STUCK PIPE MANUAL
VOLUME 2
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PREVENTION IN THE PLANNING & EXECUTION PHASES.
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TABLE OF CONTENT 1. PLANNING PHASE........................................................................ 5 1.1. 1.2.
Well Engineering Management System (WEMS) ........................................... 6 Risk identification – offset well analysis. .......................................................... 7
1.2.1. 1.2.2.
Stuck Pipe Triggers – how can you recognise the hazards?.............................. 8 Chance of getting stuck?.......................................................................................12
1.3.1. 1.3.2. 1.3.3.
Casing Design Examples .........................................................................................14 Expandable Tubulars. ..............................................................................................17 Hole Size: ....................................................................................................................18
1.4.1. 1.4.2. 1.4.3. 1.4.4. 1.4.5. 1.4.6.
Hole cleaning in vertical wells (<35deg)..............................................................22 Hole Cleaning In Deviated Wells (>35deg).........................................................24 How do we achieve good hole cleaning in a directional well? ....................28 Pipe Rotation.............................................................................................................28 Flow Rate....................................................................................................................31 Equilibrium Bed Height.............................................................................................34
1.5.1. 1.5.2.
Trajectories.................................................................................................................38 Directional Strategies...............................................................................................42
1.6.1. 1.6.2. 1.6.3.
Conventional Steerable Assemblies: ....................................................................45 Rotary Steerable Systems (RSS)..............................................................................48 Drilling tools and Equipment...................................................................................49
1.7.1. 1.7.2. 1.7.3. 1.7.4.
Vertical wells - Hole cleaning................................................................................55 Deviated & High Angle wells..................................................................................55 Differential Sticking...................................................................................................59 Reactive/time dependent shales. ........................................................................59
1.8.1. 1.8.2. 1.8.3. 1.8.4. 1.8.5.
Hydraulic capability:................................................................................................62 Rotary capability: .....................................................................................................64 Power Capability:.....................................................................................................68 Hoisting capability....................................................................................................68 Solids Control Equipment: .......................................................................................68
1.9.1. 1.9.2. 1.9.3. 1.9.4. 1.9.5. 1.9.6. 1.9.7. 1.9.8.
Osprey Risk .................................................................................................................80 Drilling Office. ............................................................................................................82 Modeling Hydraulics ................................................................................................82 Modeling Swab and Surge.....................................................................................84 Drill Viz: - 3D Visualization. .......................................................................................86 Rocksolid – Wellbore Instability Analysis ...............................................................87 Stuck Pipe Analysis and Interactive Diagnostic tool – SPAID...........................88 Sticking Risk Assessor for wireline jobs? .................................................................89
1.3.
1.4.
1.5.
1.7.
1.8.
1.9.
Hole Cleaning:.................................................................................................. 21
Directional Planning ........................................................................................ 38 Directional Assemblies. ................................................................................... 45
Drilling Fluid Selection. ..................................................................................... 55
Rig sizing and capability. ................................................................................ 62
Software & Modeling Tools. ............................................................................ 79
2. REAL TIME ANALYSIS – HOW TO MONITOR THE PLAN? ........... 91 2.1. 2.2.
Introduction ...................................................................................................... 92 Surface measurements - Rig Floor measurements...................................... 93
2.2.1. 2.2.2.
Drilling Parameters....................................................................................................93 Torque & Drag Analysis............................................................................................97
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1.6.
Casing Design/Hole configuration: ............................................................... 14
2.3.
Downhole Measurements Indicators and Signals ..................................... 102
2.3.1. 2.3.2.
Downhole Weight on Bit. ......................................................................................102 Annular Pressure while drilling (APWD). ..............................................................102
2.4.1. 2.4.2.
PERFORM ..................................................................................................................106 Stuck pipe Indicator – SPIN...................................................................................110
2.4.
Real Time Software Packages...................................................................... 106
3. BEST PRACTICES....................................................................... 113 3.1.
Communication............................................................................................. 114
3.1.1. 3.1.2. 3.1.3. 3.1.4. 3.1.5. 3.1.6.
