure zones) and to conduct borehole stability modeling. Solicit the help of the NWC Fluids Team (formerly GHOST) and BHS Global Implementation Team in SEPTAR if necessary. Prepare & maintain a drag chart for the well. Monitor / analyze deviations from predicted values to assess stuck pipe tendencies. WELL EXECUTION Try to maintain the proper mud weight for wellbore stability at all time – DO NOT play the game of going in with a low mud weight and “letting the hole talk to you” if there is no compelling reason to do so – when the hole decides to talk to you, you may not like what it has to say. DO NOT maintain mud weights low enough to trigger borehole instability problems in a misguided attempt to prevent mud loss problems. You may find that by keeping mud weight low you will actually cause the problems you were trying to prevent. The following sequence of events often applies: low mud weights -> borehole instability -> borehole enlargement & caving -> hole cleaning problems -> pack-off -> ECD surges -> tensile fracturing -> mud losses. If mud weight needs to be lowered because of excessive mud losses, lower it in steps by 0.2 – 0.3 ppg. Lowering the mud weight by 0.5+ ppg may shock the formation, leading to instability. Update your pore pressure / fracture gradient / borehole stability / mud weight model while drilling, using log information from MWD and PWD tools, software tools such as Drillworks PREDICT and RockPro, real-time pore pressure measurements, and the full analysis capabilities of the new RTOC. STUCK PIPE If overpull or setdown is experienced during movement of the drillstring (as assessed e.g. using drag charts), then there is a potential stuck pipe mechanism acting in the well, which results in more resistance to string movement than would be expected from normal hole drag alone. Use the drag charts to assess the true nature of the problem (e.g. cuttings beds, borehole instability, ledges etc.) and to formulate an appropriate response. The wrong reaction can make the problem worse. Always move the string opposite to its original direction when an obstruction is encountered; e.g. if overpull is experienced while tripping out, go back down and circulate the hole clean before trying again. DRILLING FLUIDS Minimize adverse mud-shale interactions by using SBMs/OBMs, or high-performance WBMs with special additives to prevent mud pressure penetration and clay swelling. Prevent barite sag by following barite sag guidelines (see below). Monitor static mud weights using PWD on trips to assess the extent of barite sag in the well and the need for remedial actions. Measures to prevent instability from excessive annular pressure fluctuations (swab / surge) are (1) maintain optimum mud rheology & solids control; (2) prevent excessive / progressive gels; (3) accelerate / decelerate mud pumps slowly; (4) optimize trip speeds for drillstring and casing using a reliable swab/surge simulation program; (5) use muds that prevent bitballing, accretion and pack-off; (6) use PWD technology to monitor transient annular pressures; (7) do not down-ream on connections; (8) treat the borehole gently. When encountering fractured/faulted/rubble formations that give rise to large rock fragments which are difficult to clean out of the hole, try the following measures: (1) lower fluid loss as much as practicable; (2) improve the bridging capability of the mud by adding LCMs (e.g. fine fibers, graphites etc.); (3) apply a resin/monomer formation strengthening treatment to the troublesome zone; (4) switch to a dispersed WBM system with better fracture healing and sealing ability; (5) case off the problem. Hole Cleaning Best Practices Manual Rev 0

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1.1.1

Modeling

One of the key areas of planning a high angle well is modeling. This tends to be an iterative process that must balance the hydraulics, ECD and T&D results. The following sections present general issues related to modeling these parameters, and in particular their impact on hole cleaning.

1.1.1.1

Hydraulics Modeling

The aim of hydraulics modeling (software to be used includes Shell’s IDM-based EzClean & Modrill as well as supplier software such as M-I’s Virtual Hydraulics) is to determine the flowrates that will be available for hole cleaning in each critical interval of the well, given the downhole and surface equipment to be used. The following should be considered when modeling hydraulics: •

The hydraulics model being used should be calibrated with actual well data

•

Realistic input parameters should be used:

○ If a particular pressure drop is required across the bit, this value will need to be used. Otherwise the bit should be nozzled with a realistic TFA (may change based on the use of PDC or tri-cone).

○ The pressure drop across BHA components is often underestimated. Conservative estimates should be used (e.g. 750 -1200 psi for RSS or conventional steerable BHA, 400 – 600 for rotary BHA). Note that pressure drop specifications for directional drilling equipment are generally based on pumping water through the tools, and losses with mud will be significantly more. ○

The hydraulics model should take into account the connection ID of drillstring being used. In a long section, this may result in significant pressure loss depending on the connection ID.

○ The maximum SPP should be based on the rating of the pump liners that will be used. Thus, the hydraulics needs to consider the impact on flowrates with different size liners in the pumps. Note that the pressure and flowrate rating of the liners will need to include an appropriate safety factor or operating margin. ○

The rheology and mud weight used should be based on the worst case for a conservative result. For deepwater or high temperature applications, changes to the down hole rheology should be factored into the modeling.

•

Modeling should include relevant sensitivities based on changes in flowrates, mud weight and rheology, downhole and surface equipment, cuttings size and drillstring size.

An example of hydraulics modeling is shown in Figure 15. These results are based on a 15,000’ 12¼" section drilled with 10.5ppg mud. The top chart shows the SPP when circulating at TD with different drillstring options. The bottom chart shows the impact on flowrate as the section is drilled to TD, taking into account the different drillstring sizes and a range of liners in the mud pumps.


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1,100

12¼" Hydraulics Summary for Different Drillstrings Options LINER SIZES

4500.0 5" Drillpipe 6 5/8" Drillpipe 1,000 4000.0

5 7/8 Drillpipe 7"

5 1/2" Drillpipe

Flowrate SPP (gpm) at pump limits (psi)

5" Drillpipe 5 1/2" Drillpipe 3500.0 900

6-1/2"

7"

5 7/8" Drillpipe

3000.0

6-1/4"

800

6-1/2"

2500.0

6"

6 5/8" Drillpipe

700 Assumptions : 2000.0

7"

6" liner limited to 770 gpm flowrate (90spm), and/or 3736 psi 6-1/2" liner limited to 900 gpm flowrate (90spm), and/or 3184 psi 7" liner limited to 1045 gpm flowrate (90spm), and/or 2744 psi Mud Rheology - 52 / 37 / 28 / 22 / 16 / 10, MW - 10.5ppg BHA pressure drop = 800 psi (motor / MWD)

1500.0 600 600 2000

650 4000

700 6000

750

6-1/2"

800 8000 Flowrate (gpm) 10000

850

900 12000

950 14000

7"

1000 16000

Depth (ft MD)


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Figure 15


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1.1.1.1

ECD Modeling

The aim of ECD modeling (software to be used includes Shell’s IDM-based EzClean & Modrill as well as supplier software such as M-I’s Virtual Hydraulics) is to determine the ECD’s that will be seen in the openhole interval of each critical section of the well. This includes ECD’s while drilling, as well as during circulating and cementing casing and liners. The following should be considered when modeling ECD: •

The ECD model being used should be calibrated with actual PWD data when possible.

•

The ECD model should show the calculated ECD across the entire openhole interval, not just at TD (i.e. what the PWD would show). In certain applications, the ECD may actually be higher further up the hole.

•

Ensure that connections OD’s are included as they will impact ECD. Additionally, if not accounted for with the model, some incremental ECD may need to be allowed for centralizers or other tools on the OD of the string, and cuttings loading in the hole.

•

The rheology and mud weight used should be based on the worst case for a conservative result. For deepwater or high temperature applications, changes to the down hole rheology should be factored into the modeling.

•

Modeling should include relevant sensitivities based on changes in flowrates, mud weight and rheology, and drillstring size.

•

Drillstring rotation will impact the ECD and should be included in the modeling (SECTION 6.1.4).

1.1.1.1

T&D Modeling

The T&D in each critical hole section should be modeled (software to be used includes Shell’s IDM-based Surge) to determine the expected loads on the drillstring. The following should be considered when modeling T&D:

•

Separate friction factors should be used for slack-off, pick-up and torque. The friction factors used should be calibrated with offset well data if possible.

•

The lowest expected mud weight should be used in calculations as this will be the more conservative case for T&D (i.e. less buoyancy).

•

As a minimum, the following should be analyzed in each critical interval: ○

The change in slack-off, rotating and pick-up weight as the section is drilled.

○ The increase in off-bottom torque as the section is drilled. Ensure that the additional torque from the bit is added to the off-bottom torque to calculate the maximum torque seen on surface when drilling on-bottom. ○

An analysis of the potential buckling, particularly if sliding will be required.

○ If a tapered string is to be run, calculate the tension and torque at crossover points in the string.


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1.1.1.1

Hole Cleaning Modeling

In recent years, there has been an effort to develop and utilize theoretical hole cleaning models to identify potential hole cleaning problems and optimize solutions. The basis for most models has been theoretical formulas and empirical data gathered from lab testing using flow loops. Although these models may provide some useful data, caution is recommended in using them in isolation for planning and monitoring of deep, large diameter hole sections (refer to the limitations below). Any model that is used, needs to be used as part of an entire Hole Condition Monitoring (HCM) process. The main advantage of the HCM techniques presented in SECTION 10.2, is that the actual wellbore conditions are being used to tell the story of what is happening down hole (i.e. all assumptions have been removed).

“Do not use Hole Cleaning Models in Isolation” The following are some general limitations seen with most of the hole cleaning models within the industry:

•

In general, the basis for the models are theoretical formulas and empirical data from lab testing using flow loops. There are many assumptions made within the theoretical formulas that simplify what is actually happening down the hole (i.e. weight / size of cuttings, hole diameter, fluid flow etc).

•

The flow loop testing itself can introduce errors into the models, with unrealistic parameters.

○ Flow loop testing generally involves small annular clearances (5” pipe in 8” hole), with the results for this size combination then scaled up (extrapolated) for larger hole sizes in the model. In practice, actual wellbore data clearly shows that the hole cleaning regime is entirely different in 12¼" hole compared to 8½" hole. Thus hole cleaning models tend to do a much better job predicting results in smaller hole sizes than they do in larger hole sizes.

○ The length of the flow loops are relatively short. Again, this involves the assumption that results from the flow loop can be scaled up (extrapolated) from a ±50’ flow loop, to a 15000’ hole section. It is difficult to see how true cuttings transport can be accurately represented in such as short distance (SECTION 3.2.2)

○ The pipe rpm is generally limited due to the mechanical setup of the flow loop, and often will never exceed 100rpm in the testing. Results are then scaled up (extrapolated) for the higher pipe rpm’s seen in practice. This fact, in combination with scaling up the hole size, is why hole cleaning models do not show the step change in rpm seen in larger hole sizes, as discussed in SECTION 3.6.1.

○ The outer tube representing the borehole is generally a smooth tube of a constant diameter. In practice, cuttings will need to deal with changes in the hole diameter and filtercake as they travel up the wellbore.

○ Pipe used in the flow loop is generally fixed and constrained and does not include tool joints. In practice, pipe is not constrained in the hole, and the tool joints will impact the formation of cuttings beds.

○ Simulated cuttings used in the flow loop are of a particular shape, size, and density. In practices, the cuttings will be an ever changing variable with changes in drilling parameters, geology, mud, etc.

•

When the model is used in both a planning and operational phase, a range of assumptions need to be made (cuttings size / weight, mud rheology, hole diameter, ROP, etc). Not only are there a large number of assumptions, but many cannot be


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verified in practice. Although it can be argued that small changes in the assumptions will have a limited impact on the hole cleaning results, the problem comes when the assumptions are significantly wrong (e.g. hole washed out significantly, etc).

•

Many of the models provide results based on how difficult it will be to trip out of the hole with a calculated cuttings bed height. This relies on knowing the flow-by area of the bit, which is difficult to define with many bit designs (e.g. spiral blades and gauge). Additionally, this calculation may not consider other BHA components which have limited flow-by area (e.g. MWD stabilizers, RSS pads, etc)

•

Any model, whether it be hydraulics, T&D or hole cleaning, must be calibrated with actual wellbore data to be considered reliable. Hole cleaning models are very difficult to calibrate as their output results cannot be directly confirmed with wellbore data. For example, there is no method for actually measuring the cuttings bed height downhole. Therefore the calibration of hole cleaning models with actual well data tends to be subjective and implied.

EzClean For SEPCo applications, Shell’s IDM-based EzClean software or equivalent supplier software should be used. Within the IDM suite of Well Engineering software, the EzClean program models fluid hydraulics and the transport of drilled cuttings and associated circulating pressure profiles throughout the wellbore. This allows the optimization of fluid properties, and drilling and circulating conditions for effective hole cleaning. Results can be generated for the separate cases of rotary drilling, sliding and circulating operations. EzClean has been developed from a number of earlier programs and laboratory tests, and offers several advantages for the user. It is integrated with the rest of the IDM portfolio, and so incorporates the full string, wellbore trajectory and fluid modeling as the other IDM programs. This includes fluid rheology and density dependence on pressure and temperature, based on the circulating temperature profile downhole. Drill pipe rotation and eccentricity of the pipe in the wellbore are also modeled. Calculation of the equivalent circulating density (ECD) along the wellbore can be specified with or without effect of cuttings loading in the fluid column. There is some overlap in the functionality of EzClean and IDM-Modrill. EzClean models well hydraulics in relation to hole cleaning. Modrill models well hydraulics in relation to its effect on the overall mechanical stresses on the workstring, torque/drag, etc. However, the basic hydraulics algorithms in the two applications are identical (including cuttings). One significant difference is that EzClean models only drillstrings – the hydraulics of casing/liner strings or coiled tubing must be determined using Modrill. Beyond the basic prediction of cuttings beds, EzClean also aims to provide more information on which to base real operational decisions. This includes a quantitative estimate of the likelihood of stuck pipe problems while tripping pipe in or out of the hole, due to pack-off from the residual solids that are left after drilling or circulating. This can highlight depths where special hole cleaning operations or extended circulation may be required. In turn, operations maps indicate the best combinations of flow rate and tripping speed when backreaming or pumping out of hole. Sensitivity plots show the general impact of changes in a variety of key input parameters.


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1

DRILLING FLUIDS

The drilling fluid has both function and properties related to hole cleaning. The main hole cleaning functions of the drilling fluid include: •

Removal of cuttings, cavings and other solids from the wellbore

•

Suspension of the solids when the drilling fluid is not being circulated

The main properties of the drilling fluid that will impact hole cleaning include: •

Density

•

Rheology

•

Gel strength / Thixotropy

•

SWR (Synthetic / Water ratio) for OBM/SBM

•

Low Gravity Solids

•

Inhibition

•

Barite Sag

The following section details some general guidelines that need to be considered in the selection of an optimal drilling fluid for a particular interval of the well, followed in SECTION 5.2 by a more detailed discussion of the fluid properties and their impact on hole cleaning.

1.1

MUD SELECTION

The importance of good mud system design for high angle wells cannot be over-stated. The selection of the optimal mud system for the well is often a difficult task, which must consider many factors including technical, logistical and commercial issues. In general, drilling fluid systems can be categorized as seawater (SW), Water Base Mud (WBM), Oil Base Mud (OBM, including Low-Tox OBM (LTOBM) and Diesel OBM (DOBM)), and Synthetic Base Mud (SBM, based either on olefins or esters). There are many different mud types that fall under these categories. Each system will have its own distinct properties and advantages and disadvantages. As well as the technical selection issues listed in the following table, the final selection will also be based on issues such as the cost of the fluid, local environmental legislation, and disposal logistics.


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Although there is a time and place for any given mud system, it is generally the case that a high quality mud system will be more cost effective than a cheaper mud system for a high angle well (at least for the high angle section of an ERD well). The selection of a drilling fluid should not be based on a cost/bbl basis, but rather on an overall well cost basis (i.e. consider the impact of the mud on the overall performance and cost of the well). Improved drilling performance can be expected from a properly designed premium mud system in the following ways:

•

Improved inhibition resulting in discrete intact cuttings, gauge hole, and more efficient cuttings transport (i.e. better hole cleaning).

•

Improved weight transfer to bit and bit performance (ROP) due to the absence of bit-balling and lower friction factors.

•

Trouble free tripping and casing runs.

It goes without saying, that a poorly selected drilling fluid that results in hole problems (even minor ones) will have a significant impact on a high angle well.

“Do not take shortcuts with the mud selection” Critical technical issues that must be considered when selecting drilling fluids are shown in the following table.

ISSUE HOLE CLEANING CAPABILITY

IMPACT ON DRILLING FLUIDS SELECTION For large diameter surface holes that are drilling soft dispersive formations, and where hole gauge is not critical, consider the use of an uninhibited / dispersive WBM to allow the hole to be cleaned with dispersion rather than mechanical removal of the cuttings from the hole. When drilling more consolidated non-dispersive formations, high performance WBM or SBM will generally provide improve results over uninhibited / dispersive WBM. This is mainly due to improved inhibition and gauge hole. Other critical parameters for hole cleaning include the following: •

The solids loading of the mud system. In particular, the build up of low gravity and colloidal solids will impact the hole cleaning effectiveness of the system.

•

A shear thinning fluid with adequate low-end rheology (3 and 6 rpm readings) to support cuttings in the low shear environment of the annulus. The 6 rpm reading should target 1 – 1.2 x hole size.

•

If in a pressure or ECD limited application, the rheology should be optimized to allow the maximum flowrates to be used.

•

The inhibition of the mud will be important to allow the cuttings to remain intact and removed from the hole as easily as possible.


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WELLBORE STABILITY

Wellbore stability may be a function of the reactivity of the formations (chemical), the in-situ stresses (mechanical), or a combination of both. The mud system needs to directly address these wellbore stability issues through mud weight and inhibition. Note that the mud weight and the inhibitive performance of the drilling fluid are often closely related.

If a mud allows for mud pressure penetration and clay swelling

(i.e. allows for chemical instability to occur), then mud weight will have to be increased progressively in time to offset this chemical instability with improved mechanical stability. On average, lower average mud weight can be maintained with muds that prevent mud pressure penetration and inhibit clay swelling

TIME DEPENDENCY OF FORMATIONS

On high angle wells, hole sections are generally open much longer and must be tripped through more often than on conventional wells. Time dependency and shale hydration become critical issues. An invert emulsion (e.g. OBM or SBM) system keeps the water away from the rock and virtually eliminates the hydration process if the mud’s invert salinity (in particular its water activity) is designed properly for the formations being drilled.

WELL CONTROL

This is not only a mud weight issue. Factors such as gel strength properties (which affect likelihood of swabbing or surging if the mud gels up when static), solubility of gas into the mud, barite sag and ability to use high flowrates with increased mud weights must all be considered.

LUBRICITY

In general, SBM will provide lower friction factors than a WBM. Ester-based muds appear to have the lowest friction factors of any of the SBM systems. Lubricants are available for WBM’s and have met with varying degrees of success. In a high angle well, lubricity is not only a function of the “slickness” of the mud system, but also directly related to hole cleaning. The cleaner the high angle wellbore, the lower the friction factors that will be seen. Note also that “slicking” up a mud system by adding a lubricant may not have any effect if high friction has its origin in hole cleaning problems.

DIFFERENTIAL STICKING

Differential Sticking performance of a mud system will be a key consideration when drilling through permeable formations. Generally, the increasing angles associated with high angle wells lead to increased mud weight, while the reservoir section is generally much longer due to the high angle of the wellbore. Further, high angle wells may be drilled through under-pressured or pressure-depleted formation. For shallow wells, this is a critical issue, given that there is less capability to accommodate further increases in torque or drag, and there is less available jarring capability to deal with stuck pipe. Differential sticking can act on BHA’s in degrees. Just because an assembly is not differentially stuck, it does not mean that there is not a degree of differential sticking acting on the assembly. Differential sticking forces act to drive the friction factors in the well up. Selecting the proper fluid and/or fluid additives for fluid loss control and filter cake properties (toughness, thickness, lubricity etc.) to minimize the effects of differential sticking is a key issue in high angle wells.


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BIT BALLING

This affects both drilling and tripping. The mud system’s anti-balling performance has a dramatic effect on bit and BHA selection, bit hydraulics, rig flowrate capabilities, tripping capability, well control (swabbing), and hole cleaning risks. ROP enhancers have been successfully used for the prevention and mitigation of bit balling. These products seem to preferentially attach themselves to steel and have eliminated bit balling in a number of examples. Use of SBM/OBM is the most effective way to deal with bit balling problems. Balling is an important issue on high angle wells, because bit hydraulics is often compromised (low HIS) due to limited rig capabilities. Balling should not only be thought of as the commonly envisaged “global balling”, but also the “micro-balling” that occurs at the cutter tips.

ECD AND MUD LOSSES

ECD’s are often greatly magnified on high angle wells, both while drilling and while running and circulating casing. As high angle wells have grown longer and shallower, ECD’s have begun to play a limiting role in many programs. In critical applications, the mud system may need to be specifically design around managing ECD’s.

BARITE SAG

Barite sag is an important design consideration for wellbore stability, well control and ECD management. The mud system needs to be design with adequate ultra-low rheology (< 3 rpm), which requires the use of specialized mud chemicals and testing equipment (see barite sag best practices).


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1.1

MUD PROPERTIES

Having adequate flowrate and rpm are the key parameters in good hole cleaning. Optimizing the mud properties will have a limited impact on improving hole cleaning performance. However, saying this, getting the mud properties wrong from the start will result in significant hole cleaning difficulties. Basically, it will be difficult to even get on the “playing field”, and allow flowrate and rpm to do their job, unless the mud properties are right.

“Getting the mud properties right puts you on the playing field” The following sections provide some general guidelines, as specific mud properties will need to be different with each mud type and hole section. It should be noted that sweeps are not recommended in high angle wellbores (refer to SECTION 10.3.3). Apart from not being overly effective, the other main reason for not pumping sweeps is that they tend to make the control of the mud properties listed below that much more difficult. Note that sweeps are recommended for cleaning out large diameter near-vertical holes.

1.1.1

Mud Weight

For hole cleaning, higher or lower mud weights may be preferred, depending on the specific application. The following mud weight related issues should be considered with respect to their impact on hole cleaning (see also SECTION 4.3.3): •

Higher mud weights may improve hole cleaning marginally with additional buoyancy force on the cuttings (i.e. improved carrying capacity of the mud).

•

Impact on wellbore stability. Wellbore stability may be an issue if the mud weight is decreased (in-situ stresses), or increased (natural fractures, ECD loading). Once initiated, wellbore stability is difficult to control and will result in additional hole cleaning difficulties.

•

Impact on Stand Pipe Pressure. Higher weights will increase the pressure drop through the circulating system, which may result in lower flowrates in a pressure limited application.

•

Impact on ECD. Higher weights will result in higher ECD’s. This may lead to wellbore instability or losses, both of which will impact the hole cleaning.