Introduction: ............................................................................................................114 Pre-Spud Meeting...................................................................................................114 Pre-Section meeting ..............................................................................................115 Pre-Job Meeting .....................................................................................................115 Pre-Tour Meeting ....................................................................................................115 Handover on the Drill Floor ...................................................................................115
3.3.1. 3.3.2. 3.3.3. 3.3.4.
Introduction .............................................................................................................118 Drilling........................................................................................................................118 Hole Cleaning pills..................................................................................................122 Circulating Prior to Tripping ..................................................................................123
3.4.1. 3.4.2.
Connection Practices:...........................................................................................126 Surveying - Stuck Pipe Avoidance While Surveying ........................................127
3.5.1. 3.5.2. 3.5.3.
Considerations Prior To Tripping ...........................................................................129 Considerations During Tripping ............................................................................129 Reaming and back reaming. ..............................................................................130
3.7.1. 3.7.2.
Swelling Shales. .......................................................................................................138 Cavings....................................................................... Error! Bookmark not defined.
3.2. 3.3.
3.4.
3.6. 3.7.
Connections & Surveying ............................................................................. 126
Tripping ............................................................................................................ 129
Differential Sticking ........................................................................................ 135 Problematic Shales ........................................................................................ 138
4. IDENTIFYING & FREEING STUCK PIPE ...................................... 148 4.1.
Stuck Pipe Identification ............................................................................... 149
4.1.1. 4.1.2. 4.1.3.
Stuck Pipe mechanism Identification Worksheet.............................................149 Stuck Pipe Summary Tables:.................................................................................151 Stuck Pipe Identification Trees .............................................................................153
4.2.1. 4.2.2. 4.2.3.
Solids Induced - First Actions ................................................................................161 Differential Sticking.................................................................................................164 Mechanical & Well Bore Geometry....................................................................170
4.3.1. 4.3.2. 4.3.3.
Jars ............................................................................................................................171 Accelerator Description........................................................................................174 Jar and Accelerator Positioning..........................................................................175
4.2.
4.3.
First Actions to free......................................................................................... 161
Jars & Accelerators........................................................................................ 171
5. STUCK – POINT OF NO RETURN. .............................................. 177 5.1.
Free point Indicator & Backing-off .............................................................. 178
5.1.1. 5.1.2.
Free point Indicator................................................................................................178 Backing-off...............................................................................................................181
5.2.1.
Fishing Economic Calculator ...............................................................................183
5.2.
Fishing Economics .......................................................................................... 183
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3.5.
Drilling in the box............................................................................................ 116 Hole Cleaning................................................................................................. 118
5.2.2.
Decision trees. .........................................................................................................184
5.3.1. 5.3.2. 5.3.3. 5.3.4.
General ....................................................................................................................187 Kick-off methods.....................................................................................................187 Kick-off plugs ...........................................................................................................188 Kicking-off with a motor. .......................................................................................195
5.3.
5.4.
Sidetracking .................................................................................................... 187
Reporting......................................................................................................... 197
6. Acknowledgements............................................................... 199 7. Appendix................................................................................. 200 7.1. 7.2. 7.3. 7.4.
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Unconsolidated Formations ......................................................................... 201 Mobile Formations ......................................................................................... 202 Faulted & Fractured Formations .................................................................. 203 Naturally over pressured shale collapse..................................................... 204 7.5. Appendix 4: Induced Over-pressured shale collapse. ............................. 205 7.6. Reactive Formations...................................................................................... 206 7.7. Hole Cleaning................................................................................................. 207 7.8. Tectonically Stressed Formations ................................................................. 208 7.9. Differential Sticking ........................................................................................ 209 7.10. Key Seating ................................................................................................. 210 7.11. Undergauge Hole ...................................................................................... 211 7.12. Doglegs & Ledges ...................................................................................... 212 7.13. Junk .............................................................................................................. 213 7.14. Cement Blocks............................................................................................ 214 7.15. Green Cement ........................................................................................... 215 7.16. Stuck Pipe HARC Analysis.......................................................................... 216 7.17. PowerPak Motors with Adjustable Bends Drill String RPM’s: Curved sections....................................................................................................................... 219 7.18. PowerPak Motors with Adjustable Bends Drill String RPM’s: Tangent/Straight Sections........................................................................................ 220
1. PLANNING PHASE.
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1.1. Well Engineering Management System (WEMS) The WEMS is the heart & soul of stuck pipe avoidance. This process combined with the correct technical expertise should: 1. Determine stuck pipe hazards & risks from the offset data: offset reviews EOWR, rig limitations etc. Compile the risks in a risk register. 2. Mitigate the hazards in the design phase: casing design, trajectory planning, HARC analysis, mud selection, rig modifications etc. 3. Review remaining risks. Provide specific procedures in the well operations program to minimise the severity of these remaining risks. 4. Execute the plan: implement the procedures & monitor (real-time analysis). 5. Review the operations and plans. Highlight the lessons learned and feedback into the planning cycle: EOWR, Drill DB, Intouch.
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Figure-1: IPM WEMS flow diagram
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1.2. Risk identification – offset well analysis. An offset well review is a fundamental piece of the well engineering design process and is the first opportunity to identify stuck pipe hazards. There are many sources of information (see list below), but the best by far are the day drilling reports. List of documentation that can aid stuck pipe identification. − − − − − − − − −
Daily Drilling/Operations summary report End of Well Reports Time/depth graphs. Directional drilling slide sheets and report. Pore pressure and fracture gradient profile Seismic Cross section and structural maps Drilling log. Surface and down hole drilling parameter Studies – rock mechanics, stress regimes.
Risk
Consequence/Exposure
Mitigation
Probability
Days
Depleted reservoirs in the overburden. SSH17 is at 62bar. Borehole instability in intermediate section. Borehole instability in intermediate section. Depleted reservoir + high perms.
Losses with high MW. Have to set contingency expandable liner. Hole collapse. Sidetrack
Steer around them.
5%
Borehole instability in reservoir section. Rig rate increases for 2nd phase by 20% Fixed costs increasing by 20%.
Hole collapse. Sidetrack.
Maintain correct MW Maintain correct MW Drilling practice + mud properties. Maintain correct MW. Long term contract Fix contracts for field development
Hole collapse. Set contingency expandable Differential sticking. Sidetrack.
Increase in well cost Increase in well cost
TOTAL
60
Cost €K 1000
Risked Days 3
Risked Cost. 50
10%
10
400
1
40
2%
60
1000
1.2
10
20%
10
250
2
50
10%
10
250
1
25
5%
0
1100
0
55
20%
0
370
0
74
7.2
304
Table 1: Shows an example risk register.
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Once the stuck pipe hazards have been identified they should be compiled in the risk register. This is used to evaluate the economic risk of the well and to mitigate/minimize these risks in the planning and/or execution phase. A typical risk register is shown below.
1.2.1. Stuck Pipe Triggers – how can you recognise the hazards? 1.2.1.1. Time-depth graphs: These provide an excellent high level stuck pipe identification tool and are great for highlighting major events. Well-XX Time Versus Depth 0 NAFE 500
Actual
1,000
Sidetracks are unmistakeable on time/depth graphs
1,500 2,000 2,500 3,000 3,500
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4,000 4,500 0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
tim e in days
45.0
50.0
55.0
60.0
65.0
70.0
75.0
Figure 2: Example of a time depth graph.
1.2.1.2. Daily drilling reports: These provide the bulk of the data and are invaluable in identifying potential stuck pipe hazards in the area. Typical triggers are: a. O/P’s recorded on trips out. b. Reaming required on trips. c. Caving’s reported during drilling and circulating. d. Sticking tendency during connections. e. Bit balling – packed off BHA on surface (see figure 4) f. Trip times. g. Large volume of cuttings/caving's coming over the shakers h. Actual stuck pipe events. Once the triggers have been identified they have to be linked together to determine the root cause of the problem. In most cases you need to “read between the lines” to come out with the correct root cause. Quality. Daily drilling reports can only be used as a source of information if they have been filled out correctly and the right data has been recorded. Typical information that needs to be captured to aid stuck pipe identification should include:
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− − − − − − −
Over pulls: record depth and weight. Caving’s: shape, size, and percentage (compared to cuttings). Reaming: record reaming parameters. Drilling parameters: flow rate (do not record spm unless liner volume is given), rpm, torque, circulating pressure, WOB etc. Circulating parameters prior to tripping: flow rate, rpm, pressure, and amount of cuttings coming over the shakers. Sweeps: volume, type, % increase in cuttings. Drill string & BHA: size of tubulars, bend setting of motor, type of stabs etc.