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1.1.1

Rheology

Rheology basically refers to the viscosity of the drilling fluid at different flowrates. The rheology is measured due to the fact that drilling muds are generally Non-Newtonian fluids, and their viscosity changes as the flowrate changes. This viscosity change is best illustrated for a “drilling system” by the graph shown in Figure 16 below. Figure 16 Rheology is measured using a Fann Viscometer. This instrument simulates the flow properties of the drilling fluid under downhole shear rate conditions. The results are normally measured in the standard format of 600, 300, 200, 100, 6, and 3 rpm readings. From these readings the PV (plastic viscosity) and the YP (yield point) of the mud is obtained. •

PV = 600rpm – 300rpm

•

YP = 300rpm – PV = 2 x 300 rpm – 600 rpm

•

YZ = 2 x 3 rpm – 6 rpm

The PV is a measure of the force required to keep the drilling fluid moving once it has started to flow. It is representative of the muds behavior in high shear areas such as inside the drillpipe and at the bit nozzles (i.e. turbulent). The PV will depend on the size, shape, and number of solids in the mud, and an increase in PV can point to a build up of solids in the mud (i.e. fines). The YP is a measure of the force required to get the drilling fluid to start flowing from stationary, and is to a large extent determined by the mutual electro-static interactions between particles in the mud. It is indicative of the low shear (i.e. laminar Hole Cleaning Best Practices Manual Rev 0

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flow) properties of the mud and represents the behavior of the mud in areas such as the annulus. However, it should be noted that YP is no longer as relevant a measure of low-end rheology with the shear thinning drilling fluids that are generally used for modern high angle wells (i.e. 3 and 6 rpm readings and the yield stress YZ defined by them are more relevant). Figure 17 below shows the PV and YP on a shearShear YP PV Stress Strain

Figure 17 Regardless of the mud type used, the overall objective is to maintain a pumpable fluid with low-end rheologies that are high enough to keep the cuttings moving out of the hole. Although the work on mud rheologies is ever changing, the use of 6 rpm or YZ readings as a primary indicator of hole cleaning capability, and maintaining a low plastic viscosity (PV) for pumpability, are widely accepted. For WBM systems, maintaining a 6 rpm reading 1 - 1.2 times the hole size (in inches) has proven very effective in high angle h ole applications, provided there are no restrictions on ECD. For SBM systems, temperature and pressure effects must be taken into account. This is best done by looking at rheology measurements done at actual well temperature and pressure conditions (e.g. using a Fann 70 or equivalent viscometer). In hole sections where ECD becomes the main priority, the rheology may need to be run as thin as possible, while still allowing enough support for the Barite in the system (i.e. prevent barite sag). This may compromise hole cleaning. However, if borehole instability or losses are initiated, hole cleaning will become much more difficult.


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1.1.1

Gel Strength

Gel strengths are basically used to measure the force required to restart the drilling fluid moving after it has been stationary for a period of time. •

The initial gel strength is measured after 0 seconds at rest.

•

The 10 second gel strength is measured after 10 seconds at rest, and indicates how well the mud will hold cuttings in suspension

•

The 10 minute gel strength is measured after 10 minutes at rest, and indicates how difficult it is to break circulation.

In general, gel strengths should be non-progressive (i.e. little difference between 10 and 30 minute gels) but adequate to suspend cuttings (e.g. 10 sec gel 10-18 lbs/100ft2; 10 min and 30 min gels: 16-28 lbs/100ft2). Although higher gel strengths will assist hole cleaning by preventing cuttings from settling and reducing the tendency to avalanche, they may also result in swab / surge problems or ECD spikes when breaking circulation.

1.1.1

SWR

The Synthetic Water Ratio (SWR) plays an important part in hole cleaning and drilling performance in high angle wells. It is common for vertical applications to run a system with a high water content (e.g. SWR = 60:40) for reduced mud cost and increased viscosity. However, a thinner mud, with lower PV’s, is necessary in high angle wells (for improved annular cleaning, improved flow rates, and reduced ECD’s). This necessitates the use of higher SWR levels of e.g. 80:20 as the invert emulsion droplets tends to act like low gravity solids raising the PV.

1.1.2

Low Gravity Solids

Drilled fines (or LGS) are usually the most significant contaminant in the mud system. Adverse effects caused by drilled fines account for a major portion of the drilling fluids maintenance cost and effort. These effects include: •

Difficulty in maintaining rheological properties

•

Reduced ROP

•

Increased wear on downhole and surface components

•

Increased risk of differential sticking (i.e. thicker filter cake)

•

Increased circulating pressure loss

•

More difficult to remove cuttings from the bottom of the hole

For hole cleaning, the main impact of high solids content is the effect on the circulating pressures of the increased PV. Good solids control, taking solids out of the mud flow while they are large, is the best way to prevent LGS build-up. Premium solids control equipment from the shakers through to the centrifuges will be critical in keeping the mud system as clean as possible on a high angle well. In particular, an adequate number of high quality shale shakers, fitted with as fine a mesh screen Hole Cleaning Best Practices Manual Rev 0

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as possible, should be run from the start of the interval. Getting as many solids out of the system as soon as possible will help to prevent the build up of LGS and colloidal solids in mud system (See Solids Control Best Practices). Additionally, any chemicals used (e.g viscosifying agents, salt) should be higher quality products, as the cheaper generic brands tend to include contaminants that will impact the mud PV. The ultimate solution to reducing LGS is by thinning and dilution.

1.1.1

Inhibition

If the mud provides inadequate inhibition of clay swelling, hole cleaning becomes very difficult as there is a mix of dispersion and mechanical removal of cuttings. What tends to result is a “paste” on the bottom of the hole that will not disperse, but cannot be removed without mechanical agitation from the bit (i.e. backreaming). This results in very poor hole cleaning and is often seen with poor quality WBM systems (minimal inhibition) in high angle wells. Some indications of this problem include:

•

Poor cuttings returns observed over the shakers when drilling with adequate flowrate and rpm. Basically seeing a small amount of unconsolidated material coming over the shakers. If the system inhibition is adequate, and hole cleaning parameters are good, there should generally be a large volume of firm, dry, distinct cuttings coming over the shakers.

•

Balling of bit and BHA components.

•

Tight hole and swabbing when tripping out of the hole.

•

Little or no additional cuttings seen with cleanup cycles.

•

Large “cakes” of cuttings returning when backreaming.

Additionally, poor shale inhibition and chemical stability will complicate hole cleaning by causing wellbore enlargement and additional cuttings loading.

1.1.1

Barite Sag

Barite sag may become a drilling problem when mud weights are high (> 12.0 ppg), hole deviation becomes significant (angle > 30o) and the allowable mud weight range is tight. Barite sag is caused by operational practices that take place at low shear rates (e.g. slow pump rates, tripping, logging, slow fracture breathing, etc). When the low shear viscosity in the mud is no longer sufficient to support the barite it drops out and settles. Treatments for barite sag, using organophilic clays and/or polymeric additives, tend to target the ultra-low rheology range (< 3rpm). Mud treatment recommendations to avoid sag must be strictly adhered to. In addition, operating practices must be planned around avoiding sag as much as possible. Brief barite sag prevention guidelines are given below. For more detailed information, see Barite Sag Best Practices.


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What is Barite Sag

BARITE SAG GUIDELINES

Sag is the undesirable variation in drilling fluid density due to downhole settling of weighting material, mostly in muds at densities > 12 ppg. It is a serious cause of drilling problems on HPHT wells and wells at higher deviation ( > 30o), particularly ERD wells. There are two forms of sag: static sag or settling which correlates with gel strength of the mud, and dynamic sag which correlates with (ultra) low-end rheology of the mud. Sag may be triggered by: (1) poor maintenance of the mud with rheology modifiers to prevent sag; (2) mud contamination that affects the mud’s barite suspension capabilities; (3) long periods of low shear operations breaking gel strengths, i.e. slow circulation ( annular velocities < 50 ft/min), slow pipe rotation and pipe reciprocation, mud loss or gains (fracture breathing) etc. Note that barite sag may become self-sustained in wells at high deviation under static conditions: barite sag -> density contrast in well (dense mud on low side of hole, light mud floating on top) -> differential flow (barite slumping down, light mud moving up) -> breaking of gels -> reduced barite suspension -> more barite sag. Sag is identified (1) while circulating BU by getting light mud followed by a slug of heavy mud to surface (do not confuse the signatures of sag with heavy trip slugs coming to surface); (2) PWD readings of static mud weight while tripping (i.e. light mud/reduced hydrostatic on top of heavy mud/increased hydrostatic). Other indicators are unusually high stand-pipe pressures, high ECD’s & induced mud loss, high torque & drag, unexpected kicks and BHS problems. Well Planning & Execution If you have identified that your drilling operation may suffer or is suffering from sag (i.e. your well employs muds > 12 ppg and is a HPHT well or a well at deviation > 30o) do the following:

1.

Raise the awareness of the rig crews to sag problems using these guidelines and demonstrations of sag dynamics with the ZAG tube (please contact the Fluids Team);

2.

Make sure the mud formulation coming from the mud plant guarantees sag control; it may be necessary to build a mud from scratch to achieve this. Verify sag tendency using large-scale flow-loop tests in the lab. Treatment with rheology modifiers to control sag should be strictly adhered to (contact the Fluids Team for the latest advice, which will vary for each SBM – for Novaplus SBM, treatment should be 3:1 VG-Plus : VG-Supreme, at a 3-4 ppb total concentration ).

3.

Use special sag monitoring & maintenance procedures. For monitoring, use the VST (viscometer sag test) and RBC measurements. Chandler and other ultra low-shear viscosity measurements have proven to be less reliable indicators of sag tendency. Optimum mud properties for sag control: (1) 10’, 30’ Gels: 16-28 lb/100ft2, flat; (2) YZ (2*3rpm – 6 rpm): 8 – 15 lb/100ft2; (3) Non-HPHT wells: VST < 0.5, HPHT wells: VST < 1.0; (4) RBC < 1.0; (5) ES > 600.

4.

Avoid / minimize drilling operations at annular flow rates < 100 ft/min and drillpipe rotation < 50 rpm. Understand the implications of an extended period of logging on sagging tendency.

5.

Do not go overboard in thinning back the mud to achieve a low YP prior to running casing – the mud may start to sag, increasing the chance of fracturing and losses. Instead, pump low-viscosity mud ahead of the cement spacer to aid in mud displacement and improve cement bonding.

Remedying Sag If excessive density swings are observed, stop drilling and condition the fluid with appropriate rheology modifiers (see above). Circulate until the density stabilizes + 1.5 times BU before resuming. While tripping, pump up PWD readings on static mud weight to evaluate sag tendency. If barite sag is observed (i.e. light mud/reduced hydrostatic on top of heavy mud/increased hydrostatic), DO NOT stage in the section of hole that contains the lighter, sagged out mud – staging (i.e. replacing light mud light mud by normally weighted mud) may increase the hydrostatic head on bottom and lead to mud losses. Start staging at the point in the well where the total hydrostatic head of the sagging, variable density mud equals the hydrostatic head of the mud with constant density.


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1

ECD MANAGEMENT

1.1

ECD FUNDAMENTALS

Hole cleaning and ECD management cannot be treated as separate issues on a high angle well, particularly in smaller hole sizes, and where mud weight margins are tight. The following section presents some basic theory on ECD, and why it is a significant issue on high angle wells.

1.1.1

What is ECD?

Equivalent Circulating Density (ECD) can be defined as:

“the additional “mud weight” seen by the hole, due to the circulating pressure losses of the fluid in the annulus, or surge pressures” The following formula is used to calculate ECD: Annulus ∆ P (psi) ECD (ppg) =

MW (ppg)

+

--------------------0.052 x TVD (ft)

As can be seen by the formula above, ECD at a particular depth (TVD) is a function of the pressure drop in the annulus down to that depth (MD). Thus ECD is affected by the following factors: •

Length of annulus or well

•

Annular clearances

•

Flowrate

•

Mud properties

•

Rotation of the pipe

•

Backpressure through surface return lines

•

Drill cuttings load (supported by the mud)

•

Surge (and swab) pressures


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Surge pressures are often overlooked in planning for ECD’s. They result from the downward movement of the drillstring or casing acting as a plunger, and causing an annular pressure spike or surge. Figure 18 shows an example of down reaming from the MC766#1 Princess well. This example highlights the damaging effect that surge pressures can have on the openhole formations.

16.36 ppg surge

ECD +1.1ppg SMWD ECD: 15.9 ppg

Static MW Downhole 14.75 ppg

16.37 ppg surge

Figure 18 Swab pressures are seen when pulling out of the hole, and act in the opposite direction to surge pressures. Although they counteract ECD’s, they can also be damaging to a wellbore, as they can contribute to the fatigue stresses and borehole collapse. The magnitude of swab and surge pressures will depend on the following: •

Pump rate and drillstring rpm

•

Speed of the pipe movement up or down

•

Viscosity of the mud

•

Flow-by area around the BHA or casing

•

For a floater, the rig heave also needs to be considered


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Apr 2003


1.1.1

What are the Effects of ECD?

So how does ECD impact a high angle well, and hole cleaning in particular:

•

High ECD’s increase the risk of lost circulation. This applies to both drilling and casing / liner running operations, where annular clearances are small or mud weight margins are tight. Further, reservoir damage can be a side effect if ECD's are not minimized.

•

Wellbore instability can be caused by the constant flexing and relaxing of the wellbore from pressure fluctuations caused by cycling the pumps or swab / surge. This is particularly the case if the formation is brittle (such as coals or brittle shales). Effectively, the wellbore is failed through fatigue, as would a paper clip when bent back and forth. A paper clip can be bent back and forth once or twice without breaking, even if it is bent quite severely. However, it will break due to fatigue failure if it is bent enough times. The time to failure is dependent upon how severe the bending is, how many times it is bent, and the strength and elasticity of the material. It is the same with the wellbore and ECD fluctuations. The wellbore can eventually fail, depending upon the lithology, and the size and frequency of ECD fluctuations.

•

Efficient hole cleaning will be compromised if losses or wellbore instability result from excessive or fluctuating ECD’s. As shown in Figure 14, what results is a “vicious cycle” that is often difficult or impossible to break out of. This is mainly seen when operating with narrow wellbore stability, mud weight, and fracture gradient margins. Even with only two of the problems occurring, the situation is almost beyond control. Every effort should be made in the planning phase to avoid these narrow margin scenarios.

•

The reduction in flowrate may also have a negative impact on torque and drag (increased cuttings bed height), and drilling performance (less than ideal bit and motor performance at reduced flowrates).

•

Casing collapse can be initiated by ECD’s (surge pressures) while running floated casing strings on long, deep high angle wells. Casing collapse calculations should account for the increased annular pressure due to ECD’s while running casing, rather than just for a static on-bottom scenario. Long mud-over-air casing flotation jobs have experienced collapsed casing due to the running ECD’s alone.

•

Surge pressure creates a “piston force” that behaves like drag. This can be critical for marginal casing runs.


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1.1.1

Why is ECD a Concern for High Angle Wells?

ECD’s are generally a more significant issue on high angle wells than for conventional wells. This is due to the following:

• •

Long measured depth intervals relative to the vertical depths (refer to Figure 19) High angle wells are generally shallow by their nature. The shallow-type high angle wells are particularly prone to ECD problems as their formations are often so shallow as to have little integrity.

•

High angle wells generally use larger diameter drillpipe for hydraulics or buckling reasons.

•

More aggressive parameters (flowrate and rpm) are generally required for hole cleaning.

•

Longer exposure times with long intervals on high angle wells.


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Apr 2003


than Casing iSame P ECD TVD both vertical =ER is ER @ 10.7 11.7 much ppg 10,000’ well mud greater at MD & same 350 in /350 4000’ Casing Same ECD -T than both vertical =10 is 10 wells @ 10.7 11.7 much ppg well 10,000’ well mud greater at MD & same in / psi 4000’ psi annulus ∆ 1023458769nVD MD/TVD TVD annulus wells shallow well MD MD/TVD TVD ppg shallow MD

210


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Apr 2003


Figure 19


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Apr 2003


1.1.1

ECD and Pipe Rotation

Operational data supports the literature that proposes a relationship between ECD’s and pipe rotation in small hole sizes (≤ 8½” hole). Refer to EXAMPLE 11.5. The original thinking was that this was due to cuttings being pulled up into the flowpath when rotation commenced (i.e. improved hole cleaning). Although this may contribute to some increase in ECD, the same relationship is also seen when there are no cuttings in the hole (i.e. prior to drilling out). Another theory is that the fluid has to travel an increased distance to surface due to a ‘spiraling’ flow path when the pipe is rotated (see Figure 20). As the annular clearances are decreased, the ECD impact from rotation becomes more significant. It is important that hydraulics models used to calculate ECD’s include the effects of rotation. This can be critical if ECD’s margins are tight. As such, hole cleaning parameters (flowrate and pipe RPM) may have to be compromised if ECD’s are critical, thus reducing hole cleaning efficiency and increasing drilling time.

High speed pipe rotation will cause fluid to spiral as it moves up the hole. This increases the distance that the fluid must travel, and therefore increases ECD’s. This occurs mainly in small hole sizes (i.e. 8½” or less). Hydraulics models will often fail to account for rotation, and will therefore underestimate ECD’s in small hole sizes


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Apr 2003


Figure 20


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Apr 2003


1.2

ECD MANAGEMENT - PLANNING

ECD’s cannot be treated as an after-thought, as just like hydraulics and buckling issues, there is little that the field personnel can do to reduce ECD problems at the rig-site, unless the well has been specifically designed with ECD minimization in mind.

“the only real solutions for reducing ECD induced problems are in the planning phase” There are numerous options to help reduce ECD’s on high angle wells. Although not applicable for all well types, the following sections provide possible solutions to reducing ECD in the planning stages of the well design.

1.2.1

Wellpath Design

The wellpath trajectory may impact ECD’s in several ways: •

The wellpath directly affects the total depth that must be drilled, and therefore impacts the annular pressures.

•

Casing points may change with different wellpaths, allowing for increased margins at the shoe.

•

May be able to program lower mud weights with a lower tangent inclination.

1.1.1

Hole Size Optimization

In SEPCo’s deepwater GOM wells there is little scope to optimize the hole sizes (i.e. maximize clearances and minimize ECD) due to the number of casing strings that are required. However, in most hole sections, drilling oversize hole is required in order to accommodate larger casing strings. Drilling oversize hole will provide improved annular clearance in the openhole interval, but it does not address the long section of cased hole, which may dominate the ECD’s effect.

1.1.2

Casing Plan

Although there is limited scope to modify the casing plan for SEPCo’s deepwater GOM wells, in general, the casing plan should be analyzed for possible alternatives which may reduce ECD’s in critical sections. Although the ECD reductions from some of the design changes below may be small, it should be remembered that it is the combination of a number of small incremental reductions in ECD that generally make the difference (i.e. there are few “big hitters”).


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1.1.2.1

Run Casing as a Liner

Running casing as a liner (instead of long string) should be considered if ECD’s are prohibitive for running (surge), circulating, and cementing that casing string, or for drilling the next hole section. For example, an intermediate casing could be run as a liner, and then tied-back (if necessary) after drilling the following hole section. This approach adds complexity to the casing plan (e.g. liner hangers, tie-backs), and should not be considered lightly. Additionally, hole cleaning in the large diameter upper hole section (above top of liner) should be considered carefully, since flowrates will probably be limited by the downhole tools. This may require the use of PBL or jet subs. Also if high torque is a significant problem in the production hole, then the liner solution may be ideal.

Under these

circumstances, Non Rotating Drillpipe Protectors (NRDPP’s) or Roller Bearing Subs may be considered to reduce drilling torque. Having the larger hole size above the liner top will allow the safe use of these torque reduction tools with a minimal impact on the ECD’s.

1.1.2.2

Use Alternative Casing Connections and Centralizers

The casing connections and/or centralizer type can have an influence on the downhole pressure while running or circulating casing. This is especially the case if any balling or cuttings accumulation occurs around these items. If ECD related problems are a concern while running or circulating casing, then alternate centralizers and/or connections should be considered. The use of flush or near-flush connections will reduce ECD’s, especially if the annular clearance between the casing strings is small. For example, if 10¾” casing is run inside 13⅜ casing, the annular clearance around the couplings is improved by 125% by using a Hydril 521 connection rather than an LTC or BTC connection (Assuming 133/8” 68 ppf casing with 10¾” casing inside).

1.1.2.3

Use different sizes of casing

When ECD is critical, lighter weight casing strings should be used where possible. For example, 9⅝” 40 ppf casing could be used instead of 9⅝” 47 ppf casing. This would increase the cased hole diameter from 8.681” to 8.835” (it would also allow 8¾” hole to be drilled instead of 8½”, if the casing is special drift). Although this might not sound like much of an improvement, the annular area around a 7” tooljoint has increased by more than 10%. Given the dominance of tooljoints in ECD impact in 8½” hole size, this may be critical. Simply using smaller casing sizes may have significant benefits. For example, rather than running 7” liner in 8½” hole, consider the use of 6⅝” liner (i.e. still allows 6” contingency hole size below). This will reduce the ECD while running and cementing the liner, often the highest ECD’s seen in the well.


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1.1.2.4

Casing Flotation and ECD

Another ECD issue that is often overlooked on high angle wells is the ECD’s created while running casing. This can be an issue when running long strings with tight clearances or floated casing. The collapse pressure may be acceptable in a static situation, but the running ECD’s may be sufficiently large to collapse the casing or breakdown the formations (losses). Dynamic surge pressures should always be factored into casing designs, particularly with flotation. When tight clearance are involved, open shoes and fluid diverter systems may be required.

1.1.3

Drilling Fluids

Drilling fluid selection and design is an important element for effective ECD management. Refer to SECTION 5.0 for further details of mud selection and properties and their impact on ECD.

1.1.4

Drillstring Design

Refer to SECTION 7.1 for further details of drillstring design. The drillstring design often plays a critical role in ECD management, especially on very shallow high angle wells where there is little formation integrity, and large OD drillpipe is required to overcome buckling problems. Regardless of the well type, the drillstring design should always be scrutinized and optimized if ECD’s are an issue. For hole sizes larger than 8½" the choice of 5”, 5½” or 5⅞” drillpipe will have minimal direct effect on ECD pressures and annular velocities. It is in 8½" and smaller hole size that ECD effects quickly become a significant issue. The relatively small annular area is very sensitive to tooljoint and tubular diameters, especially when a cuttings bed is present to further reduce annular area. If ECD’s are a problem in these smaller hole sizes, one effective approach is to use a tapered drillstring to reduce annular pressure drops. Certain projects may require three or more separate drillstring sizes (4” x 5” x 5½”) to manage ECD fluctuations, while maintaining the necessary torque, pickup and hydraulics capabilities. Tooljoint selection is also critical to ECD’s. As already mentioned, in 8½” hole, the tooljoint clearance is quite small and will have a significant effect on annular pressures. Hole sizes larger than 8½” are not as sensitive to tooljoint size. It is common to apply HWDP or larger OD drillpipe in shallow high angle wells to overcome buckling problems. Alternately, the drillpipe can be stiffened by the addition of Non Rotating Drill Pipe Protectors (NRDPP’s). If NRDPP’s or larger OD drillpipe is used, then the ECD effect should be allowed for. As a general rule-of-thumb, NRDPP’s add approximately 1 psi per protector. An option may be to use bladed drillpipe to provide stiffness while not increasing drag (as will occur with HWDP). The bladed drillpipe is significantly stiffer while not increasing ECD’s as much as the other solutions.


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1.1.5

Bit and stabilizer design

The bit and stabilizer programs for high angle wells should be designed for maximum junk slot area (JSA). This is primarily to reduce the risk of tripping problems when pulling through cuttings beds. It will also reduce the risk of swabbing when pulling through cuttings beds. Additionally, an increased JSA will also reduce the pressure surge when running or reaming into the hole. Although many engineers focus on the JSA of PDC bit designs, stabilizer designs are often overlooked (EXAMPLE 11.13). In particular, careful attention should be given to the stabilizers on steerable motors and MWD / FEWD equipment. These items often have much less JSA than the bit. If possible, avoid the use of sleeve stabilizers (common on MWD/ FEWD equipment) and replace them with integral blade or string stabilizers. This is often possible if planned in advance with the service company. Clamp-on stabilizers should be avoided, if possible.


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1.2

ECD MANAGEMENT - EXECUTION

The following sections discuss the main tools, parameters, and practices that will impact ECD management in the execution phase of the well.

1.2.1

Pressure While Drilling (PWD) Tools

Pressure While Drilling (PWD) technology is very valuable in applications where tight margins are involved. However the PWD tools have limitations which must be understood. The following issues should be considered: •

Hydraulics models should always be calibrated with actual PWD data.

•

The PWD will only show the cuttings that are up in the flow regime or those suspended in the low angle sections of the well. The PWD will not see cuttings lying on the low side of the hole until the beds build up to a critical level. At this stage it is likely that the hole is close to packing off.

•

The PWD will only show the pressure at the location of the tool. In certain applications (e.g. tapered drillstring, S-bend well), the ECD may actually be higher up the hole. Modeling should be used to analyze the ECD across the entire openhole interval.

•

PWD data is not available in real-time with the pumps off. Therefore the tool is of no value when tripping out of the hole without circulation. Circulating just for the PWD data when tripping is not only time consuming, but is unlikely to identify developing problems quickly enough, and may create an additional risk of packing off.

•

Real-Time models are now available that provide continuous ECD values, based on the actual wellbore conditions, even when the pumps are off. Although this is a valuable addition to the actual tool readings when circulating, it still does not allow tripping problems to be identified (i.e. output is from a model).

•

PWD information is complex and difficult to interpret in real-time (affected by flowrate, rpm, rheology, temp, etc.).

•

Time-based logs should be reviewed at the end of each run to determine the effectiveness of practices and analyze problems.

1.1.1

Parameters

If tight margins are anticipated, or high ECD and / or losses are seen in an interval, the following should be considered with respect to drilling parameters:

•

Prior to drilling out the shoe, it may prove beneficial to measure the magnitude of ECD variations with a range of flowrates and RPM’s (as per table below). This will provided some idea of the relative impact of each of theses variables. Note that the flowrate or rpm may dominate depending on various parameters. This exercise will also provide clean hole data which may aid in monitoring hole cleaning as the section progresses. Note that to be of value, the mud will need to be circulated for an adequate length of time to shear and warm it, and therefore obtain good quality data.

RPM / GPM Hole Cleaning Best Practices Manual Rev 0

400

500 Page 1

600 Apr 2003


0 40 80

•

If excessive ECD’s induce losses, consider stopping and curing the losses before drilling on with reduced flowrate and / or rpm. The reduced parameters are only likely to make hole cleaning and therefore ECD’s worse.

•

ROP may need to be controlled to limit the amount of cuttings being generated. Particularly if the flowrate and rpm have already been reduced (i.e. hole cleaning compromised) in order to lower the ECD, control drilling is advisable. The optimum ROP will most likely be determined by drilling off the PWD readings, maintaining the ECD below a targeted level.

• •

The mud system will need to be run as thin as possible (within barite sag limits) to minimize the annular pressure losses. Gel strengths should be as flat as possible to minimize pressure spikes when breaking circulation or moving pipe after stationary for a period of time.

1.1.1

Practices

If tight margins are anticipated, or high ECD and / or losses are seen in an interval, the following should be considered with respect to drilling practices:

•

Slide drilling results in the build-up of a cuttings dune immediately above the BHA. PWD tools have shown that ECD’s can increase sharply when pipe rotation is initiated after a long slide interval (EXAMPLE 11.5 and EXAMPLE 11.9) This is because of the instantaneous lifting of this cutting dune into the flow regime. There is also increased risk of packing off during this time. Slide intervals should be broken up with pipe rotation so as to re-distribute the cuttings more evenly up the hole.

•

As with slide drilling, backreaming can cause a significant cuttings dune to form above the BHA. If backreaming too quickly (i.e. the pipe is moving faster than the dune), this can result in ECD spikes due to packing off. Down-reaming should be avoided where possible. This practice will place the highest loads on the wellbore. Refer to SECTION 10.4.2 for detailed backreaming guidelines.

•

Some mud systems tend to gel up when left static or if allowed to cool down. If this is the case, it may be necessary to ‘stage’ into the hole when tripping back in. This requires breaking circulation at intermediate points when RIH, rather than when back on-bottom.

•

It is a good practice in high angle wells to slowly increase the flowrate from a low level to the maximum, rather than simply breaking circulation at the planned drilling flowrate. This is true, as well, for rotary speeds. Whenever the pumps or the rotary are started up, they should be brought on slowly to ensure a minimum effect on ECD and cuttings loading.

•

With very tight ECD margins, pipe rotation should be initiated first in order to start the fluid moving in the hole. This will help to break down the gel strength of the mud and minimize the surging effects as the pumps are brought on line.


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Apr 2003


•

Sweeps should be avoided as they may pick up excessive cuttings in the lower angle potions of the well. If margins are tight, this may result in an increase in the annular pressure and ECD that is sufficient to breakdown the openhole formation.

•

In deepwater applications, cuttings loading, and cold mud (thicker) in the riser needs to be considered. This may require the ROP to be controlled, or the riser to be boosted, to minimize the cuttings concentration and ECD impact.

1.1.1

Operations Summary

The table below is a summary of ECD management guidelines for various operations. This may be used as a template and expanded on for specific applications.

OPERATION /

ECD MANAGEMENT GUIDELINES

EQUIPMENT

PWD

• Ensure the tool is calibrated with correct TVD's used to calculate ECD •

Use PWD data to maximize drilling parameters while ensuring that the ECD does not exceed target values

•

Time and depth-based logs need to be annotated with operations taking place

• Logs need to be provided to the appropriate people in a timely manner •

Use PWD data to calibrate ECD models and to project ahead

•

Review time-based memory data after each run to determine the effectiveness of practices and analyze problems.

TRIPPING IN

BREAKING CIRCULATION

• Be aware of the max allowable pipe speed with pumps on and off. This should be defined at the well site based on PWD data •

Accelerate pipe slowly to avoid significant surge pressures

•

Break circulation at regular intervals on the trip in.

• The pumps should be started at as slow a rate as possible and built up to the drilling flow rate – monitor PWD when data is available. •

If high ECD is a concern (confirm on PWD), consider starting drill pipe rotation (1020rpm) before starting up the pumps.

REAMING TO BOTTOM

• This is the worst case for surging the formation – avoid where possible. •

Break circulation as above and ream down carefully to avoid surging. Where there are ECD concerns, ream using lower flow rates than while drilling.

• Reaming rate is to be determined at the well site based on ECD considerations. BACK ON-BOTTOM

•

Once on-bottom after a trip, break circulation as above

•

Do not start drilling until the PWD indicates that the ECD has returned to background levels.


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DRILLING AHEAD

MAKING CONNECTIONS

TRIPPING OUT

PUMPING SWEEPS BACKREAMING

RUNNING CASING / LINER

• Maximize ROP based on PWD and T&D readings. •

Minimize mud weight

•

Maintain low values for PV and LGS

•

Monitor PWD readings and adjust parameters accordingly

• Surge pressures are important at connections and while tripping. The ECD from circulating is combined with the surge effect. Pipe rotation will also increase ECD. •

Back-ream each stand once to remove cuttings from around the BHA.

•

Minimize speed while washing back down to bottom.

• Ensure that maximum allowable trip speeds are known in both the open and cased hole, with and without pumps on. •

Ensure the pipe is picked up slowly to limit the initial swab effect.

•

spikes and may fracture the formations. Keep a close watch on PWD and adjust parameters accordingly

•

Break circulation and at the same time the string is picked up to avoid surge pressures

•

Back-reaming should be avoided where possible

• Should be avoided as sweeps can pick up large amount of cuttings that cause pressure

• Running speeds should be based on PWD memory data recorded while drilling and tripping and the calibrated ECD model •

Lower mud rheology prior to POH with the last BHA

•

Start and stage mud pumps up slowly

“Small changes in pump pressure can have a significant impact on the well bore. Break circulation and move pipe SLOWLY”


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1

RIG EQUIPMENT

The following sections discuss various drilling rig equipment and components, and how these may impact the hole cleaning and general performance on a high angle well.

1.1

DRILLSTRING

Designing the optimum drillstring for a high angle well is a function of balancing many design parameters including hydraulic, ECD and T&D. Additionally, cost and logistics must be factored into the design as the optimum drillstring size may be different in each section of the well. On many projects, drillstring design is simply a function of modeling the drillstring that is available, and identifying the limitations of that string. However, if critical limits are approached (e.g. overpull margin, fracture gradient, etc), serious consideration must be given to changing the drillstring design if not optimum. In relation to hole cleaning, the main drillstring variable is the size, which is optimized through upfront modeling (SECTION 4.3.4).

1.2

HYDRAULICS CAPABILITY

Significant limitations for hole cleaning can result if a rig is specified that has inadequate hydraulics capability (i.e. limited flowrates). When evaluating the rig capability, the following parameters need to be evaluated to maximize the available flowrates in critical hole cleaning sections. Detailed hydraulics modeling, as discussed in SECTION 4.3.4.1, will be the basis for this evaluation.

•

The number and type of mud pumps is the key variable. The following issues related to the mud pumps should be evaluated:

○ As a general statement, it may be possible to drill a critical section with one or more mud pumps (at their limits), but the risk will be reduced and performance improved with additional pumping capacity (redundancy).

○ The pump liner sizes available, and the associated pressure and flowrate restrictions, need to be considered. Ensure that these restrictions are realistic and take into account actual drilling conditions (e.g. max spm may be 120, but pumps are never run above 100 spm, pop-off valves may be set at 80% liner rating, etc).

○ Consider the use of specific intermediate liner sizes if they provide improved flowrates (e.g. 5” and 5½" may be available, but have pressure and flowrate restrictions – 5¼" may be the optimal solution)

○ Ensure there is adequate power available to run the pumps at the planned flowrates and pressure. This may involve the actual power to the pumps themselves (e.g. 1600 hp pumps may only have 1000 hp motor), or a limitation in the total rig power system (refer to SECTION 7.4). Ensure the power implications are considered if the rig pumps are to be upgraded or an additional pump is to be added.


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○

Ask the question of how the pumps perform for an extended period under high load. High angle wells will require more from the pumps and this may require increased levels of maintenance (or preventative maintenance).

○ If there are only two rig pumps, consider tying in the cement pump as a temporary backup should one of the pumps go down. ○

•

The ability to boost the riser for deepwater wells needs to be considered.

The maximum standpipe pressure (SPP) will most likely be a function of the liners run in the mud pumps, but may be a function of the rating of the standpipe itself in some cases. Generally, 5000 psi would be considered a minimum for high angle wells, with 6000 - 7500psi preferred. Note that the swivel packing on the top drive can be a limitation on some rigs, as the reliability decreases rapidly as pressure increases (i.e may set a pressure limitation for reliability).

•

The standard drillstring size available on the rig can often be a critical limitation for flowrate when longer wells are to be drilled.

•

The solids control system may impose limitations on flowrates. This can include flowlines, shakers or other solids control equipment. If planning a high flowrate in a particular interval, ensure that all components of the surface system are capable of accepting this flowrates, or the required mud processing is possible at this rate. Note as a rule-of-thumb, one shaker will adequately handle ±300gpm of flowrate.

1.1

ROTARY AND HOISTING CAPABILITY

The rotary and hoisting capability of the rig will generally not have a direct impact on hole cleaning. The main issue to consider is any rpm limitations that are imposed by the topdrive or drillstring. For example, high torque seen at the base of a 12¼" or larger hole section, may impose limitations on the output rpm of the top drive, and thus impact the hole cleaning efficiency. Each top drive will have its own performance curve and the rpm verses torque should be carefully evaluated. Several examples are shown in Figure 21 below. Note that the rotary and hoisting capability will also be important to allow larger safety margins should the pipe become stuck (e.g. more overpull).

Hoisting capability tends to be an issue for running long casing strings and liners on

deepwater GOM wells.


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Maratime Varco TDS-4S-1 Hydraulics DDM-500

Figure 21

1.2

POWER CAPABILITY


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Apr 2003


Designing a rig with the appropriate hydraulics capability is critical to hole cleaning, but without adequate power to use that capability, hole cleaning can be significantly compromised. The power usage should be calculated for each critical section of the well, using the formulas shown in the table below. In general, the maximum power load will be while backreaming in deep larger diameter hole sections. Note that if backreaming can be eliminated with alternate hole cleaning practices, the rig power requirement will be reduced.

FORMULA

ASSUMPTIONS •

90% efficiency

•

Hookload - pick-up weight at TD, or string weight if pipe being rotated (lbs)

•

[Hookload + Overpull] (lbs) x PU speed (ft/min) Drawworks (HP) =

getting stuck

---------------------------------------------------

•

0.9 x 33000 x Sheave efficiency

PU speed - normal operation 50-100 ft/min

•

Pump (HP) =

Overpull - 100,000 lbs to simulate

Sheave efficiency:

–

8 lines (0.842)

–

10 lines (0.811)

–

12 lines (0.782)

Flowrate (gpm) x Pressure (psi)

•

90% efficiency

---------------------------------------

•

Pressure and flowrate at TD

2π x Torque (ft-lbs) x rpm

•

90% efficiency

--------------------------------

•

Torque and rpm at TD

0.9 x 1714

Top drive (HP) =

0.9 x 33000

• Based on the power for rig quarters, Auxiliary power (HP) = ± 1000 (estimate)

lighting and any auxiliary pumps and equipment •

Total Power Usage

Multiply by 1.1 to give 10% safety factor

= (Drawworks + Pump + Top Drive + Auxiliary power) x 1.1 Total Generator / Transformer capacity required (KVA) = Total Power (KW) ÷ Power Factor

•

Power (KW) = Power (HP) ÷ 1341

•

Refer to electrical specialist for discussion of power factor.

Refer to EXAMPLE 11.11.


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1.1

GENERAL CAPABILITY ISSUES

The following table lists other general rig capabilities that need to be considered when planning high angle wells. These may or may not impact hole cleaning.

ISSUE DERRICK

CAPABILITY •

Strength of the derrick itself will need to be checked with the extra loads imposed by drilling (i.e. high torque, weight of pipe)

• It is essential that the drill string be returned to a state of tension prior to initiating rotation (i.e. avoid damaging pipe). The derrick height and stretch in the drillpipe when deep in a high angle well may prevent the bit from being pulled off-bottom at connections when drilling with triples. This may require drilling with doubles.

DERRICK SET-BACK WEIGHT AND AREA

•

Calculate maximum amount of pipe that can be set-back based on area (finger board restriction) and weight (sub-structure limit)

• If insufficient for the length of the well, consideration will have to be given to drilling beyond the set-back depth with singles or possibly doubles.

MUD SYSTEM VOLUME

•

Particularly a concern if SBM is used

•

Need pit space for transfers, swapping systems and recovery of SBM

• Need enough volume for storage of base oil DRILLWATER SUITABILITY FOR SBM

•

Will be an issue for deep surface holes drilled with WBM.

• If SBM is required (and has not been used previously), considerable work will be required on the rig. This may include sealing the rig floor, mud-vacs, pipe wipers, pit isolations and cleanout, and the many HSE issues associated with using an SBM, etc.

• Will also need to consider the disposal method for cuttings (i.e. local regulations for dumping, cuttings re-injection, ship-to-shore etc.)

PIPE DECK AREA

•

Need to evaluate if the pipe deck is large enough to handle the required casing volumes

•

Suitability of running casing off a boat

BULK STORAGE TANKS

•

Large cement volumes depending on cement design

ACCOMMODATION

•

• Large volumes of barite required to weight up the system. Extra personnel will be required (i.e. Solids Control Engineer, additional pit cleaners, additional service companies specialists, etc.)

Several benchmark examples of rig capability are shown in EXAMPLE 11.11


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1

DIRECTIONAL DRILLING

1.1

PLANNING DIRECTIONAL DRILLING STRATEGIES

In the planning phase, each section of the well should be evaluated separately, with the aim to optimize the directional drilling strategy within the hole cleaning system, and overall well design. In order to define the BHA strategy for a high angle well, the following steps should be considered in the planning process:

1. Identify the key issues for the well as a whole. This will give a big picture view of the well, and allow key issues in the following step to be inter-linked.

2. Break the well up into hole sections and identify the key issues in each hole section. A series of key issues are discussed in the following sections. Note that not all of the issues will apply to all hole sections. 3.

Design BHA strategies around these key issues (as discussed in the following sections).

4.

Ensure that other general BHA, bit and surveying issues have also been considered

“The goal is to design a directional strategy that complements the ‘system’, and not simply to hit the target or follow the line” 1.1.1

Key Issue - Hole Cleaning

Hole cleaning is generally a key issue in most hole sections on a high angle well. The BHA strategy should be designed around minimizing the impact on hole cleaning with the BHA’s that are to be run. If there is no choice in the BHA’s that are to be used, the limitations of the assemblies should be clearly identified, and other measures may be required to compensate for these limitations (e.g. more frequent cleanup cycles, or a dedicated cleanout trip with an optimized BHA may be required if steerable motors are used). The BHA strategy should consider the following hole cleaning issues:

•

Conventional slide drilling is generally detrimental for hole cleaning due to the following: ○

When sliding, the “conveyor belt is turned off”, and cuttings are not being moved up the hole (i.e. no rotation). This results in dunes building up in the wellbore.

○ The bend settings on the motor may impose rpm limits on the drillstring. ○ When slide drilling, the pressure impact of a steerable motor (with PDC) can be up to 1200 – 1500psi. This is a function of the pressure drop across the motor, as well as a stalling buffer to prevent exceeding the rating of the popoff values on the mud pumps. In a pressure limited situation, this will likely result in reduced flowrates. Hole Cleaning Best Practices Manual Rev 0

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○

•

In tangent sections, steerable motors tend to undercut the hole, which increases the percentage of slide required.

Conventional rotary assemblies will improve hole cleaning with continuous rotation and minimal pressure drop across the BHA. However, even with the use of adjustable stabilizers, the drilling parameters may need to be run at less than optimal for hole cleaning, in order to control either inclination of azimuth. For example, a rotary assembly in a tangent section may be dropping excessively unless high WOB and low rpm is used. This may result in poor hole cleaning with high ROP’s combined with low rpm.

•

RSS’s will provide the optimal hole cleaning performance while drilling, with continuous high speed rotation, and complete directional control at a full range of drilling parameters. However, RSS’s should not be thought of as the “ultimate” hole cleaning solution, and appropriate practices will still need to be applied to prevent tripping problems. This is particularly true as several of the RSS tools have very limited flowby area. Refer to EXAMPLE 11.10.

•

As flowrate and rpm are key parameters for hole cleaning, any limitations with the tools to be run should be clearly identified and eliminated if possible. For example, this may require the use of larger tool sizes, jetted motors, or PBL subs for increased flowrates.

•

If a BHA is selected based on one of the other key issues that is a higher priority (e.g. high bend setting for high dogleg capability), and it is known that hole cleaning will be compromised, consideration should be given to the following strategies:

○ Drill a smaller hole size as a pilot hole, clean up the section, and then open up the hole on a separate run ○

Plan a dedicated cleanout run with an optimized hole cleaning BHA (i.e. layout any tools with rpm or flowrate restrictions)

•

BHA’s to be run in the high angle section of the well should utilize a minimal amount of drillcollars and HWDP to avoid unnecessary pressure loss which may impact flowrates. Refer to SECTION 8.2.1.

•

The BHA strategy may be impacted by the mud system proposed for an interval. For example, when drilling dispersive formations with uninhibited WBM (e.g. top hole drilled with gel / SW), hole cleaning requirements will not be as stringent due to the fact that the hole will be largely cleaned by the cuttings dissolving into the mud. This explains how large diameter, high angle surface holes can often be drilled without problems despite poor hole cleaning parameters. However, if long sections of non-dispersive formation are to be drilled, or an inhibitive mud is to be used, hole cleaning practices and the directional drilling strategy will be more critical.

1.1.1

Key Issue – Directional Control Required

Another key issue for BHA strategy is the requirement for direction control within an interval. This includes the requirement for changes to inclination and azimuth, as well as the build rates required to achieve these changes.


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The BHA strategy should consider the following directional control issues:

•

Based on the previous section, rotary assemblies and RSS’s are preferred for hole cleaning. With rotary assemblies, inclination control is limited (even with adjustable stabilizers), and azimuth control is not possible (unless using walking bits). The main application for rotary BHA’s will be in long tangent sections, where targets are large enough to allow for some bit walk. Alternatively, if a steerable or RSS run is planned in the next section anyway, there may be more scope for running a rotary assembly and allowing it to deviate from the planned wellpath (within limits).

•

RSS’s will provide full directional control, but may not be suitable in all application (e.g. uneconomic, high build rates).

•

If the required directional control cannot be achieved with rotary assemblies or RSS’s, steerable motors will be required. The bend for steerable assemblies should be optimized to allow the build rate to be achieved, while maximizing rpm.

•

It is essential that every assembly run in a high angle well have a fully developed contingency as a backup. These contingencies should be available on the rig and ready to run in the case that the primary plan is not successful. In particular, Operators often ‘put all their eggs in one basket’ with RSS’s, and have been caught out with no backup due to tool failures, or a lack of success in a particular application.

1.1.1

Key Issue – T&D

The BHA strategy can be critical in allowing the well to be drilled within the T&D limits (e.g. drilling torque, casing running, buckling, etc). This is mainly a function of how the BHA will affect the tortuosity of the wellpath. Tortuosity is a measure of how “wiggly” the wellbore is, or the cumulative dogleg. In a normal directional well, the tortuosity may not significantly impact T&D. However, in a long, high angle well, tortuosity in upper sections may have a significant impact on torque and drag in the lower hole sections. The BHA strategy should consider the following tortuosity and T&D issues:

•

The top build section will be the most critical for tortuosity, as this is where the tensions are the highest and therefore the greatest percentage of T&D is generated.

• •

Tortuosity will be minimized with the use of RSS’s, or possibly rotary assemblies (refer to EXAMPLE 11.12). Steerable assemblies generally result in increased tortuosity, which is often difficult to see with the sliding and surveying practices used (as demonstrated in Figure 22). Tortuosity can be minimized when sliding by breaking up slide intervals into as small as increments as possible. MWD tools with continuous surveys are beneficial in identifying micro-doglegs (refer to EXAMPLE 11.12).

•

If a smooth build section is critical, and a motor is to be used, consideration should be given to using motors with At-BitInclination (ABI) for precise directional control. Alternatively, consider drilling a pilot hole, as directional control is generally improved in smaller hole sizes.

•

If buckling is seen as an issue, slide drilling (particularly with PDC’s) will be difficult and inefficient. Alternatives include modifying the drillstring size/weight in an effort to overcome the buckling, or running rotary assemblies.


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• Big-bend motors usually drop while rotating • Slide 1, rotate 2 pattern • Survey every 3 singles Su Po rvey Rota int te Sli de

Su R Po rvey ota te int Sli de

Sliding Pattern May Hide Tortuosity

• DLS = 0°/100’ (NOT!)

Figure 22

1.1.1

Key Issue – Bit Selection

In high angle wells, bits should not just be “pulled off the shelf” or selected on a cost/ft basis, but must be designed to match the BHA strategy to maximize performance and aid in hole cleaning and tripping effectiveness. The BHA strategy should consider the following bit issues: Hole Cleaning Best Practices Manual Rev 0

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•

Steerable motors will generally require heavy set PDC bits or tri-cones in order to allow efficient sliding. However, PDC designs have progressed significantly in the last few years and more aggressive “steerable” PDC designs are now available.

•

If RSS’s are run, the bits must be selected specifically for the application and tools they are to be used with. The main priority will be to have a stable design to minimize vibrations, while still allowing good directional control. Generally, a short active gauge will be required for direction work, with a longer less active gauge suitable for tangent intervals.

•

More aggressive bits can be used for rotary assemblies. If using adjustable stabilizers, the bit design will need to allow for the capabilities of this tool (e.g. short gauge to maximize build/drop capability).

•

The hydraulics impact of a bit design should always be considered as part of the larger “hole cleaning system”. This includes issues such as the required pressure drop across the bit, number of nozzles, nozzle sizes, fluid flow and face cleaning etc.