Without quality data the reports become useless. 1.2.1.3. Surface and down hole drilling parameters “A picture paints a thousand words”. The drilling data provided by real time monitoring systems such as PASON can be extremely effective at highlighting problems, especial whilst tripping. Schlumberger Private
Figure 3: Trip data from a real time rig drilling data system.
The left hand chart shows the hook load for a trip out through a salt sequence. The spikes in the hook load easily identify the problems areas. The chart in the
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centre shows the trip back to bottom and the right hand chart shows the final trip out of hole. It can clearly be seen in this case that the check trip really helped in reducing the amount of tight spots in the section. This can now be used in planning stage to help mitigate the hazard in future wells. 1.2.1.4. End Of Well Report: The end of well report is a very valuable document if compiled correctly, but there is a tendency within the industry just to repeat what is in the daily drilling reports. To be of real use to the drilling engineer in the planning stage it must highlight the lessons learnt, discuss the planned versus the actual, and give clear and concise explanations on why certain operations were performed. Pictures and real-time graphs should be included and it’s just as important to highlight the things that worked as the things that didn’t.
Figure 5: Photograph of caving’s with a scale, are much better than a written explanation in an EOWR.
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Figure 4: The pictures show a balled up BHA after drilling surface hole. This type of information can help the engineer build-up an accurate picture of the drilling problems and is a great aide in communicating the hazards to the rig. Pictures like these should be included in the end of well report.
1.2.1.5. Studies: In order to quantify & then mitigate a hazard it is sometimes necessary to look at a specific problem/hole section in more detail. Rock mechanics studies are a good example of this, but it doesn’t have to be as complex. It can be as simple as plotting some basic trends (see Figure 6). Length of 12 1/4" BUS vs time 600
hours & meters
500
400
300
Hours to drill section Hrs to check trip & POOH Length of BUS (m) Total hrs for 12 1/4" section
200
0 MLM-18
MLM-17 H3
MLM-16
MLM-15
MLM-14
MLM-13
MLM-12
MLM-11
MLM-10
Well number
Figure 6: The graph opposite is a simple plot to show how slight changes in design can have a massive impact on the timings and risk. This examples shows the timings to drill 8deg/30m build-up sections from vertical too horizontal in 12 ¼” hole in the same field, using the same well design. The first 4 wells (MLM 10-14) are straight builds, but after that short tangent sections at 65deg inclinations are included in the trajectory. Initially (MLM15) the tangents are 80m in length, but by the time of MLM-17 they have crept up to 150m. On MLM-18 the tangent length was reduced back to 70m. The graph clearly shows that the inclusion of a tangent had a massive impact on the timings. Analysis concluded that the root cause was poor hole cleaning, which was a direct result of the design of the trajectory & sub optimum hydraulic capacity. No management of change process was applied when the tangents were added and as a result, the rig and trajectory limitations were not anticipated.
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100
Borehole Azimuth
upper limit = Fracture Gradient @ 18.14 kPa/m
17.8
SW1 @ 1.35 sg 16.8
H2 @ 1.29 sg 100
Increasing Optimum Mudweight [Kpa/m]
15.8
110 and 90 deg 120 and 80 deg
14.8
SW1
130 and 70 deg
13.8
40 and 160 deg 30 and 170 deg
12.8
10 11.8
0 and 20 deg
H2 & SO1
10.8
lower limit = Pore Pressure Gradient @ 9.8 kPa/m 9.8 0
30
60
90
Borehole Inclination [deg]
1.2.1.6. Directional drilling slide sheets: These should be kept as part of the well file/end of well report. They can provide valuable information on the hole condition and provide the drilling data for torque and drag analysis (see section 2.2). 1.2.1.7. Logs Calliper logs can help analyse well bore stability and can identify potential problem areas.