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•

There may be some hole cleaning benefit to producing smaller cutting sizes (i.e. smaller PDC cutters). However, this is not likely to be a significant part of the “hole cleaning system”.

•

Junk slot area (JSA) is a critical component of the bit design for high angle wells. Effectively the bit acts as a plunger when being dragged through the cuttings bed. The smaller the JSA, the thinner the cuttings bed must be to allow acceptable tripping. This may result in slower trips and possibly more time performing remedial hole cleaning operations during trips. The shape of the JSA is also important. For example, full spiral wrap blades, or “Steering wheel” bits may have similar junk slot area as a given straight bladed bit. However, these bits are much more likely to experience cleaning and tripping problems with the cuttings having to pass through them. Refer to EXAMPLE 11.13.

•

Drilling oversize hole with underreamers or with bi-center bits may make hole cleaning more difficult (i.e. lower AV’s in larger OD hole), but may provide benefits for both tripping (large JSA) and ECD management (refer to EXAMPLE 11.1 and EXAMPLE 11.2).

1.1

DIRECTIONAL DRILLING PRACTICES

Once the BHA strategy is decided upon in the planning stage of the well, there is generally still adequate scope in the execution phase to optimize the BHA design for hole cleaning, and general ERD drilling performance.

1.1.1

BHA Weight

Traditional vertical well BHA design includes long sections of drill collars and HWDP. This is mainly to provide sufficient weight to keep the neutral point in the BHA, and to ensure that the drillpipe is not in compression when drilling. Note that these practices do not apply to high angle wells when drilling at high angle. On most high angle wells, the majority of the drillstring will be in compression when drilling (due to drag). With the pipe lying on the low side of the hole, buckling is much less of an issue, and running the drillpipe in compression is not considered a problem. Therefore, for high angle wells the amount of weight in the BHA should be minimized for the following reasons: •

Weight in the high angle portion of the well produces excessive torque and drag (laying on low side)

•

Creates buckling problems further up the string (increased drag)

•

Increased pressure drop (may result in reduced flowrates and less effective hole cleaning)

•

Running drillpipe in compression is not a significant issue

•

The effectiveness of jars is questionable

Drill collars should only be run as required for MWD and LWD tools, and a maximum of 3 stands of HWDP should be run. The HWDP is required to provide a stiffness transition between the drill collars and drillpipe. Note that drillpipe that has been run in compression should be regularly rotated through other sections of the drillstring (if possible).


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1.1.1

Stabilizer Design

This discussion is not intended to be an authoritative analysis, or to recommend a particular stabilizer design. Every directional company and directional driller seems to have a different experience and preference for stabilizer designs. The following are some general guidelines to consider. •

In general, the amount of stabilization should be kept to three or less stabilizers for a high angle well. This will be dependent upon specific requirements, but increased stabilization will only increase torque and drag.

•

Stabilizers should be designed for maximum junk slot area. String or integral stabilizers are preferred over sleeve stabilizers, which in turn are preferred over clamp-on type stabilizers. The sleeve and clamp-on type stabilizers are commonly used on motors and MWD/FEWD equipment to provide design flexibility in the field. These stabilizers reduce junk slot area appreciably, and can often be replaced with better designs with some pre-planning. Refer to EXAMPLE 11.13

• •

Stabilizers should have tapered leading and trailing edges to prevent the stabilizer hanging up. Straight blade stabilizers may be preferred for high angle wellbores, for easier tripping through cuttings beds. Refer to EXAMPLE 11.13. Note in some applications they may also produce more torque and vibrations compared to a spiral stabilizer.

•

However, spiral stabilizers have also been seen to increase the torque compared to straight blades in some applications. This is believed to be due to the greater contact area of spiral blades.

•

Spiral stabilizers may have application if bit/BHA whirl is a significant issue. It is envisaged that the spiral type blades will not whirl as aggressively as a straight bladed stabilizer.

•

Any spiral stabilizers used in ERD applications should be a partial wrap design with maximum junk slot area. The use of 360˚ wrap stabilizers is not recommended.

1.1.1

Adjustable Stabilizers

There are multiple BHA design options that can utilize adjustable stabilizers for inclination control. Each design has different applications and different advantages and disadvantages. Similarly, there are different adjustable stabilizers on the market, which have different advantages, disadvantages and applications. The final choice will depend on many factors. Following are some general design and operational considerations: •

For straight tangent sections on shorter wells, simple 2-position tools are available in a wide range of hole sizes (6” to 17 ½”). These tools are cycled hydraulically, by WOB, or a combination of both.

•

For more complex applications, or where a larger range of flexibility is required, more complex tools are available with a wider range of stabilizer settings. These tools are cycled using mud-pulse telemetry and are available in 12¼”, 9⅞” and 8½” hole sizes.

•

The gauge design of bits used with adjustable stabilizers is important. Long gauge bits will tend to constrain the assembly and reduce the effectiveness of the adjustable stabilizer. Short gauge bits are preferred (1” - 2”).

•

When planning hydraulics, ensure the pressure drop required below the adjustable stabilizer is accounted for. On a rotary assembly, this may require nozzling the bit for up to 750psi pressure drop required for the more complex tool.


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•

The tools should be set up to provide some indication of their position downhole (open / close). With the simpler tools this is a function of a change in pressure, which may be difficult to see when deep in the hole.

•

Adjustable stabilizers can be run behind motors, though the reaction seen from them will be reduced (too far back). If run behind motors, conventional power sections should be used to get them closer to the bit.

•

Multiple adjustable stabilizer tools have been used in effectively in a single horizontal drilling BHA. This requires tools with different cycling mechanisms to avoid interference and confusion.

1.1.1

Bladed Drillpipe

Bladed drillpipe was originally intended to reduce drilling torque by the use of low-friction alloys on the blade surface. However, along with a reduction in torque, a notable side benefit was an improvement in hole cleaning performance. Another benefit observed by some Operators when using the bladed drill pipe has been improved slide drilling performance. This is a combined result of the cleaner hole and the stiffer nature (i.e. more buckling resistance) of the bladed drill pipe in the string. In general, the bladed drillpipe has a similar configuration to that of standard drillpipe, with the addition of integral bladed centralizers placed evenly between the tooljoints. SMF’s Hydroclean drillpipe is shown in Figure 23 below. Each centralizer consists of 5-6 spiral blades (slightly larger OD than tooljoint), which are hardfaced with a low-friction coating designed to reduce torque and casing wear. The blades are designed to stir up the cuttings bed into the high flow regime on top of the hole and therefore improve hole cleaning.


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Figure 23 Testing results are shown below in Figure 24 for the Hydroclean drillpipe at Tulsa University flow loop. 300 GPM Reduced Reduced weight finalEROSION bed of cuttings height bed 40-60% RESULTS Wt. EQUALIBRIUM BED BED40-50% HEIGHT RESULTS 200 GPM 15-25%Reduced longer for time bedbyto60% build up 50 RPM (lb.) 30 ft./hr ROP 80 RPM 1800 Standard 960

HH

575

Hydroclean Standard

460

Hydroclean

175

750

750

1000 2000


Time Time(sec.) (sec.)

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Figure 24 Although this testing confirms their effectiveness, it has proved difficult to quantify their actual benefit in the field. The following general observations can be made with respect to using bladed drillpipe:

•

If good hole cleaning practices are already in place, the benefits of running these tools will be limited. The main benefit will be to speed up the cleanup cycle process (e.g. may require 3.5 x BU rather than 4 x BU to cleanup the hole).

•

A sufficient number of tools need to be run in order to be effective (cost implications).

•

Generally run in 10⅝" and larger hole sizes, with one joint every 3-4 stands through critical intervals over 45º inclination. With Bladed Without Bladed Drillpipe Drillpipe


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•

The tools have been seen as beneficial when backreaming, as they help to break up and spread out the cuttings beds (Figure 25). This will help to reduce the risk of packing off and may speed up the backreaming process.

Figure 25


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1.1.1

Other Mechanical Tools

Consideration should be given to the following mechanical tools for various applications that may directly or indirectly impact hole cleaning in a high angle well. However, keep in mind that none of these tools will replace poor practices, and each may add some degree of additional risk to the well.

•

If a motor is to be run, and it has a flowrate limitation that is considered inadequate for hole cleaning, most motors will allow a nozzle to be run in the top of the rotor that allows fluid to bypass the rotor / stator gap. This will allow increased flowrates to be pumped, but may result in reduce torque output from the motor and careful consideration needs to be given to the impact on sliding and bit selection. This may require tri-cone bits to be run (i.e. less torque required).

•

Jet subs run in the BHA will also allow higher flowrates to be pumped when flowrate restrictions are seen with other BHA components (i.e. similar to motor nozzling).

•

There are many different types of PBL subs that function using various mechanisms. In general, tools run should be simple to operate, and have a good track record or reliability and functionality. The tool shown below in Figure 26 is a multi-activation system that works by dropping a series of vinyl and steel balls for up to 6 cycles. These tools are suitable for a wide range of applications which may include:

○ Allow increased flowrates in various applications (e.g. flowrates restrictions in BHA, in larger casing ID above the top of liners, to reduce pressure loss through small ID strings used inside liners, faster wellbore cleanup, etc)

○ For pumping aggressive LCM pills which cannot pass through downhole tools. ○

Allow pressure activated underreamers to collapse when circulating and rotating in cased hole.

○ Allows circulation while in casing with bi-center bits (or conventional bits) run on motors (i.e. avoiding casing wear and bit damage). This applies for cleaning up the hole while tripping out, as well as breaking circulation while tripping in.


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Figure 26


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Apr 2003


•

Underreamers are generally run to drill oversize hole where annular clearances are tight, or ECD is an issue. An added benefit is that they allow more tolerance to cuttings beds in the hole for tripping. However, they may also make hole cleaning that much more difficult by drilling a larger OD hole. The two most commonly run tools are shown in Figure 27 below. Key issues with these tools include adequate stabilization to reduce vibrations, cutter durability, and the hydraulics and pinning setup. They can be run in a variety of different BHA setups (e.g. steerable, RSS, rotary, dual tools, string or NB, etc).

Security Anderreamer DBS NBR


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Figure 27


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•

Bi-Center bits (Figure 28) provide similar benefits to underreamers (larger JSA, easier tripping), with less risks (no moving parts). However, they have several disadvantages, including the following:

○ Cannot be used with “push-the-bit” RSS’s. ○

Often poor sliding with motors

○

Tend to drop angle in rotary making directional control difficult, and increased percentage of sliding with a motor in the hole.

○

Increased vibrations compared to a conventional PDC.

Running Drilling Ahead Through Casing


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Figure 28


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1.1

PRACTICES

1.1.1

Priorities for DD’s

The traditional performance criteria upon which a directional drillers performance is judged, are not conducive to good hole cleaning performance, or for “efficient” drilling on a high angle well. They are generally expected to have followed the planned wellpath as close as reasonably possible, and intersect the target(s). This may result in excessive slide drilling and a wellpath that is more tortuous than necessary. For high angle wells, it is important that all parties are in agreement with respect to the directional drillers priorities, including the company geologists and reservoir engineers. Their priorities should be to:

1. Intersect the target(s), with as smooth a wellbore as reasonably possible. Minimum dogleg severity (both individual doglegs and cumulative) is key to minimizing torque, drag and buckling problems.

2. Pro-actively maintain good hole cleaning environment throughout the drilling process. This involves planning BHA’s that will maximize rotary drilling and allow high continuous rotary speeds (on and off-bottom). Furthermore, it is vital that BHA planning take into account the rig’s capabilities, particularly hydraulics.

3. Drill a smooth, accurate build section, as this is critical for future torque and drag management. Time and cost should be secondary priorities here. Sliding frequency and time should be based around the long-term benefit, and not ROP.

1.1.1

Chasing the curve

As mentioned above, one of the traditional expectations for directional drillers was that they stay “on the line”. Trying to stick to a vertical section when the well is falling behind can cause serious problems in high angle wells. "Chasing the Curve" refers to the practice of trying to get back on the planned vertical section line when the well falls behind on inclination. Excess shallow doglegs in a high angle well can have a severe impact on torque, drag and buckling for drilling, casing and completion operations. As the tension below the doglegs increase, so too does the resulting torque and drag. If the well falls below the designed vertical section in wells of less than ±70°, the well should be re-drawn to the target and the original design discarded. Although this will increase the tangent angle, it will ultimately reduce the overall torque and drag for the well. See Figure 29. However, for wells greater than ±70°, and for negative weight wells, the tension below the doglegs begins to reduce and, therefore, the effects of the critical doglegs are lessened. For these wells, sticking to the planned vertical section may be critical to keeping the tangent angle down, and therefore minimize the effects of negative weight on the well.

Actual Planned ChasingWellpath Wellpath the original –– chasing wellpath the line curve will result Actual Wellpath re-drawn curve in increased torque and drag problems. The Hole Cleaning Best Practices Manual Rev 0wellpath should be re-drawn to the target from the current location, rather than chasing the original line

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Figure 29


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2

CASING / LINER & COMPLETION RUNNING

As discussed in SECTION 3.4, the definition of a clean hole will be different for drilling, tripping and casing running operations. Running casing or liner is often the limiting factor in a high angle well, and generally requires a cleaner hole than drilling or tripping operations. Particularly when clearances are tight, or when running floated casing, there is little tolerance for cutting beds in the hole. Cuttings and cuttings beds will be seen as additional drag when running casing, and planning for casing runs should account for this as well as increased stiffness with larger OD pipe (i.e. not the same as drilling friction factors). As discussed below, there are numerous casing /liner running methods that can be used to overcome varying degrees of drag.

2.1

PLANNING A CASING RUN

It should never be assumed that a casing or liner string will run to bottom on a high angle well with no problems. Modeling of the string weights while running and picking up the string should always be an integral part of the planning process for a high angle wellbore. Modeling will highlight potential problems and allow the run to be modified prior to the difficulties being seen in the field. Examples of casing runs on high angle wells are shown in EXAMPLE 11.8. All of the casing running techniques listed below have been used in various applications around the world to run casing in challenging applications. It should be noted that for deepwater GOM wells, casing slack off weights are generally not the main issue in casing running. Rather, the pickup weights are generally more the issue with very high string tensions in deep lower angle wells. Note that each of the alternatives below may have specific applications that lend the technique to some wells and not to others. For further information on any of these alternatives refer to K&M Technology Group or other personnel with a suitable level of experience in these applications.

•

Roller Centralizers - the use of roller centralizers on the casing can have a significant impact on the running weights. Generally only effective in cased hole, they have been seen to reduce the cased hole friction factors by us to two thirds.

•

Lighter weight casing – reducing the casing weight results in lower drag in the high angle portion of the well. Will have minimal impact.

•

Inverted Casing Designs – running weights will be improved by utilizing heavier weight casing in the low angle section (e.g. < 30º), with lighter casing in the high angle section of the well. Again the impact will be minimal unless the string is floated.

•

Hang-off Drill Collars – drill collars can be run and hung off inside the casing in the low angle section of the well for additional running weight.

•

Run casing as a liner – If possible, consideration can be given to running a long string of casing as a liner in order to improve running weights.

•

Top Drive Weight – with the use of a push plate, part of the top drive weight can be applied to the top of the casing string for additional weight.


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•

Air Filled (empty) – the casing can be run empty in order to significantly reduce the drag. Risk is always increased with this option as casing collapse must be considered in both a static and dynamic mode when the casing is fully or partially air filled. There have been two incidents of collapsed casing with floated casing runs.

•

Mud over air – in this option the casing is run empty through the high angle section, but mud is added to the low angle or vertical portion of the wellbore for additional weight. The mud and air are generally separated with the use of a Davis Lynch Selective Flotation collar.

1.1

OTHER CASING RUNNING ISSUES

Following are some general considerations that apply to running casing and liners in ERD wells:

•

Good centralization improves cementing, but the first goal must be to get the casing to bottom. Casing running friction factors can be quite sensitive to the centralization program and tortuosity of the wellpath. The centralizer type, placement frequency and overall number will all affect the casing drag. Centralizers act to stiffen the casing and, if bow spring centralizers are used, can act as “brakes” on the casing string (i.e. the restoring force of the centralizer applies a normal force to the wellbore wall). The following centralizer observations are made for high angle wells:

○ Centralization should be minimized (within cementing objectives). The only exception to this would be in the case of running casing or liners with flush connections, across a zone where differential sticking is anticipated.

○ If pipe rotation is not required, then semi-rigid or ‘double bow’ centralizers are recommended. Since the outside diameter of these tools is equal to the hole size, the “brake” action of a conventional bow spring centralizer does not exist. ○

If pipe rotation is required, then solid body centralizers are recommended. These should be as short as possible to reduce casing stiffness.

○ To limit ploughing, it is recommended that the shoe track be centralized for maximum shoe standoff and maximum shoe track flexibility. The optimum method for achieving this involves placing 1-2 centralizers back-to-back at the very bottom of the shoe joint, to ‘lift the nose up’. There should then be no centralizers at all for the next 2-3 joints (see Figure 30). ○

Consider the use of roller centralizers (as discussed above). They will only really be effective in cased hole intervals over ±30º inclination.


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The Thisconventional centralization centralization is less likely (as to have above) problems will stiffen running the casing in the hole shoe significantly. It is more likely to hangup or plough when running in the hole through a build or turn, or while passing a ledge

Figure 30

•

If rotation of the casing or liner is possible (e.g. floated casing string, liner), consider running a reamer or asymmetric shoe to help work the string down past ledges or cuttings beds.

•

Picking up casing and liners with tight clearances should be minimized as this can result in excessive swabbing or induced wellbore instability.

•

Liner hanger systems should permit circulation and rotation to aid in working the pipe through tight spots or cuttings beds left in the hole.


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•

Fill and Circulate (FAC) tools are recommended to be run with long strings of casing. ○

Allows the casing to filled regularly with minimal time impact to the operation (i.e. do not have to rig up extra hoses)

○

If circulation is required to work the casing down or for any other reason, the FAC tool allows this to happen efficiently without having to stop and rig up circulation subs.

•

1.1

With tight annular clearance consider running open shoes or fluid diverter systems to help reduce surge pressures.

COMPLETION

When planning a high angle well, the feasibility of running completion and intervention strings in and out of the wellbore must also be considered in the early planning stages. The operational practices and engineering designs relating to drilling the well will certainly affect various aspects of the completion and workover programs.


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2

DRILLING AND TRIPPING PRACTICES

2.1

DRILLING PARAMETERS AND PRACTICES

The following sections provide guidelines for the actual parameters and practices that should be employed to maintain good hole cleaning while on-bottom drilling. These guidelines are based on the hole cleaning theory presented in SECTION 3.0, as well as a considerable amount of ERD experience from a wide variety of high angle wells drilled throughout the world. The discussion below assumes that the engineering work in the planning phase has “got it right”, and all limitations have been designed out of the system.

“the best laid plans can come apart very quickly when inappropriate parameters and practices are applied, or inappropriate decisions are made”

2.1.1

Drillpipe Rotation

As discussed in SECTION 3.6.1, drillpipe rotation is critical for good hole cleaning in the high angle portion of the wellbore. Flowrate alone is ineffective unless the pipe is being rotated fast enough to stir the cuttings into the flow regime, and “turn the conveyor belt on” (SECTION 3.2.2). Field experience suggests that in 9⅞" and larger hole sizes, there are hurdle rotary speeds that produce step changes in hole cleaning performance on high angle wells (see Figure 10). This has been clearly verified by cuttings return at the shakers on many high angle wells. The mechanics of why these hurdle speeds occur is unclear, especially since relatively constant hurdle speeds have been noted for a wide variation of hole size, drillpipe size and mud systems. Note that theoretical models will not predict these step changes, but they are seen on most wells in practice.


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In the table below, the recommended drillstring rpm to allow effective hole cleaning is shown for some common hole sizes.

HOLE

DESIRABLE

SIZE

RPM

MINIMUM FOR EFFECTIVE HOLE CLEANING

17½”

120 – 150 rpm

120 rpm

14½”

120 – 170 rpm

120 rpm

12¼”

150 – 180 rpm

120 rpm

9⅞”

120 – 150 rpm

100 rpm

8½”

70 – 100 rpm

60 rpm

The following operational issues should be noted with respect to drillstring rpm and hole cleaning:

•

In large diameter holes such as 16” or 17½", rotation speeds greater than 130-150rpm should be avoided, as some operators have seen significant BHA damage at high rotary speeds in this large hole size.

•

Vibrations monitoring should be an integral part of optimizing the rpm to avoid harmonics, and vibration induced drillstring and downhole tool failures.

•

In smaller hole sizes the impact of rotation on ECD should be carefully mapped to allow limits to be set. Refer to EXAMPLE 11.5.

•

If the drillstring rpm is limited by the motor bend, the possibility of increasing rpm when off-bottom should be considered. The off-bottom loads on a steerable motor are significantly lower, and therefore the fatigue considerations may allow for the increased rotary speeds.

•

There may be some concern that the high rotary speeds recommended above may result in damage to the borehole or drillstring. If drilling a vertical or low angle well this may be the case. However, in a high angle wellbore, the majority of the drillstring is supported by the lowside of the hole, and the pipe will rotate smoothly (does not whip around). Note also that buckling while rotating is almost impossible to achieve in a high angle well (very high WOB required).

•

Many high angle wells have been successfully drilled with lower pipe speeds (typically 80-100 rpm, for reduced fatigue on steerable motors). As such, some will argue that the recommended high rotary speeds above are unnecessary. However, to compensate for the reduced rotary speeds, much greater rig capability is normally necessary. For example, it is common on such operations that 6⅝” drillpipe, and 3 rig pumps is considered to be a minimum requirement to enable effective hole cleaning. Such large equipment should not be necessary if practices and parameters are set appropriately.


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1.1.1

Flowrates

Ideally, the maximum possible flowrates should be used for every section of a high angle well, within the other limitations that may exists in the well design. These may included:

•

Standpipe pressure (SPP)

•

ECD and fracture gradient

•

Downhole tool limits

•

Directional issues (e.g. shallow build section often have to be drilled at reduced flowrates to avoid washing out the hole, and allowing the build to be obtained)

Field experience seems to suggest that a point of diminishing returns is reached with escalating flowrate (refer to SECTION 3.6.2). For example, 1300 gpm in 12¼” hole is not necessarily much better than 1000 gpm, whereas 1000 gpm is definitely much better than 700 gpm. This statement is based on experience where “drilling in the box” practices resulted in similar maximum sustained ROPs regardless of the flowrate above 1000 gpm (in 12¼” hole). In the table below, the recommended and minimum flowrates to allow effective hole cleaning are shown for some common hole sizes. The minimum workable flowrate assumes a comprehensive “systems approach” has been implemented for hole cleaning in the planning and operational stages.

HOLE

DESIRABLE

MINIMUM WORKABLE

SIZE

FLOWRATE

FLOWRATE

17½”

900 – 1200 gpm

800 gpm

14½”

850 – 1150 gpm

800 gpm

12¼”

800 – 1100 gpm

650-700 gpm

9⅞”

700 – 900 gpm

500 gpm

8½”

450 – 600 gpm

350-400 gpm

The following operational issues should be noted with respect to flowrates and hole cleaning:

•

The SPP when off-bottom is usually less than when on-bottom drilling (especially if a PDC bit and steerable BHA is in use). Hence, higher flowrates may be used when off-bottom and circulating the hole clean (if pressure limited).

•

Bit nozzling should be with flowrate limitations in mind, as well as optimizing bit hydraulics. The bit hydraulics can use up too much available pressure at the expense of hole cleaning. Alternately, bit hydraulics can be ignored in the attempt to maximize annular velocities, forgetting that good hole cleaning is pointless if you can’t drill ahead due to poor bit hydraulics. Poor bit hydraulics may also lead to bit balling, and a balled bit makes tripping through a cuttings bed more difficult and increases risks.


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•

There may be some concern that the high flowrates recommended above may wash out the hole (i.e. erosion). This is unlikely for the following reasons:

○ For all intents and purposes, with the viscous mud systems that will be used in these wells, it is impossible to get turbulent flow in the annulus. Turbulence may be feasible with seawater across the drill-collars, but otherwise laminar flow is assured.

○ Such high flowrates (say, 1000 - 1200 gpm in 12¼” hole) will give theoretical AV’s of 196-235 fpm across 5” drillpipe, 205-245 fpm for 5½” drillpipe, and 231-277 fpm for 65/8” drillpipe. When you consider that walking pace is 330 – 440 fpm, it is very difficult to visualize that such relatively slow velocities can erode the wellbore.

○ Regardless of the theoretical AV’s, the actual fluid velocity immediately next to the wellbore is essentially zero (i.e. the fluid film in contact with the formation is near stationary). This is because the fluid is viscous, and the fluid is moving slower near the wellbore, and faster in the center of the hole. See Figure 31 below.

•

It is clear, however, that hole erosion can and does occur (note that hole erosion should not be confused with hole enlargement due to other reasons, such as instability or chemical interaction). Most hole erosion occurs at the bit, especially if the bit is nozzled for high HSI. Erosion due to AV’s across the BHA and drillpipe is extremely unlikely, except perhaps in extremely unconsolidated or shallow formations.

•

Note that some documentation recommends a minimum annular velocity of 150 ft/min in order to maintain adequate hole cleaning in high angle hole sections. There are several problems with this rule-of-thumb:

○ With 5½" drillpipe in 17½" hole, this would require 1700gpm to obtain this annular velocity. We know that 17½" hole can be adequately cleaned with less flowrate. Similarly, in 8½" hole a flowrate of 260gpm would be required, and from experience this flowrate is seen as inadequate. Therefore this rule-of-thumb should not be used. Flowrate Profile in the annulus of deviated wellbore

○ As discussed in SECTION 3.3.1, and demonstrated in Figure 31 below, “annular velocity” has less meaning in a high angle wellbore. Hole Cleaning Best Practices Manual Rev 0

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Figure 31

1.1.1

ROP

ROP is a key parameter in the process of “Drilling in the Box” (SECTION 2). Once all the sides of the box have been established, a certain ROP will be required to maintain good hole cleaning, or stay within the box. If the ROP increases, you either have to change one of the parameters, or you will move outside the box (cuttings start to build up). If the ROP decreases, one or more of the sides of the box may be relaxed and still allow you to remain within the box. This process is shown in Figure 32 below. Refer to SECTION 10.2 for guidelines of how to establish the optimum ROP to continue “Drilling in the Box”.


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Drilling ROP If no changes Increases: Decreases: in steady can be state: made to the sides The (i.e. If allsize ROP size) parameters decreases, ofofthe thebox box, stay some is the a function ofsame ROP the will parameters (i.e. of need the boxlimits is mayimposed by the different design and operational the to be be relaxed same reduced size), toparameters reduce (or andremedial ROP thewhich size increases, hole ofimpact the cleaning you box hole will andcleaning. still The inside of the box represents a good adequate move practices have hole outside will cleaning be the hole required) box environment, cleaning. and excessive andcuttings outside the box is poor hole cleaning. The red diamond beds will represents start to build the up current in thehole hole.cleaning position (approaching the limits of the box).of the sides of the box may be able to One be changed (e.g. increase flowrate, change rheology, etc), and this will allow this increased ROP to be managed (i.e. back within the box).


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Figure 32


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1.1.2


The connection practices on a high angle well should be different than those used on a vertical or low angle well. The aim of these practices is as follows:

•

Minimize the potential for getting stuck. This is achieved by moving any cuttings beds up away from the BHA prior to stopping for the connection. This is particularly important with intervals in the 35º - 60º range where avalanching will occur when the pumps are stopped. This will also be more critical when slide drilling.

•

Aid with hole cleaning. If for any reason the ROP (or any other parameter) cannot be controlled to maintain good hole cleaning within the box, the connection may be used as an opportunity to spend additional time circulating to aid in cleaning up the hole.

•

Collect consistent T&D data. The connection allows an opportunity to obtain a good relative measurement of the T&D, which will provide an indication of the hole cleaning efficiency.

•

Minimize pressure loading on the hole. Connections done with poor practices can result in large ECD spikes on the hole (e.g. through the startup of pumps and pipe movement). Particularly when tight margins are involved, ECD’s at connections need to be analyzed and practices modified accordingly.

Note that connections on a high angle well will generally take longer, but the practices used will prove valuable in preventing stuck pipe, losses, or more significant hole cleaning problems. The following generic procedure is provided as a template. For each well and each interval, specific connection procedures need to be developed by engineering and operational personnel. 1.

Drill down stand at the required parameters for efficient hole cleaning.

2. Backream the stand as required. –

Note backreaming is performed solely to clear cuttings from around and above the BHA so they do not cause problems while the pumps are off and pipe is stationary.

–

Factors to consider are the flowrate, rpm, hole size, hole angle, ROP, and mode of drilling prior to the connection.

–

Depending on hole conditions the stand may be reamed 1 to 2 times. If the ROP is controlled in the last single (with rotary drilling), backreaming the stand may not be required at all.

– 3.

Down-reaming should be controlled or avoided as this can cause excessive surge.

With one single off-bottom, and at consistent pump rate; –

Record rotating off-bottom torque and string weight

–

Stop the rotary and pick up at 30 ft/min, record pick-up weight

–

Slack off at 30 ft/min, record slack-off weight

1.

Shut down pumps and bleed off pressure

2.

Slack-off and set slips.

3.

Break out top drive.


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4.

Pick up new stand, and makeup connections.

5. Start pumps slowly (stage up the pumps over several minutes), and pick up out of slips. If ECD’s are approaching the fracture gradient, start rotating slowly prior to starting the pumps (break the gels and reduce ECD spikes). Regardless of which is done first, change one parameter at a time awaiting its response.

6. Drill ahead as instructed or wait on MWD survey (if required)


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1.1

HOLE CONDITION MONITORING

High angle wells that are designed with an effective hole cleaning system must also include adequate monitoring of hole cleaning performance as the well is being drilled.

This process is known as “Hole Condition Monitoring” (HCM), and is basically the real-time collection and interpretation of relevant well data, with the aim of maximizing ROP within the hole cleaning system. The relevant well data collected can include the following.

•

Off-bottom Torque and Drag (T&D) data

•

Cuttings returns

•

Drilling parameters

•

Mud Properties

•

Downhole tools (PWD / DWOB / DTORQ / Calliper)

As discussed in SECTION 10.1.3, ROP is the key output that is used to remain “Drilling in the box”. HCM is the process that is used to allow the optimal ROP to be defined for a given “box size”. However, it is important to clearly define the ROP (hole cleaning) strategy up front. Historically, there have been two different schools of thought on drilling ROPs in high angle hole sections. Some Operators choose to drill at maximum instantaneous ROPs and then perform remedial hole cleaning operations as required (usually in the form of wiper trips or backreaming). Alternately, some Operators nominate a “safe” speed at which ROP will be limited to. This controlled ROP may be based on personal experience, or on published “stuck pipe school” guidelines. It has been K&M’s experience that the best overall footage/day (and therefore cost/foot) is achieved if hole cleaning is managed pro-actively.

“Generally, it is safer, easier and more efficient to keep the hole clean, than it is to clean up a dirty one. “ The process of monitoring T&D data (refer to SECTION 10.2.1 below) has proven to be a reliable way of maximizing ROP and minimizing stuck pipe occurrences. It is possible to safely drill at relatively high-sustained penetration rates for long, high angle hole sections if all drilling parameters, practices and strategies are optimized for the drilling rig capability. Further, it is possible to do so with minimal (if any) remedial action such as pumping sweeps, clean-up cycles, wiper trips or backreaming (refer to EXAMPLE 11.4). “Drilling in the box“ is the technique that was developed by K&M to achieve this.


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1.1.1

Torque and Drag (T&D) Data

Real-time T&D monitoring involves taking torque, rotating string weight, pick-up and slack-off readings at the surface, at every connection. Note that all readings are off-bottom. This data is then plotted against predicted trends that are based on previous experience, and calibrated with the data from the current well. If the actual results start to diverge away from the predicted trends, then a hole cleaning problem may be developing. The combination of this data, and carefully monitored cuttings, mud, and drilling parameter data can then be used to optimize drilling ROP, and / or to decide what remedial action is necessary. So what is T&D monitoring actually telling you? As shown in Figure 33 below, tooljoints will create additional drag as they are pulled through the cuttings bed (EXAMPLE 11.13). The amount of additional drag will be dependent on the bed height. Therefore, as cuttings beds build up in the hole, pick-up and slack-off weights, and their divergence from theoretical trends, can be used to gauge the level of cuttings beds in the hole. A change in the pick-up weight is normally the first indicator of hole cleaning problems. If the cuttings bed is thin, the cuttings will be moved aside leaving a groove, and slack-off may not be influenced to the same degree as pick-up. Slack-off weight changes indicate further development of hole cleaning problems. This is due to the cuttings bed becoming thick enough to re-fill the groove left after pulling the tooljoint through it while picking up. As the cuttings bed height increases, the effect on slack-off weights will become more pronounced. Therefore slack-off weight is often used as the key indicator defining the point at which remedial action is required. Torque is a secondary hole cleaning indicator as it is not as sensitive to the cuttings bed height and increased torque can be caused by other problems (i.e. changes to the mud system, hole geometry, etc.). Tooljoints Torque iscreate not a reliable additional indicator drag asofthey holearecleaning, pulled through but maythe respond cuttings if the bed. The drag of the cuttings tooljoint bed isgets dependent thick enough on the bed height.


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Figure 33


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The following advantages are seen with the T&D method for monitoring hole cleaning:

•

This method allows the actual wellbore conditions to “talk to you” while drilling, and provides positive indications of what is happening downhole in real-time. As compared to hole cleaning models, almost all assumptions are eliminated.

•

The same method can be used to monitoring tripping (in and out), as well as casing and liner running operations. Again, in these operations, T&D monitoring provides a real-time indication of actual wellbore conditions, without the limitations of PWD methods (SECTION 6.3.1), or hole cleaning models (SECTION 4.3.4.4).

•

When using off-bottom T&D data, most BHA, and all bit interaction (both of which vary wildly and are unpredictable) are removed from the equation.

•

The data collected can be used as the basis for T&D modeling and planning for future high angle wells. The value of this data cannot be understated. Quality T&D data is the key to planning challenging high angle wells. This is particularly the case when the feasibility of a well is in question, or trying to stretch the rig capability.

•

The hole cleaning monitoring is not sensitive to downhole tool failure (as with PWD).

It is important to trust the T&D modeling, but it is just as important that its limitations are well understood. T&D modeling has proven to be an excellent tool for monitoring cuttings bed build-up, but there are many phenomena that may be occurring, that will not necessarily show up or that may be misinterpreted. Differential sticking, key-seating and wellbore instability effects should not be misinterpreted as cuttings build-up. The symptoms are different and their identification underlines the importance of collecting and interpreting the T&D data in conjunction with the other relevant well data (following sections) on an ongoing basis. An example Torque & Drag (T&D) monitoring chart is shown in Figure 34. Refer to EXAMPLE 11.7 for other example plots of T&D monitoring from actual wells.


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Figure 34


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1.1.1

Cuttings Returns

Monitoring the cuttings coming over the shakers at regular intervals is a critical component of HCM. This applies both while drilling, and while performing cleanup cycles prior to tripping. Both the volume and type of cuttings can “tell a clear story” of what is happening downhole. The cuttings volume will provide a relative indication of how well the cuttings are being removed from the hole. The drilling parameters (ROP, rpm, flowrate) and other components of the hole cleaning system (e.g. mud, sliding or rotating), should all be taken into consideration when comparing the volume of cuttings on the shakers. The key is to look for trends and changes in the trends. If there are no cuttings coming back has something changed, or is something wrong? If the hole unloads, has one of the parameters increased, or has something else changed? Attempts have been made to quantitatively measure the cuttings volume coming out of the hole with the use of cutting weighing devices attached to the discharge of the shakers. The aim of these tools is to determine the weight of rock coming out of the hole, compared to the weight being drilled, and thus how clean the hole actually is. There are many assumptions involved with this method, which make it difficult to use as a definitive hole cleaning tool. However, it can provide valuable information when used in conjunction with T&D and other well data. Other Operators have attempted a simpler method, involving the collection and weighing of cuttings in a bucket at regular intervals. Again, this provides a valuable relative comparison. The type of cuttings (e.g. size, shape, character) coming over the shakers are also very important (see Figure 3). This information can be used to determine how well the hole is being cleaned, if wellbore stability is being seen, if the mud is doing its job, etc. The shaker hand is a critical person in the hole cleaning system, as they will often be the first ones to pick up a change in cuttings character, which will indicate a change downhole.

1.1.2

Drilling Parameters

Drilling parameters (time, depth, BHA, rpm, WOB, ROP, flowrate, pump pressure, etc.) should be recorded at regular intervals to provide a relative indicator of changes in the system. This data will prove invaluable in interpreting what is happening downhole. This information should already be captured by the mud logger or other personnel, but is often not analyzed in detail by onsite personnel.

1.1.3

Mud Properties

Mud properties should also be monitored on a regular basis, with an aim to identify trends (i.e. changing conditions) rather than actual values. Properties monitored should include weight, PV, YP, fann readings, LGS, gel strength, fluid loss, Chlorides, SWR, etc.


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1.1.4

Downhole Tools

Various MWD-based tools have been developed to help monitor hole conditions, and in some cases have also proven to be valuable in monitoring hole cleaning performance. These tools may provide valuable imformation, but should not be used in isolation to monitor hole cleaning, as they have distinct limitations as discussed below.

1.1.4.1

Pressure While Drilling (PWD) Tools

PWD tools are valuable for ECD management, but should not be used as a primary hole cleaning tool. Refer to Section SECTION 6.3.1.

1.1.4.2

Downhole Weight on Bit and Torque (DWOB / DTORQ) Tools

Anadrill originally developed the DWOB / DTORQ tools, which measure downhole loads at the MWD tool. These tools can provide very valuable information, particular while sliding (e.g. weight transfer to the bit). Several Operators have used DWOB / DTORQ extensively in high angle drilling to monitor hole cleaning. This is done by comparing the difference between the surface loads and the downhole loads. When the surface and downhole loads start to diverge, this is assumed to be due to cuttings loading. As with the PWD tools, reliance upon DWOB / DTORQ as primary hole cleaning monitoring tools in not recommended. The following are key issues:

•

The DWOB / DTORQ tool relies on being on-bottom (i.e. drilling) to be effective. Hence, the measurements must account for the variations of on-bottom bit and BHA interaction. With PDC bits in particular, the comparison of downhole and surface loads can be quite complicated.

•

The DWOB / DTORQ information is generally very complex, and difficult to interpret on the rig floor in real-time (difficult to track trends).

•

Careful and frequent calibration of the tools is required, which is difficult in a high angle well.

•

Perhaps the most important limitation of relying on DWOB/DTORQ, is that this tool is useless when tripping in or out, which is the greatest risk of stuck pipe.

Despite these disadvantages, the DWOB/DTORQ information can be very useful. The DWOB tool is an excellent way to monitor drillpipe buckling, and is a good way to calibrate T&D and Buckling modeling programs.


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1.1.1.1

LWD Calipers

Some LWD tools (Resistivity / Density / Neutron) provide pseudo-calipers which can be used to monitor the hole diameter when drilling and tripping. This may be beneficial for monitoring wellbore stability and aiding with hole cleaning decisions. Resistivity based pseudo-calipers provide an indirect measurement that can measure hole sizes up to 60”. This type of tool is designed primarily for the detection of large washouts in shales and unconsolidated sands. Density / Neutron based pseudo-calipers measure the time taken for ultrasonic signals emitted from the tool to bounce off the formation and return to the tool. The size of the washout that can be measured is generally limited (inches not feet).


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1.2

REMEDIAL HOLE CLEANING

It has been repeatedly demonstrated on high angle wells that it is better to stay on-bottom at an optimized ROP (controlled to match hole cleaning system) than it is to drill in short fast bursts and then use remedial operations to clean the hole up (refer to EXAMPLE 11.4). It is safer, easier and more efficient to maintain a clean hole than it is to clean up a dirty hole. As discussed in SECTION 10.2, Hole Condition Monitoring (HCM) is the process used to optimize ROP and stay on-bottom. If practices and parameters are optimized, it is generally possible to drill for very long intervals without any cleanup cycles, wiper trips (or any other remedial hole cleaning measures). However, there may be occasions where some remedial actions will be required. This may be due to changing conditions (e.g. loss of a pump, deteriorating wellbore condition, poor mud properties). Remedial operations should only be used after optimization options have been exhausted, and should be based on clear T&D and cuttings return trends. Further, the effectiveness of remedial operations should be closely observed and quantified via T&D (and PWD) monitoring before and after the operation. It is critical that any remedial operations are initiated for the right reasons and that the response is appropriate. Ensure that the symptoms correspond with cuttings bed behavior and that remedial operations will be appropriate for hole cleaning. For example, drilling through a reservoir section may result in some differential sticking acting as drag and erratic torque. Remedial hole cleaning measures would then prove inappropriate.

1.2.1

Cleanup Cycles

If for any reason, the hole cannot be kept clean through optimizing parameters or controlling the ROP, performing an intermediate cleanup cycle should be considered as the first remedial option. A cleanup cycle simply involves stopping to circulate the hole clean prior to drilling ahead. Note that the same procedures are also used for performing a cleanup cycle prior to tripping out of the hole, or prior to backreaming. The following generic guidelines are provided as a template for a cleanup cycle. Note that the same procedure will most likely be used in all hole sections, and regardless of whether it is being used as an intermediate cleanup cycle, or as the final cleanup prior to tripping. Circulate 2.5 - 3 x BU and until shakers are clean •

Measure the quantity of cuttings coming over the shakers every 15 minutes.

•

Maintain rpm and flowrate at their maximum level.

•

Pull up slowly to avoid washing out the hole, at a rate of one stand every ±60 minutes

•

Monitor relative changes in T&D and PWD compared to both modeled and last observed prior to cleanup cycle. Expect improvement as the hole cleans up.

•

Monitor vibrations to avoid excessive levels.


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•

Generally 2 distinct waves of cuttings over the shakers will occur during the cleanup cycle (second generally comes at 1-1.5 x BU after the first peak drops off).

The following should be noted:

•

Do not stop circulation after a nominal 1 or even 2 x bottoms up, as these terms are largely meaningless for hole cleaning in high angle wellbores (refer to SECTION 3.6.4). Remember that the mud is traveling on the high side of the hole at a rate much faster than the cuttings moving on the low side of the hole. It is not uncommon that good cuttings return does not actually commence until after 1 - 2 x bottoms up, and for the shakers to clean up after 4 x bottoms up (times will vary according to parameters and conditions).

•

Some form of quantitative cuttings measurement will be beneficial during this process to help in deciding when the hole is adequately clean.

•

The flowrate and pipe rpm should be maximized during the circulation. Remember that achievable off-bottom flowrates may be higher than those used for drilling, especially if pressure limited. Pipe RPM may also be greater than that used when drilling.

•

If there are concerns with undercutting or washing out the hole while rotating and circulating it clean, the pipe should be reamed up slowly at ±60 min/stand and the stand set back. Note, this is not the same as backreaming as the aim is to fully cleanup the hole before drilling ahead or tripping out.

•

The T&D and PWD trends should be monitored throughout the process. If these values return to clean hole values following this procedure, then drilling may be resumed. Otherwise, a wiper trip or some other remedial action may be warranted (e.g. backreaming).

•

Vibrations should be carefully monitored to ensure that no damaging vibrations are being induced while rotating at high rpm off-bottom (often worse than on-bottom).

•

Often the cuttings returns over the shakers come in two distinct waves. It is not exactly clear why this is the case, although it should be planned for by continuing to circulate another 1-2 x BU after the well initially cleans up.

•

Additionally, dependent on the drilling mode, cuttings flow over the shakers may also vary considerably with time, as the hole is cleaned up. If a motor assembly is in the hole and periods of slide drilling have been used, then various “dunes” may exist in the well at any one time. As these dunes are removed from the hole, it can give the appearance that the hole is unloading. Experience with the system on the rig will instill confidence in the amount of time the well will take to clean up. The key is to be patient.

•

If mud volumes are tracked carefully on the rig, then a significant mud loss can be seen as the hole cleans-up. This phenomenon tends to make mud volume tracking especially difficult in wells with inclinations greater than 65°. When drilling recommences, pit gains of the same sort of volume will be observed as the cuttings bed builds back up and displaces the mud.

“Patience is the real key to effective hole cleaning. If cuttings are still coming out of the hole, then the hole isn’t clean yet.” 1.1.1

Wiper Trips


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Unless preceded by a cleanup cycle, wiper trips have limited (if any) value for hole cleaning. Note that wiper trips for other reasons may still be necessary (e.g. to wipe a permeable zone to prevent excessive filter cake build up, or a swelling shale interval, identify wellbore instability, etc). However, these are not the hole cleaning related remedial actions that are being discussed here. It has been proven that long, high angle hole sections on high angle wells can be drilled without wiper tripping, if good practices and strategies are used throughout.

1.1.2

Sweeps

“The use of sweeps in high angle wells has proven largely ineffective, regardless of the sweep design.” A brief look at the downhole profile in a high angle well (refer to Figure 5) points to the reasons that sweeps are not very effective. Firstly, the fluid will take the path of least resistance, and will tend to stretch out on the top side of the hole. With higher viscosity fluids, this effect will be increased. With the fluid flow along the top of the hole, even the most viscous of pills will eventually allow the cuttings to fall to the bottom of the hole. Furthermore, as the pipe is rotated, mixing of the sweep with the drilling fluid is inevitable. The most common result of pumping a sweep in a high angle well is that it is seen early at the shakers, or it is not seen at all. Refer to examples of sweeps in high angle wellbores in EXAMPLE 11.1 and EXAMPLE 11.2. On the rare occasions that sweeps do bring cuttings to the shakers, it is unlikely that the cuttings come from very far downhole. Almost certainly, the cuttings recovered by a sweep came from the vertical or build section, rather than the high angle section of the wellbore. So what are the downsides of pumping sweeps on high angle wells: •

Time and money

•

In high angle wells, mud rheology is already difficult enough to keep within specification, without the detrimental effect of low-vis or hi-vis sweeps being absorbed into the mud system.

•

If barite sag is a concern, sweeps only make managing barite sag that much more difficult.

•

ECD’s are usually critical already. When sweeps do work, they bring cuttings back in a very concentrated amount, which is likely to have a detrimental effect on ECD’s.

If it is determined that a sweep is nonetheless required, the following is recommended:

•

Carefully document the following to avoid doing the same thing twice and expecting a different result:

•

○

Sweep volume and properties

○

Parameter used when pumping the sweep (rpm and flowrate)

○

Results of the sweep (volume and type of cuttings returned)

The pipe should be rotated throughout the displacement process. The pipe rotary speed while the sweep is inside of the drill pipe should be greater than 60 rpm. Pipe rotary speed with the sweep outside of the drill pipe should be greater than 120 rpm in 9⅞" and larger hole sizes (and preferably 150 - 180 rpm).


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Apr 2003


•

The bit should be pulled off bottom as the sweep clears the bit (actual preference is not to be drilling and adding further cuttings to the system).

•

Do not shut down the rotary or the pumps until the sweep is seen back at surface (likely identified by a density change in the fluid). It is not uncommon for sweeps to be detected at the surface earlier than expected, since the sweep will tend to ‘channel’ on the high side.