1.2.2. Risk of getting stuck? How easy is it to determine our chances of getting stuck? There are four main methods: 1.2.2.1. Experience: This is the most common method and is based on a person’s, or group of person’s previous experience & knowledge. The results of the assessment vary widely, and are influenced by specific problems they have encountered and/or their pet hates. However, if combined with a formal HARC analysis the subjective nature of the exercise can be minimised. 1.2.2.2. Field/area risk sheets:
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Figure 7: The graph shows the optimum mud weight vs. inclination through a shale sequence that is situated in a tectonically stressed area (maximum stress in this case is horizontal). Unfortunately the study was commissioned after a series of stuck pipe events.
This method is excellent if you have plenty of relevant offset data and/or you are involved in a drilling campaign. It takes out the subjectivity that is associated with method one, and can help with identifying trends, especially when changes are made (management of change). Two examples of this are: a. The trend graph in figure- (BUS section graph) is one example. b. Compiling a differential sticking index for an area. This requires a wide offset review focusing on wells that got differential stuck and looking for a consistent trend e.g. wells with inclinations of over 30deg with overbalances of 1400psi or more have a 60% chance of getting stuck. 1.2.2.3. Historical data for different well types (Osprey Risk): Osprey risk has a number of generic risk categories that can be used to highlight areas of high risk in a well design. Osprey risk is described in more detail in section 1.9.1. 1.2.2.4. HARC Analysis.
http://intouchsupport.com/intouch/methodinvokerpage.cfm?method=ITEVIEW& caseid=3858822&outype=3 - File Attachments HARC - Stuck Pipe Final Rev 001.doc HARC analysis does not have to be performed on such a high level. It can be easily used to analysis specific stuck pipe mechanisms in a certain well type e.g. differential sticking when drilling through depleted reservoirs.
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HARC analysis provides an excellent format for assessing risk and identifying control measures. A generic stuck pipe HARC analysis is in InTouch at the following link:
1.3. Casing Design/Hole configuration: Stuck pipe hazards have a major affect on casing design and in some cases drives the design process as much as the well control requirements. Unstable shale’s, hole cleaning and differential sticking are probably the most likely stuck pipe mechanisms to influence and change a design. The next three examples highlight this point, and show how the casing scheme can be changed to mitigate the stuck pipe risk. In some cases an additional string might not be an option, and in these situation the drilling practices and mud selection becomes of paramount importance.
1.3.1. Casing Design Examples 1.3.1.1. Example 1
LIMESTONE
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SHALE SANDSTONE
INTERBEDDED
SANDSTONE The schematic shows a fictitious geological column with a simple build and hold trajectory. The surface casing is set at the top of the shale to ensure BOP protection for the potential hydrocarbons in the intermediate section. The plan is to drill the intermediate section with Oil Based Mud, and from offset data we know the shale’s are stable with a mud weight of between 1.3-1.35sg. In this situation the main stuck pipe risk is hole cleaning in the intermediate 14
section and as such the drilling procedures should be planned to minimise this risk (see section 1.4 & 3.3). 1.3.1.2. Example 2
LIMESTONE
SHALE (Time dependent shale)
SANDSTONE
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INTERBEDDED
SANDSTONE In this next case the shale is time dependent and from offset data the exposure time is estimated at 7days. If a 2-string scheme is used, then the estimated drilling time for the intermediate section is ±6 days. Oil based mud is prohibited in this area so the decision has to be made whether to attempt to drill the section with two strings, or go for the safe option and add an additional string to case of the shale after it has been drilled. In this case the 3-string option has been chosen because: o Running casing takes 2 days o 50% of the intermediate sections require TD logging. If the well is the first one of a 20 well campaign then the ultimate aim would be to reduce drilling, logging, & casing times in the intermediate section to below 7 days. This would allow us to revert back to the original 2-string design.
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1.3.1.3. Example 3
LIMESTONE
SHALE (Unstable shale. MW required = 1.5sg)
SANDSTONE (High Permeable Sand. Estimated overbalance = 10000kPa)
σ1 INTERBEDDED Schlumberger Private
(Unstable shale. MW required = 1.5sg)
SANDSTONE In this third example the maximum stress (σ1) is horizontal and the shallowest sandstone has a high porosity and permeability. Rock mechanic studies indicate that a safe MW to stabilize the main shale and the shale layers in the interbedded section is a mud weight of 1.5sg. To mitigate the shale stability risk it has been decided to use oil based mud and drill with the recommended mud weight. This decision has greatly increased the differential sticking risk from a low to high potential across the sandstone. This is considered unacceptable and it has been decided to drill the sandstone with a minimum overbalance and to introduce a 4th string in to the design. In many cases a 4th string is unrealistic and expensive option and in many cases may not be feasible. An alternative option would be to change the trajectory (see section 1.5.1).