•

Sweeps must be coordinated with the directional drillers to ensure that they are not slide drilling while the sweep is in the hole.

•

Different sweep types may be trialled. Options included:

○ Tandem sweeps, with a relatively small low-vis volume followed by a large hi-vis sweep. The high-vis sweep may be weighted to improve buoyancy of the cuttings and to move the sweep closer to the low side of the hole. This approach is intended to cause turbulent flow (or at least better disturb the cuttings bed) followed by a “catch-all” fluid. The two pills must be back-to-back to be effective. The low-vis sweep should be large enough to remain intact.

○ Weighted sweeps have been shown to be effective in aiding with the removal of fine silt beds (formation sand and barite) on the low side of the hole. These sweeps should be weighted 3-4ppg over the mud weight with a minimal increase in the fluid viscosity. The volume should be sufficient for a 200-400ft column in the annulus. Another advantage of weighted sweeps is that coarse grain barite can be used, which will allow the sweeps to be removed at the shakers and thus avoid impacting the specifications of the entire mud system. ○

1.1.1

Fiberous LCM has been used to aid in picking up cuttings by scouring the wellbore.

Backreaming

Backreaming should be considered as a last resort for remedial hole cleaning options, but may be necessary prior to tripping in certain applications (e.g. floated casing, tight clearance casing programs such as SEPCo deepwater GOM wells). Refer to SECTION 10.4.2 for detailed backreaming guidelines.


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1.2

TRIPPING

Tripping on high angle well is where the “rubber meets the road”. This is where most problems tend to occur when Operators simply utilize the same practices that were employed in vertical holes. The main differences that must now be considered are the transport of cuttings, formation of cuttings beds, and what happens as the BHA is pulled through these beds. If tripping procedures do not account for these issues, then the practices are likely to result in an inappropriate, time consuming, and often-dangerous operations. Refer to EXAMPLE 11.10 and EXAMPLE 11.13 Regardless of the method used to trip out of the hole, every trip should be preceded by a cleanup cycle (refer to SECTION 10.3.1), to minimize the potential for problems while tripping. This does not mean that there should be no cuttings at all, but simply that the cuttings bed height is sufficiently low and evenly distributed to allow the bit and BHA to pass through without problems. The advent of the top-drive system has lead to many Operators choosing not to invest time in cleaning up the hole prior to tripping, since they have the ability to backream, if necessary. This has developed into a time consuming and risky practice.

1.2.1

Standard Tripping Practices

The following generic guidelines are provided as a template for standard tripping procedures. This procedure will apply to all intermediate bit trips as well as the final trip prior to running casing if there are no special requirements (SECTION 10.4.2.2).

1. Perform cleanup cycle (SECTION 10.3.1). 2.

When shakers are clean, pull 5-10 stands wet to check hole condition.

3.

Pump a slug and POOH on elevators

–

Record pick-up weights on every stand and plot on a theoretical T&D chart in real-time (preferable on the rig floor). Refer to example plots in EXAMPLE 11.8.

–

Use of analog weight indicators is recommended to better identify fluctuations.

–

Note that if tight hole is likely based on offsets or analog wells, consider pulling wet all the way to the shoe before pumping a slug and POOH on elevators (i.e. limits slugs in the hole).

1.

If a tight spot is encountered (>30kips overpull) assume the tight spot is cuttings. RIH 2-3 stands until the BHA is clear of the obstruction, and circulate for 30 minutes. -

2.

The goal here is simply to confirm if it is a cuttings bed, not to circulate BU

Pull up wet through the tight spot without rotation. If the tight spot has disappeared, then it was caused by a cuttings bed that has now been moved up the hole. Return to step 1 and circulate the cuttings out of the hole. -

If the tight spot remains in the same place, then it is likely another mechanical process (i.e key seating, ledge). If this is the case, ream through section and try to eliminate the tight spot. Pull up through the tight spot again without rotation to see if it has been eliminated after reaming. If obstruction has been removed, go to step 3.

6.

Backreaming should be used as a last resort if a cuttings bed cannot be circulated out. If backreaming is started, it should be continued up to ±30o inclination.


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The primary rules for tripping in high angle wells are:

•

Always assume that any tight hole or over-pull is due to cuttings (i.e. hole cleaning related). However, this needs to be tested to ensure wellbore stability (or another issue) is not the problem.

•

The actual pick-up weights should be plotted against the theoretical weights, to ensure that sections of tight hole and overpull are quickly and clearly identified.

•

Do not assume that cased hole is a safe haven for tight hole avoidance. It is not unheard of for stuck pipe to occur inside casing, either just inside the shoe or many thousands of feet inside casing.

•

Backreaming should be used as a last resort if a cuttings bed cannot be circulated out. If backreaming is started, it should be continued until ±30º inclination before circulating the hole clean and POOH. Refer to detailed backreaming procedures as detailed below.

•

Tripping in practices should also be developed to minimize the surge exerted on the formation, and deal with potential barite sag.

1.1.1

Backreaming

Although backreaming may be considered an appropriate practice in vertical and conventional low angle deviated wells, in general, backreaming and pumping out of the hole are not appropriate practices for high angle wellbores, as a primary hole cleaning tool.

1.1.1.1

Problems with Backreaming

So what’s so bad about backreaming in a high angle wellbore:

•

Backreaming cleans the wellbore completely below the bit and BHA, rather than leaving a small cuttings bed that the bit and BHA can safely trip through. As such, a dangerous cuttings dune builds up just above the BHA. This dune is likely to be much higher and thicker than the cuttings bed left from a cleanup cycle. The dune significantly increases the risk of packing off and stuck pipe. See Figure 35 below. Also, refer to EXAMPLE 11.3 and EXAMPLE 11.10.

•

If pack-off does occur, there is a high risk of permanent damage to the wellbore below the pack-off. A feature of high angle wells that utilize backreaming is that the wellbores often seem to deteriorate over time, especially if any tight hole was encountered while backreaming. This is likely due to the “hydraulic hammer effect” (or “water hammer effect”), which exposes the wellbore to brief, but extremely large, instantaneous pressure surges. The ‘hydraulic hammer effect’ is well known to pipeline and systems engineers and is the primary reason that pipeline valves are designed so that they cannot be shut-in quickly. In essence, a quick shut-in in a high pressure hydraulic system (such is the case if the wellbore packs off instantaneously when the pumps are on) causes a brief, but extremely violent’ pressure wave within the upstream system. This pressure wave quickly builds upon itself, and is known to burst pipelines and pressure vessels. It is possible that even the briefest pack-offs expose the lower wellbore to similar effects.

•

Backreaming can be detrimental for casing wear as high tensions forces in the drillstring are seen in the build section. Casing wear is generally not a serious concern in ERD, unless backreaming is used on a regular basis.


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Apr 2003


•

Backreaming can also have a significant impact on the fatigue life of the drillstring (again due to high tension and cyclic stresses).

•

High vibrations and shock are often seen on the MWD when backreaming.

• •

Backreaming can mask the true wellbore conditions (difficult to see cuttings beds when POOH). From a feasibility aspect, power requirements for optimum rig sizing must account for backreaming expectations. If backreaming is to be a planned part of ERD hole cleaning practices, then the power requirements may be significantly more than if hole cleaning and tripping practices are designed to prevent the need for backreaming.

•

Backreaming is a time consuming operation. Once it is started it cannot be stopped, and it must be done slowly.

Beach or dune isleft created Harmless No Result Acceptable cuttings of Backreaming cuttings bedCuttings left in below the Bed – Hole for theis Tripping cleaned –near hole100% is notbelow 100%the clean, bit, moving but the bed otherwise height harmless is low above the BHA bit cuttings backreamed to enough above interval the to allow BHA. easy The passage cuttingsof form the aassembly dune which without presents pumps a significant or rotationstuck pipe / pack-off risk unless backreaming is extremely slow. “Pumping out” (no rotation) is even more dangerous, since there is no rotation to move the cuttings dune away.


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Figure 35

1.1.1.1

Backreaming Applications

There may be certain applications in which backreaming is required and cannot be avoided. These may include: •

Cuttings are not removed by cleanup cycles due to build up of fines, or paste, on low side of the hole (e.g. poor mud quality)

•

Hole problems not related to cuttings beds (i.e. swelling formation, ledges)

•

To prevent swab related formation compressional failures.


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Apr 2003


•

If a very clean hole is required for subsequent casing running operations. Examples may include:

○ Where these is minimal string weight available ○

Casing flotation where circulation will not be possible

○

For tight annular clearances (surge pressures, tight hole)

○

When running casing or liner with open floats

1.1.1.1

Backreaming Guidelines

The following generic guidelines are provided as a template for backreaming operations. 1.

Perform a full cleanup cycle as per the previous guidelines. Do not take a short cut with this step!

2.

Commence backreaming at a maximum of 5 stands per hour.

–

If an RSS is included in the BHA, and where applicable, ensure the pads are set in the neutral position.

–

Maintain maximum flowrate and rpm.

–

Monitor PWD and vibrations.

–

Monitor pump pressures, return flow, and torque for signs of packing off and tight hole.

–

Be patient!

1. Continue to backream to ±30 o inclination (maybe inside casing) before circulating a further 1.5 - 2 x BU and POOH on elevators -

Consider circulating the hole clean prior to backreaming into the casing shoe.

The following general guidelines should apply:

•

There is no application for “pumping out” of the hole (i.e. circulating out, without any or insufficient rotation). Note that pumping out further increases the risk of packing off and/or stuck pipe. In this situation, the dune is still being created, while there is insufficient rotation to disturb and move the dune away from the BHA.

•

Backreaming should always be performed at maximum allowable flowrate and string rpm.

•

The pulling speed is a critical parameter. Keep in mind that backremaing is basically the same as drilling back up the hole. Wouldn’t you expect to have hole cleaning problems if you drilled a stand down in 5 minutes (1200’/hr), and made a connection with no further circulation? Some Operators have theoretical models for predicting the fastest safe speed that the pipe can be pulled when backreaming. Regardless, the process needs to be based on surface torque and pump pressure measurements as a means of determining pulling speed. Typical speeds may be as slow as 10 - 15 min/stand in 12¼” hole. Be Patient!

“Backreaming is an exercise in patience”


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•

Always perform a cleanup cycle prior to starting backreaming. This will minimize the risk of stuck pipe and pack-off.

•

Consider intermediate cleanup cycles while backreaming out of the hole.

•

Always perform a cleanup cycle immediately after finishing backreaming – never just POOH. This applies to both cased and openhole.

•

Take special care when backreaming into a casing shoe as the larger diameter rathole below the shoe may be an area where cuttings will accumulate. Consider extra circulation with rotation before backreaming into the shoe.

• •

Consider bladed drillpipe or stabilizers in the drillstring to spread the cuttings load (refer to SECTION 8.2.4). Consider tripping for a smaller and cheaper assembly prior to backreaming. This will allow high cost MWD / FEWD tools to be laid out, and an undersize bit and stabilizers to be used. This will reduce the risk of pack-off and stuck pipe.

•

Sweeps should not be pumped while backreaming as they may increase the risk of packing-off.

Refer to EXAMPLE 11.10


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1

CASE STUDIES

The following case studies have been included to provide examples of different theory, practices and techniques described in this manual. Although the majority of the examples are based on data from SEPCo wells, some other data has also been included.

EXAMPLE 11.1 11.2 11.3 11.4 11.5

WELLS Ursa A3 & A5 MC 765 #1 Ardennes JA-2 & others Ursa A5 MC 766 #1 & other

TOPIC Hole Cleaning Practices

Hole Cleaning Practices (2) Backreaming Intermediate Hole cleanup Effects of pipe rotation hole cleaning and ECD and

11.6

Ursa A10

11.7

Other

T&D Monitoring while drilling

11.8

Other

T&D Monitoring while tripping and running casing

11.9

Other

ECD effects

11.10

Other

Tripping Practices

11.11

Other

Rig Capability

11.12

Other

Tortuosity

11.13

Other

Expro Stuck Pipe Prevention Course cuttings bed sticking model


Borehole Instability and Hole Cleaning

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1.1

HOLE

CLEANING PRACTICES

The Ursa A5 was spudded in October 2000, and did not utilize good hole cleaning practices. After the poor performance on this well, many of the hole cleaning practices detailed in this manual were then implemented to some degree on the Ursa A3, which was spudded in June 2001. The hole cleaning, and overall performance, was considerably improved on this well. The tables that follow provide a summary of the operations on each well, with the rating system shown below used to describe the various hole cleaning practices seen on each of these well. Poor practices (mainly on the A5) included the following: •

Low rotary speeds and flowrates

•

Relying on sweeps to clean the high angle hole section

•

Insufficient circulating time (e.g. 1 x BU)

•

Backreaming used too often and inappropriately

•

Hole cleaning capability limited by BHA designs (e.g. rpm and flowrate restrictions, sliding)

•

Tight hole treated as hole problems rather than cutting beds

In summary, although there was tight hole seen on many of the trips (particularly A5), no significant problems were encountered on either of these well (e.g. stuck pipe). This is despite the fact that the hole cleaning practices were often poor. It is likely a function of drilling oversize hole (larger annular clearance and bit junk slot area) that prevented more significant problems from occurring due to the poor practices (increased tolerance for cuttings beds).

Good hole cleaning practices / performance Marginal hole cleaning practices / performance Poor hole cleaning practices / performance URSA A5 Start Depth

End Depth

Operations Summary

Rating

Comment

17" Hole (UR to 22") to 7350', 16" Casing set at 7320' 6185'

7350'

7350'

RIH with 17" tri-cone bit, LOT 10.8ppg, using PHPA mud, drill to 7350' (1472gpm, 120rpm), pump regular hi-vis Nut Plug sweeps for hole cleaning, still vertical.

Vertical

7350'

POOH to 6475', some drag, BR to 6168', having problems with hole packing off, ream down to 6754', work tight spots, pump Nut Plug sweep, BR to 4200', pump 100bbl caustic sweep, good returns of gumbo and cuttings, RIH to 6876', taking 20 kips, POOH to 6548', encountered 20 kip OP and swabbing, pump out of hole to 6373', POOH removing gumbo from string.

Vertical


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Apr 2003


7350'

7350'

RIH with same BHA and UR hole to 6755' with 120rpm, 724gpm, while raising MW to 10.3ppg, circ and condition mud at 6755' due to 10.78ppg ECD, UR to TD, pump Nut Plug sweep and circ hole clean with 120rpm, 1400gpm, wiper trip to shoe, spot 16ppg mud on bottom, POOH ok.

7350'

7350'

RIH with 16" J-55 109# Hydril 511 casing on 6⅝" landing string, RIH to 7320' ok

Vertical

Vertical

10⅝" x 14½" Hole to 9916', 13⅝" Casing set at 9875'

9916'

RIH with 10⅝" PDC, 14½" RWD, motor (1.15 bend), PBL, 6⅝" DP, displace to 10.8ppg NovaPlus, FIT to 11.7ppg, drill to 9580', pumped 3 hi-vis sweeps and noted increase in fines, but no change in larger cuttings, drill to 9916', 40 rpm, 1250gpm, approx 48deg at TD.

With inclination up to 48deg on bottom, hole cleaning will be impacted by low rpm, and amount of sliding.

9916'

9916'

Circ and condition mud (1.5hrs), 50 rpm and 1283gpm, BR to 7441', 50rpm, 1325gpm, no tight hole, circ for 1 hr, POOH to shoe, RIH, drag at 8940', wash and ream to bottom raising MW from 11 11.2ppg, circ 50bbl hi-vis sweep, returned large volulme cuttings, continue circ until cutting dropped off, BR to 8673' (30deg inc), pump hi-vis sweep, RIH to TD no problems, circ 3 x BU and hole still unloading large volume cuttings, pump hi-vis sweep, BR to 8007', pump hi-vis sweep, POOH to 4105', open PBL in riser, circ hole clean, POOH.

Circ prior to BR would have done little with 50 rpm, and all the BR is doing is picking up everything and dropping it back on the lowside above the BHA. There are a lot of cuttings as little would have been removed while drilling the section.

9916'

9916'

RIH with 13⅝" 88.2# P-110 GB-TCC-IS-SC casing on 6⅝" landing string to 9875', max 25 kips drag, no returns or partial returns, wellhead problems.

7350'

9½" x 14" Hole to 17260', 11¾” Liner set at 17255'

17260'

RIH with 9½" PDC, 14½" RWD, motor, NBR (14"), 6⅝" HWDP, 5½" DP, Bladed DP every 4 stands, 11.5ppg NovaPlus (MWD showing 11.95 and 11.83ppg), FIT to 12.54ppg, drill and slide to 11534' (building angle 51+ deg), 40-50rpm, 1016gpm, circ and condition mud for 0.5 hrs due to increasing ECD's, Drill to 12980', pumps 2 hi-vis sweeps when ECD's increasing, first one brought back good load, no impact from second, Drill to 13150', pump lo-vis followed by hi-vis, 70rpm, BR from 13150' to 10100', 70 rpm, 1016gpm, lo-vis / hi-vis pill brough back good load cuttings, circ hole clean 1.5 hrs, RIH ok (no fill), drill to 17260', 70rpm, 1000gpm, inc 50-55deg, MW up to 11.7ppg, sweeps show little benefit

Poor hole cleaning environment with slide drilling (majority in rotary), 50-70rpm, 45-55deg inclination. Sweeps most likely unloading the riser when extra returns seen. Bladed drillpipe may have helped with sweeps.

17260'

17260'

Pumped hi-vis sweep and circ BU, no increase cuttings (sweep back 100bbls early), BR to 10009', 70rpm, 1000gpm, pumped hi-vis sweeps during BR with minimal success, pumped lo-vis/hi-vis with good returns at 10009', RIH, tight 10090', wash and ream to 10200', circ BU, RIH in TD, hi-vis sweep no extra returns, POOH to 10288', pump lo-vis / hi-vis sweep (no increase), BR to 9980', activate PBL, cir BU, 50rpm, 1000gpm, POOH ok

This trip gives good evidence of the limited value of hi-vis sweeps (came back early). Tandem sweeps slightly more effective, but again limited with rpm of 50-70

17260'

17260'

RIH with 11¾” 65# P-110ST-L Liner on 6⅝" running string to 17255', lost returns at 12460', well took 12 bbls/stand after, excess, but erratic torque noted, shoe plugged,

Hole was not adequately clean based on casing run

9916'


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Apr 2003


Start Depth

End Depth

Operations Summary

Rating

Comment

10⅝" Hole to 24840', 7⅝" Liner set at 24835' 17260'

17261'

RIH to drillout shoe with tri-cone, some junk in hole, squeeze liner lap

23769'

RIH with 10⅝" PDC, 8¼" motor, 3-point reamer, LWD tools, 12.5ppg NovaPlus, LOT 14.8, drill to 23769', drop angle down to 30deg, 60-90rpm, 750-775gpm, MW up to 13ppg, gas cut back to 12.8ppg

Minimal sliding, but motor restricts rpm and flowrate

23769'

Pump Hi-vis / Lo-Vis sweep and circ 1.75 x BU, short trip to 19442', 10-20k OP in Yellow sand, and further tight spots shallower, RIH with no resistance or fill, pump sweep and circ BU, POOH to 17130', 15k OP at 20599', 17512' and 25k OP at 17356', work through each, circ at top 11-3/4" liner, no extra cuttings, POOH

Insufficient time spent circ BU left cuttings beds (tight spots), no indication of rpm used (most likely 60-70rpm).

23769'

RIH TLC, tool string HU @19652' (50deg), could not work down, POOH with lots of damage, some slow circ done with TLC tools

Failure to get tools down likely a result of cuttings bed left in the hole from previous cleanup, slow circ most likely resulted in barite sag seen on following wiper trip

23769'

23769'

RIH for wiper trip, 10⅝" hole opener, UG stabs, RIH and tag obstruction at 19652', could not work through without rotation, 70rpm, 700gpm, RIH and HU 21762', work through, tag several further obstructions, all around slide points, barite sag seen near bottom, circ single BU at TD, 40rpm, 727gpm, POOH to shoe, again saw OP at 19652', RIH to this point and ream through this area, RIH to TD ok, Circ 1 x BU, 40rpm, 700gpm, Barite sag seen, POOH again seeing several tight spots

Insufficient rpm just smoothing out the cuttings beds or accumulating them back in doglegs or washed out intervals

23769'

23769'

RIH with TLC, logged ok, left a small SS/rubber element in hole

24840'

RIH with 10⅝" PDC, Motor, LWD, break cir on way into the hole, some HU points on the way in, raising MW to 14ppg on bottom and circ for 5 hrs, Drill to 24840', 80rpm, 670gpm, majority rotary, circ regularly to reduce gas, 34deg inc

Limited flowrate and rpm, circ for gas would have helped to some degree

24840'

24840'

Circ for 3 hrs at 80rpm, 670gpm, BR to 23,297', POOH, tight spot at 17478', wash and ream through, POOH to shoe, circ BU at 20rpm, 670gpm, RIH to TD ok (no fill), circ BU, mud losses, 75rpm, 500gpm, POOH to top 11¾” liner, circ for 2.5 hrs at 50rpm, 260gpm, POOH

Again poor hole cleaning with inadequate rpm and circ time

24840'

24840'

TLC run, tools HU 21240' but dropped through, ran to bottom ok

24840'

24840'

RIH with Logging BHA, break circ on way in, very low flowrates to avoid losses, Barite sag, POOH spotting LCM as required

24840'

24840'

RIH with 7⅝" 47.1# P-110, 39# Q-125 VAM ACE Liner to 24749', wash liner to 24825', no mud losses while washing down, losses during cement job up to 730bbls

17261'

23769'

23769'

23769'


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Apr 2003


URSA A3 Start Depth

End Depth

Operations Summary

Rating

Comment

17" Hole (UR to 22") to 7366', 16" Casing set at 7320'

6167'

7366'

Run 21" drilling riser, 20¾” BOP stack, RIH with 17" tri-cone bit, motor (1.15 bend), 6⅝" DP, FIT 10.65ppg, using HP-WB mud, slide / rotate from 6167' - 7366' (1350gpm, 45rpm), circ for 0.5 - 2 hrs several times before running gyro survey, inclination from 0 - 15deg

7366'

7366'

Pumped 100bbl hi-vis sweep and circ for 2 hrs raising MW from 10.1 to 10.3ppg, POOH ok

7366'

7366'

RIH with 22" UR and PBL sub, UR section with 1350gpm

7366'

7366'

Pump 100bbl hi-vis sweep and circ well clean for 2 hrs with 1350gpm, POOH and noted 25kip OP and swabbing at 7171', MU TDS and wipe section, suspect cuttings bed, RIH to 7246' and 25 kips drag, wash and ream to TD ok, spot 94bbl 16ppg pill back to 7166', POOH to 6269', activate PBL, BR to 4056', circ BU, POOH ok

7366'

7366'

RIH with 16" X-56 109# Hydril 511 casing on 6⅝" landing string, RIH to 7320' ok

Low Inclination

Low Inclination

Low Inclination

10⅝" x 14½" Hole to 10120', 13⅝" Casing set at 10071'

7366'

7938'

RIH with 10⅝" PDC, 14½" RWD, motor (1.5 bend), 6⅝" DP, displace to 10.8ppg NovaPlus, FIT to 10.8ppg, drill to 7938', circ 1.5 hrs at 1350gpm (60 rpm), started taking losses, pump slug and POOH, inc up to 23 deg.

7938'

10120'

TIH, wash and ream from 7331' to 7938', drill to 10120' (40 rpm, 1150gpm), pumped a 13ppg hi-vis sweep at 9370' (40rpm, 1150gpm), circ for 0.5 hrs at 9420', raise MW to 11ppg, approx 60deg inc on bottom.

rpm too low while drilling, and insufficient cleanup time with sliding.

10120'

No circ at TD, BR to 7320' with 60 rpm, 1280gpm (multiple tight spots), pump 50bbl hi-vis sweep, RIH to 8895', 25kips drag, wash to 9092' (reaming down), TIH to TD ok (no fill), spot 16ppg mud back to 9920', POOH to 7367', open PBL and circ, POOH to 4094', circ, POOH

No circ prior to start BR, BR just drop cuttings out above BHA (explains tight spots), leaving cuttings beds in the hole forces down reaming to get back to bottom, insufficent rpm throughout

10120'

RIH with 13⅝" 88.2# P-110 GB-TCC-IS-SC casing on 6⅝" landing string, full returns to 9380', started taking 60-80kips drag, washed and reciprocated to 9458', RIH to 10071' with partial returns, lost 52 bbls running csg

Drag and losses probably due to cuttings beds LIH

10120'

10120'


Page 1

rpm too low while circ prior to tripping, although inclination low.

Apr 2003


Start Depth

End Depth

Operations Summary

Rating

Comment

12¼" x 14" Hole to 20116', 11¾” Liner set at 20116'

10120'

13832'

RIH with PDC, PD900, NBR (14"), 6⅝" HWDP, 5½" DP, bladed drillpipe every 4 stands, 11.5ppg NovaPlus, FIT to 12.7ppg, open NBR below shoe, drill to 13832', 140-160rpm, 1100gpm, trip due to PD900 failure, 60deg inc in the hole

13832'

13832'

Circulate 5 hrs at 160rpm, 1100gpm prior to trip, hole cleaned up after 2 circ, 2nd spike in cuttings seen after 3rd BU, POOH ok

Good practices, no BR, no tight hole.

20116'

RIH ok, drill to 20116' with 160rpm and 1100gpm, MW up to 11.7ppg at end, torque 23 kft-lbs, 60deg tangent, good run

Excellent hole cleaning conditions throughout, monitoring T&D verses theoretical would be of value to optimizing ROP and hole cleaning.

20116'

No circ, BR to 11303' with 160rpm, 1060gpm - BR 3 stands/hr until pronounced decrease in cuttings over the shakers at 3.75 x BU, increase to 5 stands /hr, several tight spots with increase in torque, BR from 11303' to 10160' with 160rpm, 1060gpm - lower to 3 stands/hr as hole unloading large size cuttings over shakers, RIH to 10255', spent 1 hr cleaning up the hole, trouble getting NBR into casing shoe, RIH to TD, ok (no fill), dropped gyro, POOH into shoe, worked several tight spots

On the initial cleanup while slowly BR up, may have been advisable to circ for longer to see if a second wave of cuttings seen on the shakers, may want to add in intermediate cleanup point

20116'

RIH with 11¾” 65# P-110ST-L Liner on 6⅝" running string to 20101 (seen deeper when drilled out), run ok, losses started at 17093' and 110bbls lost by TD, could not circ at TD due to plugged shoe, 667 bbls mud lost during cementing

May still have been cuttings left in the hole due to not cleaning up the hole after backreaming.

13832'

20116'

20116'

Good flowrate and rpm

10⅝" Hole to 26533', 9⅝" Liner set at 25635' 20129'

RIH to drillout shoe with tri-cone, LOT to 14.67ppg, installed WWT protectors from 14271' to 19028' (bit depth), POOH

20129'

21260'

RIH with 9⅞" PDC, PD675, LWD tools, RWD (10⅝"), 5½" HWDP, 5½" DP, bladed drillpipe every 4 stands, 12.7ppg NovaPlus, shut down several days for weather, drill to 21260', PD675 not giving any reaction, POOH

21260'

21260'

Circ and condition mud prior to POOH with PD675 (5 hrs), POOH ok

26533'

RIH with 10⅝" PDC, 8¼" motor (1.15 bend), LWD tools, 5½" HWDP, 5½" DP, bladed drillpipe every 4 stands, drill and slide to 25952' (dropping angle to approx 45deg), rotating 60-100rpm, 775gpm, mud weight increased to 13.4ppg, @25952' circ and condition mud (1 hr), drill and slide to 26147' (past base of Yellow), build to 47deg, stop and circ 3 x BU while increasing MW to 13.9ppg, 100rpm, 760gpm, drill to 26218', see losses at 26200' (max ECD 14.62), slow pump rate to 520gpm, no losses, drill to 26243', stage pumps up, but losses, pump 2 x LCM pills, still getting losses, drill to 26340' at 520gpm, pump another LCM pill, drill to 26553', Pump out of hole to 25095' at 775gpm, log down and try to identify loss zone while circulating and cutting MW to 13.5ppg (11 hrs), could not rotate or induced losses, once MW back to 13.5ppg could rotate at 90rpm, POOH ok

20116'

21260'


Page 1

Checked ECD prior to drilling ahead with 12.7ppg mud in the hole (@635gpm 80rpm / 13.38ppg, 100rpm / 13.39ppg, 120rpm / 13.42ppg, 140rpm / 13.43ppg

May have done some more circulation while sliding, lots of time spent circulating before POOH, although rpm is unknown

Apr 2003


26533'

26533'

RIH with cement stinger, Barite sag seen with mud circulated up, set cmt plug, POOH

25395'

25650'

RIH with 8½" tri-cone, 10⅞" RWD, 12¼" NBR, PBL, 5½" HWDP, same DP as previous, pumped up static MW of 13.7ppg at shoe, ream to 25395' where tagged cmt, drill cmt to 25650' (TD)

Short distance drilled with high rpm and flowrates

25650'

25650'

Circ 1.5 hours at 760gpm, 140rpm, BR to 20074' (760gpm, 140rpm), several tight spots, no circ after BR, circ at several depths with the PBL sub on trip out, POOH ok

Good flowrates and rpm, no circ after BR

25650'

25650'

RIH with 9⅝" 43.5# P-110 ST-L Liner to 25635', 20bbl losses getting liner to bottom, liner shoe plugged, circ with full returns, 100bbls lost during cementing

Cuttings may have been left in the hole as hole was not cleaned up after backreaming

6½" x 9⅞" Hole to 26534', 7⅝" Liner set at 26532'

25650'

25810'

RIH with 6½" PDC, 9⅞" RWD, 6¾” XP motor (1.15 bend), LWD, PBL, 5" HWDP, 5" DP, sag of 12.5 - 17.4ppg seen, drillout shoe to 25657', started seeing losses after 15min circ, 13.7ppg NovaDrill, FIT 15ppg, problems KO out original wellbore, losses and sag seen, condition mud, ECD's up to 14.7 and mud losses, POOH

25810'

25810'

RIH with 3½" stinger, 14.4ppg mud on bottoms up at 23000', cement back to 24948', hesitation squeeze, POOH

25432'

26534'

RIH with 6½" PDC, 9⅞" RWD, 6¾” XP motor (1.15 bend), LWD, PBL, 5" HWDP, 5" DP, tagged TOC at 25432', drill cmt to 25670', circ and condition mud to 13.5ppg (static MW 13.75 from PWD), FIT 15ppg (15.15 from pWD), drill and log cement to 26517', POOH to 25607', FIT to 14.71 from PWD (twice), POOH ok

26534'

26534'

RIH pressure samples on TLC, ok

26534'

26534'

RIH with 7⅝" 47.1# P-110 VaRSS-1 Liner to 26532', no losses while running liner, 216 bbls mud lost during cementing

Sag and ECD issues

Sag and ECD issues

6¼" x 7" Hole to 27535', 5½" Liner set at 27535'

26840'

RIH with 6¼" tri-cone, LWD, 3½" DP, 5" DP, drillout shoe, still some sag seen, 13.9ppg mud, FIT to 15.0ppg, drill to 26840' with 260gpm, 50 rpm (no losses), circ 2 vol of 7⅝" x 9⅝" annulus to clear cuttings, 10 stand wiper trip, POOH (MWD failure??)

26840'

27092'

RIH 6¼" tri-cone bit, 4¾” motor (no bend), NBR (7"), LWD, 3½" DP, 5" DP, PBL sub in string at top of 7⅝" liner, MW 14ppg, open up hole to 7", 14' fill on bottom, drill to 27088' (pipe stalling), had to PU to approx 140 kips OP to break free, decision made to weight up to 14.2ppg, drilled to 27092' in attempt to get MWD signal, POOH to 26600', open PBL and circ for 8 hrs, POOH ok

27092'

27535'

RIH same BHA as previous, drill to 27535', 50rpm, 250gpm,

Limited cleaning in 9⅝" and above, get this on the trip out with PBL

27535'

27535'

Circ 6.5hrs, 50 rpm, 250gpm, wiper trip to shoe and back, circ 2 x 7⅝" x 9⅝" casing volumes, POOH and open PBL above 7⅝" liner top, circ 2 x BU, 50 rpm, 356gpm, POOH

Adequate time spent circulating

27535'

27535'

RIH TLC, tools stuck, worked free, POOH ok

27535'

27535'

RIH with 5½" 23# P-110, ST-L liner to TD, ok, lose a total 736 bbls mud while cementing

26534'


Page 1

Apr 2003


1.1

HOLE CLEANING PRACTICES (2)

The MC 765 well was originally drilled to 21702’ MD with a 10⅝" bit. The inclination was ±50º. The well was successfully drilled, tripped, logged and plugged back to the 11¾” shoe for delineation as sidetrack #1. Parameters while drilling were 625gpm and 50-80rpm, and practices employed included sweeps, a short wiper trip, and no backreaming. Hole conditions throughout this section were reported as good. There appears to have been less problems with cuttings in this original hole compared to the sidetrack. This is most likely due to the fact that the original hole was shorter, at lower inclination, and 10⅝" rather than 12¼".

MC 765 #1 ST1 11 ¾” Liner 13244’ md

12 ¼” Bi Center hole to 23244’ md 57 o


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Apr 2003


The well was then sidetracked with a 12¼" bi-center bit and drilled to 23244’ MD with similar parameters and practices. The hole angle on the sidetrack was ±57º. Based on the results from EzClean below, the cuttings bed height in the 12¼" hole was ±7”. The hole cleaning index was ±1, even in light of these thick beds. This is attributed to the use of the bi-center bit which provides a junk slot area of 50% in 12¼" hole. Again, the limitations of hole cleaning models should be kept in mind when using their results (refer to SECTION 4.3.4.4).


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Apr 2003


Both Hi-vis and Lo-vis sweeps were employed while drilling the sidetrack (± every 2000’). Based on the results seen below, the sweeps were ineffective in removing cuttings from the tangent section. Refer also to the details of the Hi-vis sweep pumped at a depth of 17260’ in the A5 well (EXAMPLE 11.1).


DEPTH

SWEEP

RESULT

14200’

?

No result Page 1

Apr 2003


16768’

140bbl Lo-Vis

No Result

18463’

Hi-Vis

?

21388’

150bbl Lo-Vis

?

23275’

140bbl Lo-Vis

Few cuttings

The mud weight was continuously increased through the section due to tight hole and stuck pipe (packed off). The problem was incorrectly diagnosed as wellbore instability. With a flowrate of 625 gpm and 50-80 rpm, very few cuttings would have been removed from the 12¼" tangent.


Page 1

Apr 2003


Once at TD, a single BU was pumped with no pipe rotation (see data below). As while drilling the section, little if any cuttings were seen coming back, which was attributed to the cleanliness of the hole. The bi-center bit was POOH successfully with only a few tight spots (due to large JSA). At this stage it was incorrectly assumed that the hole was clean.

Drill to TD

Circ BU

One BU, No Rotation

POOH

The first tool pusher logging run stood up at 17902’ MD. A subsequent cleanout run was made with a 10⅝" hole opener with the motor and MWD laid out to try and gain additional flowrate. Three additional tool pusher logging runs were made, all having problems with tight hole and excessive drag due to cuttings beds. After a cleanout run (which still failed to cleanup the hole), the 9⅝" liner was run, but stuck at 18075’ MD. The 9⅝" was eventually recovered and the well sidetracked again with similar results. On the third sidetrack, there was an added focus on hole cleaning including additional flowrate with 6⅝" drillpipe, and a dedicated backreaming run prior to running the casing. This sidetrack was successful. The following are the main learnings from this example: •

High angle hole cleaning requires different practices from those used on vertical wells.

•

Tight clearance casing programs have their benefits (e.g. oversize hole)

•

Sweeps are generally ineffective in high angle wells

•

Different bed heights are permissible depending on the operations (e.g. drilling, tripping, logging, casing)


Page 2

Apr 2003


1.1

BACKREAMING

In this example, one of the key learnings is the limited planning time that was available for this well to be drilled. High angle wells require adequate planning time and resources in order to be successful. The Ardennes HI A545 JA-2 was a last minute addition to the rig schedule. The rig had just finished a deep, vertical HPHT well in record time. However, the rig was still under contract, and the options were to stack it, or drill the Ardennes well (a high angle development well with high gas rate potential). Planning time was only 2 weeks, but this was considered as adequate as it was only 6800’ TVD, into mild geopressures, and on a record setting rig (vertical hole focus). 11¾” surface casing was set at 4300’ MD. 10⅝" hole was then drilled to 9167’ MD, at a maximum angle of 66 degrees, when loss circulation was experienced. The LWD confirmed the losses were at ±5100’ MD, and LCM treatments provide ineffective. An unplanned 9⅝" liner was run, and subsequently stuck below the weak zone at 6142’ MD. In the interest of not giving up ±3000’ of hole (± 2 days of drilling), the original 10⅝" hole was cleaned out with an 8½" bit (to 9167’ MD), before drilling ahead in 8½" hole to the planned TD of 11540’ MD.

9 5/8” liner stuck at 6142’ md

10 5/8” hole to 9167’ md 8 ½” to TD

66o


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Apr 2003



Page 3

Apr 2003


The flowrate was reduced to 332 gpm below the 9⅝" casing in an attempt to reduce ECD. At the reported drilling parameters the estimated bed heights would be 6” to 7” in the 10⅝" section, and 3” to 5” in the 8½" section (refer to EzClean results below).

At TD, one bottoms up was circulated and the interval was back reamed at 332 gpm, 90 rpm, at a rate of 30 FPM (7-9 stands/hour. The plot on the following page shows the surface parameters while back reaming in the 10⅝" section. Note the torque and pressure spikes, which are good indicators that the hole is packing off. At 6705’ MD, just after making a connection, the hole packed off. The rig reported that returns were re-established after working the pipe and backreaming was continue for an additional 5 feet where the drill string again packed off and was permanently stuck. A kick off plug was set below the 9⅝" liner and the interval was redrilled in 8½" hole at 540gpm and 90 rpm. The EzClean plot on the following page highlights the benefits of the improved parameters and hole size (1.5 – 3” beds). Additionally, a hole cleaning plan was prepared and agreed to by all parties. It called for a cleanup cycle at TD, with 4 x BU, plus a dedicated backreaming clean out trip with a minimum BHA (at reduced speeds). The rig crews were skeptical of the need for 4 x BU on the cleanup cycle, but report that cuttings returns only cleaned up after the fourth BU. A 7” production liner was successful run to TD.


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Apr 2003


Torque Spikes SPP Spikes

BR ~ 30 FPM Pack off 6705’ MD


Page 1

Apr 2003



Page 3

Apr 2003


The following are the main learnings from this example:

•

Adequate planning time is required for high angle wells. Integrated hole cleaning plans and crew training is critical.

•

“Sometimes you must go slow to go fast”

•

○

Plugging back the 10⅝" hole to start with would have significantly helped

○

Cleanup cycles were not viewed as productive work

○

Backreaming was too fast

Backreaming should be avoided in high angle holes, but when necessary, needs to be done carefully with appropriate practices to minimize risks. In this case: ○

No cleanup cycle prior to commencing backreaming

○

Backreaming too fast and with inadequate parameters

○ Ignored the warnings (torque and pressure spikes) FURTHER EXAMPLES: The PWD logs on the following page are from the 12¼" section of an 82º well drilled in the North Sea. The well was drilled with a steerable assembly down to a depth of 20783’, with a flowrate of 850 – 950 gpm and 60-120 rpm. A 6⅝" x 5½" tapered drillstring was being used. The mud was an 11.8ppg Petrofree SBM with a 6 rpm reading less than 10. The overall ROP was controlled at 100 ft/hr with instantaneous rates up to 150 ft/hr. While drilling at 18855’, the well packed off and was eventually worked free with rotation. A further 14 days were then required to get out of hole. This included a significant amount of backreaming as shown in the short sample of PWD data on the following page. Numerous pack-offs occurred during this time, with large ECD spikes being seen on the formation. This was only discovered at a later date in a post well review, when the time-based PWD logs were studied. This hole section was eventually lost after drilling to TD and performing a wiper trip prior to running casing. The loss of the wellbore was attributed to wellbore instability induced through the backreaming process (ECD cycling of formations).


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Apr 2003



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Apr 2003


1.1

INTERMEDIATE HOLE CLEANUP

The hole cleaning performance on the Ursa A5 was discussed in detail in EXAMPLE 11.1. The 14 ½” interval was drilled with a ±53º tangent to 17260’ MD, where an 11 ¾” liner was run. Several experiments were made in drilling this hole interval, include the use of bladed drill pipe, and the application of an intermediate backreaming run.

13 5/8” shoe at 9875’ md

14 ½’ hole at 17260’ md

53 o


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Apr 2003



Page 3

Apr 2003


Based on the EzClean modeling shown below, the estimated bed height in this interval was 9-10 inches. This was a concern when drilling this interval. As a result it was decide to pilot test an intermediate back reaming run to see what effect it may have on the cutting beds and drilling conditions.


Page 5

Apr 2003


The plot on the following page shows the PWD EMW vs MD for the 14½" interval on A-5. The ROP prior to the intermediate backream run was ±75 fph. A total of 24 hrs was required to backream the hole from 13200’ MD to the shoe, and trip back to bottom. When drilling re-commenced, ECD’s were reduced and this permitting the ROP to be increased to ±100 fph. However, after 700’ was drilled the equilibrium cuttings beds were re-established and the ROP was again reduced to 65 fph to control ECD. In addition to the rig cost for the backreaming time, there is the added risk associated with performing an additional and unnecessary backreaming run.


Page 7

Apr 2003


The main lesson to be learnt from this example is that an intermediate cleanup trip is generally not required if the Hole Condition Monitoring (HCM) process is being used correctly. This will allow the bit to stay on-bottom drilling at the optimum ROP for hole cleaning and ECD management.


Page 1

Apr 2003


1.2

EFFECTS OF PIPE ROTATION ON HOLE CLEANING AND ECD

The plot below shows the directional plan for the Princess Appraisal Well, MC 766 #1. The well was drilled to a TD of 31753’ MD. A 7⅝" liner was run and stuck at 28801’ MD, due primarily to wellbore instability. The 9⅞" open hole was eventually abandoned with cement plugs, and the well was sidetracked as bypass #1. The kick off plug was soft, and so the 7” directional BHA was washed to ± 29050’ MD, before a ledge was encountered, and sliding to kick off commenced.

7 5/8” Liner at 28801’ MD


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Apr 2003


The plot on the following page shows PWD and surface parameters for the kick off of MC 766 #1 BP1. The mud was NovaPlus with a surface mud weight of 14.8 ppg. Notice the evidence of sag in the mud, which is primarily evident by the elevated static mud weights on connections in the “conditioning by circulating” section. After conditioning the hole, the BHA was slid for ±12 hrs (i.e. poor hole cleaning). Notice the increase in ECD and static mud weight while sliding. After the slide, pipe rotation is again commenced, and after an initial increase (as expected), the ECD’s begins to come down. Equally important is the fact that the static mud weights drop to more of an expected of 0.2 to 0.3 ppg over surface mud weight.


Page 3

Apr 2003


Depth (ft MD)

Rotary Speed (rpm)

Conditioning by circulating

Sliding

Flow In (gpm)

ECD (ppg)

Downhole Mud Weight

Surface Mud Weight 14.8 ppg

Expected Downhole Mud Weight 15.0 ppg (SMW + Compressibility)

ECD

Rotary Drilling

MC766#1ST1 (22/Apr/2002)

The main lessons to learn from this example are: Hole Cleaning Best Practices Manual Rev 0

Page 1

Apr 2003


• •

Hole cleaning is basically non-existent without rotation (build up of cuttings and ECD). Rotation after a long period of sliding will initially cause an increase in ECD as the cuttings are moved up into the flow stream. However, the rotation will result in improved hole cleaning and therefore should lower ECD with time (depending on the specific wellbore conditions.


Page 1

Apr 2003


FURTHER EXAMPLES: The following examples demonstrate the impact of drillstring rotation on hole cleaning in larger hole sizes:

•

On a 75° inclination well, drilling 10⅝" hole at 600 gpm. A sidetrack was performed with a motor with a large bend limiting string to 40 rpm. There were very few cuttings over the shakers. Before tripping out, 4 x BU were circulated at 100 rpm, and a slight improvement was seen in the cuttings load on shakers. After tripping back in the hole with a rotary assembly, the well was circulated at 120rpm. At 2 x BU, the shakers were flooded with cuttings, and remained full as the well was drilled ahead with 120 rpm.

•

Refer to Example 1 in EXAMPLE 11.10.

The following examples demonstrate the impact of drillstring rotation on ECD:

13.7 •

The plot below shows an example of a typical connection from the 12¼" interval of the Ursa A-10 well. The ECD impact from simply increasing the rpm from 0 to 120 is clearly seen (± 0.1ppg).

13.6


Page 1

Apr 2003


•

On this high angle well (80º+ inclination), an ECD tests was performed with the PWD prior to drilling out the 9⅝" shoe set at 20,800’ MD (i.e. no cuttings effect). Note that the WBM was being used, with a mud weight of 8.4 ppg at the time of the testing (PV/YP =12/23). A full string of 5½" drillpipe was used with a tapered 11¾” (top 5650’) x 9⅝" casing string. These results show that rotation actually has a greater impact on ECD than flowrate. RPM

•

350 GPM

400 GPM

450 GPM

ECD (PPG)

DHP (PSI)

SPP (PSI)

ECD (PPG)

DHP (PSI)

SPP (PSI)

ECD (PPG)

DHP (PSI)

SPP (PSI)

0

10.12

3006

1300

10.17

NA

1510

10.2

NA

1750

40

10.25

3047

1360

10.4

3086

1600

10.53

3127

1800

60

10.37

3085

1370

10.5

3117

1630

10.6

3153

1840

80

10.42

3103

1380

10.54

3140

1650

10.64

3167

1840

100

10.41

3107

1394

10.58

3152

1650

10.67

3177

1830

120

10.42

3108

1390

10.59

3157

1650

10.68

3181

1840

On the following well in this same project, ECD tests were again performed prior to drilling out the shoe at 22,818’ MD. This time SBM was being used, and a tapered string with 4½" (8363’) x 5½" drillpipe was run. A full string of 9⅝" was run to surface. The mud weight was 9.3ppg at the time of testing (PV/YP = 17/12). Again, these results show that rotation has a greater impact on ECD than flowrate.

RPM


ECD (PPG) 280 GPM

365 GPM

437 GPM

0

10.24

10.35

10.52

40

10.34

10.54

10.74

80

10.44

10.64

10.81

120

10.49

10.71

10.91

Page 1

Apr 2003


1.1

BOREHOLE INSTABILITY AND HOLE CLEANING

11 ¾: Liner at 17600’ MD 10 5/8” hole to 27600’ MD ~ 62 o

URSA A10 STK 1 is a good example of the detrimental effect of wellbore instability on hole cleaning. The A10 was sidetracked below an 11¾” liner shoe at 17600’ MD. A 10⅝” hole was drilled to 27600’ MD where the BHA was tripped at a planned logging point. The average inclination in the 10⅝” hole interval was ±62º. The interval was drilled with a 12.6 ppg SBM. Drilling parameters were 750 gpm and 130 rpm. There was no evidence of any problems with wellbore instability or hole cleaning while drilling the interval.