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1.3.2. Expandable Tubulars.
Adding an additional casing to a conventional well design can be costly and in many cases will have a massive impact on the project economics. To incorporate the string in to the design we either have to: − −
Keep the top-hole size the same, and size down the final hole size through the reservoir. Or, keep the final hole size the same and size up from the surface.
The first option impacts the productivity of the well and the second impacts the cost. Expandable tubulars can provide a solution to this problem and are becoming more common within the industry. They can also be used as a contingency if the casing is stuck off bottom.
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1.3.2.1. Example: In example 2 an additional casing string is required to case of the time dependent shale. If production requires the reservoir hole size to remain the same, we have to up size the well to incorporate the additional string. In this case we have a light rig and upsizing is not possible. An expandable liner provides the solution (see below).
LIMESTONE
13 3/8”
SHALE (Time dependent shale)
Trajectories
SANDSTONE Expandable liner 3 OD 11 /4” → 12.238” ID expanded → 11.385”
INTERBEDDED Next Section: 2 options. Under ream to 12 ¼” or, Drill 11” or 10 5/8” hole.
Next Casing/Hole: 9 5/8” casing / 7” hole or, SANDSTONE 8 5/8” casing / 6 5/8” hole.
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1.3.3. Hole Size: In the drilling industry we tend to drill with conventional hole and casing sizes i.e. 17 ½” / 13 3/8”, 12 ¼” / 9 5/8”, & 7” / 6 1/8”. In most cases this is acceptable, but with respect to stuck pipe avoidance this is not always the case. The table below is the Hughes Christensen tri-cone product line. It clearly shows that there are many different bit sizes available and it is not always necessary to drill conventional sizes.
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Table 2: Shows the tri-cone bit types available for different hole sizes.
Hole size optimization with respect to stuck pipe avoidance, is mainly applicable for the following: −
−
Hole cleaning: 12 ¼” hole is the hardest to clean and in many cases the rig is working at 100% of its capacity and is “drilling outside the box” (see section 3.2). In order to move back inside the box, 11”, 10 5/8” & 9 7/8” hole instead of 12 ¼” can be a solution. Of course this has to be balanced against the reduction in hole size through the reservoir, but in cases where this is not a major issue, drilling these sizes can be a real advantage (see section 1.4 for flow rate improvement). Sticky / reactive formations: This application is mainly used in top-hole drilling where larger hole sizes are drilled to give more annular clearance for running casing. An example of this comes from a major operator in the Middle East. During an in fill drilling campaign, it was decided to slim down the well design 18
from 17 ½” hole / 13 3/8” casing top hole, to a 12 ¼” hole / 9 5/8” casing. The bottom third of the top-hole section contained reactive/sticky shale’s and it was common to have tight hole/ packed BHA’s when POOH. An offset review of the early wells was made, and they noticed that one other well had been drilled in the slim design. Coincidentally this had the most difficulty in getting the casing to TD and they were close to losing the top-hole section. To mitigate the increased sticking risk with the slim design, they decided to drill a larger hole size to increase the annular clearance e.g. 14 ½” hole instead of 12 ¼”. The difference this made to the reduction in the stuck pipe risk and the improvement in the section timings can clearly be seen on the graph.
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Figure 8: Offset analysis showing improved tophole performance on the last three wells (XXX-28 to 30). The performance can be attributed to drilling with a large hole sizes to minimize the impact of sticky shale’s/clays.
Factors to consider when changing the hole size: 1. Management of change process. 2. Reduction in hole size – impact on ECD? 3. Increase in hole size – impact on hole cleaning. 4. BHA components – stabs, subs etc. 5. Bits. 6. Fishing tools – size, availability? Bi-centered bits & hole opening tools Bi-centered bits & hole opening tools are now widely used within the industry to increase the annular clearance in a hole section. Their main advantage is that
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the casing scheme does not need to be upsized to incorporate the larger hole OD, and this is off particular advantage in deeper hole sections. Typically they can enlarge the borehole up to 20% of the bit OD.