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Apr 2003


Downhole Equivalent Mud Weight (ppg)

14.1 ppg

TVD (ft)

13.0 ppg

Drilling

Drilling Margin

POOH

Clean up Cycle


Page 3

Apr 2003


Once A10 STK 1 reached the planned logging depth of 27600’ MD, a 2-3 bottoms up clean up cycle was performed at 750 gpm and 130 rpm. The drillpipe was then tripped on elevators. The graph above shows the PWD equivalent mud weight verses TVD while drilling and tripping on A10 STK1. The blue data is the PWD data collected while drilling. One can see that although the surface measured mud weight was 12.6ppg, the effective down hole mud weight with pumps off was about 12.9 ppg. There is about 0.2ppg increase in effective down hole mud weight due to mud compressibility. The maximum ECD range from 13.6 to 13.8ppg while drilling. The opaque blue shows the target range for the effective down hole mud weight based on STABOR prediction to avoid borehole instability (e.g. cavings) and/or fracturing the formation . This range was 13.0 to 14.1ppg. Notice while drilling and while backreaming during the clean up cycle that the actual down hole mud was within 0.2 to 0.3ppg of that mud weight recommended to prevent the borehole instability. However, the effective down hole mud weight dropped to 12.4 to 12.5ppg when the drill string was tripped conventionally. At 13500’ TVD (19300’ MD), the drill string began dragging significantly on the trip. For the remainder of the trip, the drill string was backreamed out of the hole. Packing off was occurring while back reaming the upper part of the hole. The pack off is evident through the pressures spikes on the ECD verses TVD plot from 13500’ to 13200’ TVD. This packing off was due to a massive cavings load (dune) being moved past gauge sands.


Page 5

Apr 2003


A10 STK 1 was underreamed to 12¼” with a 12.8ppg mud and a 9⅝” drilling liner was run. The 9⅝” liner stuck ±900’ off bottom at 26707’ MD. The borehole instability which caused the packing off and prevented the 9⅝” liner from reaching TD is clearly evident in the caliper on the left. The maximum hole size of ±20” was measured in the shales while the sands remained nearly gauge at 12¼”. This oversized hole was very difficult to clean and the gauge sands provided ample opportunity for the cuttings to pack off while back reaming, and prevented the liner from reaching TD. The log on the right shows MWD density derived calipers from A10 ST1 BP1 from the same interval as the caliper on the left. A10 STK1 BP1 was drilled with a 13.0ppg mud weight. All well operations were focused on maintaining the equivalent down hole mud weight within the target mud weight envelope. This included pumping and back reaming out the hole instead of straight pulling out of the hole to avoid excessive swabbing. The caliper clearing shows that these practices resulted in a nearly gauge hole even after two weeks. The gauge hole greatly improves the ability to clean the hole and reduces the risk of trouble (e.g. packing off, stuck drill pipe, stuck casing, etc).


Page 3

Apr 2003


1.2

T&D MONITORING WHILE DRILLING

Various examples of T&D monitoring charts while drilling are shown on the following pages.

A10ST1 Princess 10 5/8" hole section 3-27-02 300

350

400

450

500

550

600

650

700

750

800

18000

18000

Started backreaming (24740 ft.) full stand on connections! Note drop in p/u weights and ECD also dropped following this 20000

20000

22000

22000

24000

24000

26000

26000

28000

28000

30000

30000 12

12.2

12.4

12.6

12.8

13

13.2

13.4

13.6

13.8

S/O cal. (0.13/0.08)

S/O (act.org.)

S/O (act) st #1

Rot (cal.)

Rot.(act.org.)

Rot. (act)st#1

P/U cal.(0.15/.16)

P/U (act.org.)

P/U (act) st #1

ECD1


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1.3

T&D MONITORING WHILE TRIPPING AND RUNNING CASING Various examples


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1.4

ECD EFFECTS


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Apr 2003


The following plots taken from actual wells demonstrate how various operations can impact ECD.

Cuttings Pick Up Sliding

ECD SPIKE WHEN BEGIN ROTATING AFTER SLIDING:

ROTATION BEGINS AFTER SLIDING

ECD SPIKES AS CUTTINGS DUNE IS PICKED UP AFTER SLIDE

PIPE MOVEMENT, FLOWRATE AND RPM IMPACT ON ECD:


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Apr 2003


Gel Breakdown

ECD SPIKES DUE TO ROTATION AND CIRCULATION AFTER CONNECTION:

ECD SPIKES AS

GELS BREAK FLOW WITH AFTER EACH CONNECTION NO ROTATION

FLOW WITH ROTATION


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Apr 2003


1.5

TRIPPING PRACTICES

The examples provided below highlight poor tripping practices. The comments in (red) provide a discussion of the problems and possible solutions. EXAMPLE 1: On this deepwater well in the GOM, a 20” hole section was being drilled using an 8¼" AutoTrak tool, with a 14¾” bit and 20” NBR. The section was drilled to a TD of 9285’ MD, at an average of 50-60 ft/hr, with ±35º on bottom. An SBM was being used and had poor low-end rheology (thin) for hole cleaning. The drillpipe was 5⅞".

•

At TD, a 100 bbl weighted sweep (1.5ppg over the mud weight) was pumped and the well circulated for 4 hours at 100 rpm until the shakers were clean. (The shakers were most likely clean as the cuttings were being bypassed on the low side due to inadequate rotary speed).

•

An attempt was made to POOH with the hole tight from 9285’ (TD) to 9240’. Backreamed from TD to 7527’ at 100rpm and 600gpm. The hole was tight with showed signs of packing off. Pulled two stands ok without pumping or rotating. RIH and took weight (20 k lbs) at 8912’. Washed and reamed to TD with hole again tight trying to pack-off. (Tight hole straight after picking up is a good indication of the ineffectiveness of the previous sweep at low rpm in this higher angle section of the hole. Inadequate parameters were used for backreaming which did little to move cuttings out of the hole. Also, at this angle it would not have taken cuttings long to fall back down the hole)

•

On bottom again, increased rpm to 150 while pumping a 100 bbl weighted sweep (3 ppg over mud weight) and circulating bottoms up. Had to reduce flowrate due to shakers overloading with cuttings. Pumped a second sweep and continued to clean up hole with 150 rpm and 1060 gpm (riser boosted at 500 gpm). (Finally the cuttings are being removed from the hole with a combination of high rotary speeds, increased flowrate, and the weighted sweep)

•

Backreamed out of the hole to 6948’, with 120 rpm, 830gpm and 4 stands per hour. Hole condition good. RIH back to bottom with the bottom 40’ of 14¾” hole tight. Circulated another 100 bbl weighted sweep at 150rpm and a small amount of cuttings over the shakers. POOH ok with no backreaming. (A cleaner wellbore has now allowed “safe” backreaming with improved parameters. Final trip out confirms the hole is adequately clean for tripping)


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EXAMPLE 2: On a well in Trinidad, a 12¼" hole section was being drilled with a tangent section of ±52º, from the EOB at ±3450’. The section from the 13⅜” surface casing shoe at 5713’ to 11414’ had been drilled with a rotary Andergauge assembly and a 13” NBR. This was followed by an 8¼" AutoTrak tool for drilling the subsequent build to horizontal (no NBR). A 10.2ppg SBM was being used and the drillpipe was a tapered 6⅝" x 5½" string. While drilling, the flowrates ranged between 960 – 1060gpm and rpm between 130-150. ROP’s were not particularly high ranging from 60-100 ft/hr.

•

Due to some pump problems the hole was circulated with a lo-vis / hi-weight sweep at 13459’ (1060gpm, 150rpm). A wiper trip was conducted back to 11300’ and no tight spots were encountered on the trip out or in. (The hole cleaning environment while drilling was very good with 100% rotary, high rpm and flowrate. The circulation at this depth was likely 1 x BU, and adequate to reduce the cuttings beds to a safe height to trip up to 11300’ without problems. If the BHA was tripped further, problems may have been encountered).

•

The well was drilled ahead to 13805’ at 1050 gpm and 150 rpm. Towards the end, pump problems again reduced the flowrates to 960gpm. Additionally T&D had been increasing (torque increased from 35 – 43 k ft-lbs). The decision was made to POOH. (The increasing torque may have been an early indicator of hole cleaning problems, or alternatively may have been due to a formation change as a reduction was also seen in ROP).

•

Prior to tripping, an estimated 3 x BU was circulated while pumping a 50 bbl lo-vis / 50 bbl hi-weight sweep (unknown parameters). No excess cuttings were noted when the sweep returned and the well was assumed to be clean. (Again the ineffectiveness of sweeps in high angle holes is highlighted. Even if a good flowrate and rpm were used while performing this cleanup cycle, the fact still remains that limited cuttings were returned. More circulation was required, as the following operations prove there were still a significant volume of cuttings in the hole).

•

The BHA was POOH to 10721’ where excessive drag was encountered (35 k lbs). An hour was spent backreaming through the tight area (960 gpm, 150 rpm). The torque increased from 25 to 35 k ft-lbs. The BHA was then tripped a further ± 200’ before again encountering excessive drag (35 k lbs). A single BU (1.5 hours) was circulated while backreaming through the tight area. The BHA was then tripped a further ± 200’ before again encountering excessive drag (35 k lbs). After backreaming 210’ in 30 minutes (±5 stands per hour), the hole packed off at 10164’ and was jarred free after 2 hours. (It is clear from the above description that a sufficiently thick cuttings bed was pulled into starting at 10721’. All that resulted from backreaming the first two times was to shift the cuttings bed up the hole ±200’. However, backreaming the last time was too fast with the BHA moving 210’ up the hole in 30 minutes, where the previous two backreaming runs had only moved the cuttings 200’ in 1 – 1.5 hours. The correct procedure would have been to stop and circulate the cuttings out of the hole after they were first pulled into).


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Apr 2003


•

After working the string free, another sweep was pumped with a single bottoms up (955 gpm, 150 rpm), and no excessive cuttings were seen. The BHA was backreamed to 9790’ (955 gpm, 150 rpm) at a slower rate of 2 stands per hour. Another sweep was pumped with a single BU and again limited cuttings were seen over the shakers. The BHA was then backreamed to 8450’ at 3 stands per hour. Some packing off was seen with the string stuck once. Another sweep was pumped and a single BU circulated with 150 – 175 rpm, 1050gpm and excessive cuttings were seen over the shakers. After backreaming to 8075’, the auger at the shakers failed and the trough backed up with cuttings. For 19 hours the string was reciprocated without pumping while the auger was repaired. (The continual process of backreaming, sweeps, and circulating 1 x BU, moved the cuttings up the hole, but not out of the hole. The packing off while backreaming is likely to have induced the wellbore stability seen later in this section. It is also likely that reciprocating the pipe without circulation while repairing the auger, would have aided the cuttings in avalanching back down the hole below the BHA)

•

The process of backreaming and pumping sweeps was continued back to the 13⅜” shoe at 5713’. Prior to entering the shoe, approximately 5 x BU were pumped with several sweeps at 955 gpm and 150 rpm. No problems were seen POOH after this. The BHA was clean. (Finally the hole is cleaned up properly with the majority of cuttings above ±8000’ now removed from the wellbore. Below 8000’ are the cuttings that avalanched back down the hole when reciprocating for 19 hours without pumping. Additional cuttings may also now be in the hole due to induced wellbore instability from the packing off while backreaming).

•

An Autotrak assembly was run back in the hole. Static mud losses at the shoe are reported as 1.5 bbls/hr with the mud weight 10.1ppg. The string first took weight at 7522’ (20 k lbs). From this point down to 8407’, the string was washed and reamed down with continual high torque spikes, pack-offs and stuck pipe. The mud weight was increased to 10.3 ppg in an effort to reduce the perceived well bore instability problem. This assembly was eventually worked out of the hole and found to have significant damage to the AutoTrak (likely due to downreaming and jarring with stuck pipe). (The cuttings beds were still in the hole and resulted in the significant problems seen as attempts were made to work through them. Compounding the problem would have been the AutoTrak assembly with very low flow-by area around the steering ribs and LWD tools).

•

A simple cleanout assembly with no MWD was then RIH. The first tight hole was encountered around 8409’. After cavings were reported to be coming over the shakers, the mud weight was raised to 11 ppg. After washing and reaming to 8683’, a gyro survey was run which confirmed that the hole had been sidetracked. The wellbore was plugged back and sidetracked from the 13⅜” shoe. (Although there may have been wellbore instability by this stage, it is highly probable that this was induced by the poor practice during this trip, rather than being the root cause of the problems)


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•

The 12¼" sidetrack was redrilled with several changes. The mud weight was started at 11 ppg and increased to 11.8 ppg. However significant losses resulted in the weight having to be reduced to 11.5ppg. Practices were modified ○

Higher rpm (150 -160), flowrates were often limited due to the losses

○ Sufficient cleanup cycles were pumped (i.e. > 1 x BU) ○

When tight hole was encountered on trips out, the string was lowered back down the hole and circulation or backreaming was used at this point (i.e. not starting rotation in the middle of the cuttings bed)

○ The ribs on the AutoTrak were retracted when tripping •

At TD of the 12¼" sidetrack, two 15ppb LCM sweeps were pumped while circulating an estimated 4-5 x BU. Good cuttings were seen over the shakers. The trip out of the hole was good other than a few tight spots after pumping out with no rotation, and backreaming. Tight hole was also seen on a wiper trip to TD and back to the shoe. The 9⅝" casing was run to TD ok. (Although the practices used on the sidetrack were improved, some minor problems were still seen, most likely due to the pumping out and backreaming)


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1.1

RIG CAPABILITY

The example shown in the table below highlights the fact that a large rig is not necessarily required for drilling large high angle wells. The larger rig has enough "grunt" to simply overcome many of the difficulties with brute force. However, for the smaller rig, a focused hole cleaning design approach is critical to work within the limitations of the rig.

ESSO AUSTRALIA LTD

BP WYTCH FARM

FORTESCUE A-29

M5

SUMMARY: Although the TD and throw of this well is not particularly

At one time, this well held the world record for ERD. Although

significant by today’s standards, the well exceeded the rigs rated

Wytch Farm is generally not a good project to benchmark against

capabilities. The well was drilled and completed with 12¼" hole

because of several unique factors that do not apply to most high

to TD. This well set several regional depth, reach and

angle wells, it is still a good comparison for the rig capability

performance records and is believed to have set a world record

used.

for the longest high angle well with only 2 casing strings. K&M and Esso were awarded an Engineering Excellence Award for

Although the final 8½” TD is significantly larger than the A-29

the achievement, given the limited rig capability.

example, the 12¼” TD’s are very similar. Given that the 12¼” section is often the most difficult part of a high angle well to drill, the two wells provide good benchmarking comparisons.

WELL DETAILS:

• 8½” TD = 8700m MD (28,500 ft)

• TD = 6210m MD (20,375 ft).

• Throw = 8000m (26,250 ft)

• Throw = 5249m (17,221 ft)

• +/- 82 tangent section, to horizontal

• 79 dropping to 45 (S-turn profile)

• Includes 2000m (6,500 ft) horizontal section

• 17½” was drilled to 1500mMD (4,921 ft), and

• 17½” to 1300m (4,250 ft), 12¼” to 6700m

12¼” drilled to TD. • Total days (drill and complete) were 53.4 days.

(22,000 ft), 8½” to TD. • Total time to drill to 12¼” TD 30-35 days.

Total days to 12¼” TD = 39 days. RIG CAPABILITY:

Additional 70-80 days to drill the 8½” horizontal section • TDS-4 top drive

• TDS-4 top drive (38,800 ft-lb.)

• 3 x 1600 HP pumps

• 2 x 1600 HP pumps

• 6000 HP electrical power.

• Electrical power = 4500 HP

• 6⅝” drillpipe is used for 17½” hole

• 5½” drillpipe with HT-55 connections

• 5½” x 6⅝” drillpipe is used for 12¼” hole, (5½”

• Maximum surface pressure - 3,600 psi • (flowrate at 12¼” TD was ±700 gpm)

drillpipe has 60,000 ft-lb. connections) • Low Tox SBM is used for 12¼” and 8½”

• Drilling fluid = Ester SBM • Racking capacity = 5,000m of 5½" drill pipe

sections. • Racking space for 9,000m (29,500 ft), with 50%

• Derrick load = 1,000 kips

each of 5” and 5½” drillpipe. • Nominal 2.3 million tons mast capacity.


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Apr 2003


The following example again highlights what can be achieved with a limited rig capability, but a focused hole cleaning design approach.

EXXON HONDO H-42 SUMMARY: The H-42 was drilled from the Hondo platform in 1999. It was a challenging well with the limited rig capability. The rig was upgraded from a cased hole workover rig to the configuration below.

WELL DETAILS: • 14¾” to 7500’ • 10⅝” to 17500’ • 7⅝” to 19555’ (TD) • Tangent angle 75º RIG CAPABILITY: •

2 x 1000 HP pumps (620 gpm max flowrate)

•

TDS 9S (24, 000 ftlbs)

•

500,000 lbs mast

•

700 bbl mud system

• 5” drillpipe


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Apr 2003


The example below shows a detailed evaluation of the power consumption for various operations in a 12¼" interval on a high angle well. Power Consumption: O1 (12¼" Hole Section) HOLE: MD: TVD:

Rotary Horsepower

12¼ in. 5867 m 2642 m

efficiency:

0.9

RHP =

Torque x rotary speed eff x 5250

DHP =

Hookload x trip speed eff x 33,000 x sheave eff

HHP =

Pressure x flow rate eff x 1,714

Drawworks Horsepower efficiency:

0.9

Hydraulic Horsepower efficiency:

0.9

Sheave Efficiency: 0.842 8 lines 0.811 10 lines 0.782 12 lines

Horse Power Summary (Worst Case) OPERATION

Torque

Tension*

Overpull

Rotary

Trip Speed

ft.lbs.

lbs.

lbs.

rpm

ft./ min.

Rotating off bottom (ROB)

30,000

270,000

150

Rotate into Hole (RIH)

30,000

270,000

150

Rotary Drilling (RD)

35,000

270,000

Backreaming (BR)

35,000

270,000

100,000

952

40

1,100

4,500

952

150

10

1,100

4,500

150

40

1,100

4,500

60

Slide Drilling (SD)

160,000

10

Trip out of Hole (TOH)

400,000

Running Casing - TIH

160,000

Running Casing - TOH

700,000

MAXIMUM RIG HORSEPOWER REQUIREMENT

POWER Rotary

4,500

180,000

100,000

psi

1,100

Trip into Hole (TIH)

100,000

Hydraulics gpm

Hoisting*

Hydraulics Aux Equip 500

4,661

465

3,209

500

5,126

1,111

116

3,209

500

4,936

1,111

637

3,209

500

5,457

465 1,200

5,000

TOTAL

3,209

69

3,890

500

965

500

4,458 1,792

60

1,292

500

60

413

500

913

60

2,067

500

2,567

6,003

hp

4,476 kw

Factor of Safety: 1.1

* Includes 80 kips block weight


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1.1

TORTUOSITY

EXAMPLE 1: The following example highlights the hidden tortosity that may not be seen if you only get a survey every 100’. This example is from an 8½" horizontal interval drilled with both motors and RSS’s. By monitoring the continuous surveys, the micro-doglegs in the wellbore were clearly seen.

91 90.5 Hole Cleaning Best Practices Manual Rev 0

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Apr 2003


EXAMPLE 2: RSS’s will generally provide a significantly smoother wellbore than those drilled with conventional motors. The example below is from three wells drilled in the Cook Inlet in Alaska. Note that the conditions on these wells were identical, other than the use of an RSS in the 8½" hole (2500’ to 8523’ MD) on well #3. The tortuosity difference is obvious.

0

2000 Hole Cleaning Best Practices Manual Rev 0

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Apr 2003



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1.2

CUTTINGS BED MODEL

The following demonstration comes from the Expro Stuck Pipe prevention course. A cuttings bed sticking model was set up with a 100 mm diameter Perspex tube representing a 1/3rd scale model of a 12¼" hole. The model operates with no fluid or fluid flow. The dry bed is obviously not the case in reality, however, the actual forces, distances and times will not change dramatically. The model is sufficient for illustrating basically what is happening down hole while pulling out without back reaming or circulating. The model is used in a horizontal situation to simplify the operation of the model. This is representative of the best case for hole cleaning as no avalanching of cuttings is occurring. The

BHA is made up of six component parts fabricated from Nylon and machined to approximately 1/3rd scale: •

The thinnest section of the model seen at the top of the picture is the 30ft section of 5" Drill Pipe.

•

The next section is a 32-ft section of 8" drill collar. The alternative drill collar (absent from Photo) is a 35ft section of 9.5" collar.

•

The top stabilizer has 12⅛" (i.e. slightly undergauge) blades on a 10-ft long, 9.5" OD body, and is a straight bladed type.

•

The bottom stabilizer is a spiral blade stabilizer (again 12⅛" OD blades with a 10-ft long 9.5" body). The outer diameter of the stabilizers is painted solid red or black, and the body area is hatched in red to enable clear identification of the models various components once inside the Perspex tube.

•

There are two bit models, one PDC and one blank tricone body. The two bit models can be used to illustrate the relative importance of bit flow by area between bit types, however, in this case only the PDC model is used.

The solids in the tube are also 1/3rd scale, made from two different sizes of salt (sea salt at 2-4mm and table salt at 0.5-1mm). The volume of cuttings is approximately 5-10% by volume (scale 1.5” cuttings bed). The picture below shows the drillpipe / drillcollar crossover “shoveling” a significant pile of cuttings ahead of the change in cross sectional area. This is a scale distance of 40’ above the top stabilizer. Hole Cleaning Best Practices Manual Rev 0

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After pulling the BHA a further scale distance of 6’ into the model, the pile of cuttings ahead of the drillpipe / drillcollar connection can be seen to increase in height.

The top stabilizer enters the tube and cuttings begin to build up.


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Apr 2003


As the BHA is drawn further into the tube the cuttings can be seen to build up around the stabilizers


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Apr 2003


The straight blade stabilizer has less of a shoveling effect than the spiral stabilizer. The difference in the thickness of the cuttings bed after the BHA has passed can be seen in the picture below. Below the stabilizer (to the right of it) very few cuttings remain on the low side of the tube.

As the BHA is drawn further through the tube a significant pile of cuttings builds up in front of both stabilizers. Again the bigger pile is in front of the spiral stabilizer.

The gap at the top of the annulus has now closed and the stabilizer if effectively packed off with cuttings. The overpulls now increase rapidly and the string will become stuck in a short time. Hole Cleaning Best Practices Manual Rev 0

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Apr 2003


Here an overview of the two stabilizers and the cuttings forming around them can clearly be seen.

The picture below shows how the cuttings are dragged ahead of the stabilizers leaving very few cuttings behind to cause problems at the bit. If the flow by area of the stabilizer were not as restrictive then the piling of the cuttings would likely occur at the bit. Due to the lower flow by area of the bit, it is likely that the piling up of cuttings would occur over a shorter distance.


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Apr 2003


So what are the learnings from this model: •

Illustrates how the cuttings can build up in front of stabilizers and other changes in cross sectional area.

•

Highlights the dangers of jarring up when stuck while pulling out of the hole.

•

The model is aimed at situations where gauge or close to gauge hole exists. Over gauge hole will give fewer problems with cuttings build up as the flow by area around the BHA components will effectively be far greater.

•

The depth of a cuttings bed that will cause problems while POOH is surprisingly small (5%-10% Volume).


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SEPCo 20Hole Cleaning 20Manual 1

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