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1.4. Hole Cleaning: The facts speak for themselves. A third of all stuck pipe events in non-deviated wells and 80% events in high angle wells are hole cleaning related. The ramp up in percentage is a direct result of the increasing difficulty in achieving good hole cleaning with increasing hole angle (see figure 9).
Hole - Cleaning: Difficulty vs. Angle Difficult
I
II
III
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Relative Difficulty
IV
Easy
0
30
Inclination
60
90
Figure 9: Graph shows the hole cleaning relative difficulty vs. inclination.
Many of the events, especially in deviated wells, are “failure by design/poor planning” and could have been prevented if the proper measures had been implemented in the planning stage. In this section we will discuss the main components that control the effectiveness of hole cleaning in the well. For a more detailed discussion on the theory of hole cleaning and cuttings transportation then please go to Chapter 7: Trouble Free Drilling Manual.
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1.4.1. Hole cleaning in vertical wells (<35deg). Hole cleaning in vertical wells is often overlooked and considered unimportant. However, it is amazing the number of stuck pipe incidents in vertical wells that can be attributed to poor hole cleaning. 1.4.1.1. Main factors that influence hole cleaning in vertical wells?
‘High’
Cuttings density
Mud weight
Cuttings size
Influence on cuttings transport
ROP Flow Rate
LSYP YP
PV
‘Low’ ‘Low’
Ability to control
‘High’
Figure 10: Shows the main factors that influence hole cleaning in a vertical well vs. the ability for us to control.
1.4.1.2. How can we evaluate hole-cleaning efficiency in vertical wells? One method is the volumetric cuttings concentration in the annulus and the other is the transport ratio. The equations are shown below:
Transport Ratio = FT = Vslip V FT = T = 1 − Va Va
Transport Velocity Annular Velocity
Volume of cuttings in the annulus. Vol cuttings conc. =
Total annular volume
Both equations are described in detail in Page 46, Chapter 7: Trouble Free Drilling Manual. Anything that increases the transport ratio increases the hole cleaning efficiency in vertical wells. A reduction in slip velocity is one way that the transport ratio can
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RPM
be increased. The slip velocity is influenced by the density and size of the cutting, and by the viscosity and density of the fluid. Much of what we do to improve hole-cleaning efficiency in vertical wells is aimed at reducing the slip velocity or increasing the average annular velocity. The volume of cuttings concentration in the annulus is influenced by the rate of penetration and the annular velocity. To improve cuttings concentration in the annulus we can either reduce the ROP or increase the annular velocity. 1.4.1.3. What can be done in the planning stage? Less planning is required to ensure good hole cleaning in vertical wells compared to deviated wells. In the end it comes down to the implementation of good drilling practices and keeping the mud in shape.
Factors That Influence Hole Cleaning Mud weight Mud rheology
ROP
Scenario Planning
Solids Control Equipment
The higher the weight the better the cleaning. Ensure that the correct mud parameters are in the program and these have been communicated effectively to the wellsite. See next section for guidelines on correct rheology. Calculate the annular velocity for the planned flow rate. Check that there is effective cuttings removal. Limited on flow rate? 1. Reduce ROP 2. Drill pilot hole & open up with hole opener. Good option for hole sizes >17 ½”. Calculate the maximum ROP for the planned flow rate in the section. Set maximum ROP limits to ensure the annulus is not overloaded. Communicate these limits to the rig and ensure they stick to them. What if’s? IPM have had a number of stuck pipe incidents in vertical wells where the shakers or flowline has been overloaded and the pumps have been stopped to clear the cuttings. On resumption of circulation the hole has packed off. Discuss contingency planning with the well site for these types of situation. Do you have enough shakers? What screen sizes are required? Is the flowline & cuttings shoot large enough?
Table 3: Lists the factors that influence hole cleaning in a vertical well.
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Annular Velocity
Measures that should be taken in the Planning Phase.
1.4.2. Hole Cleaning In Deviated Wells (>35deg) 1.4.2.1. Introduction Figure 11 sums it up. The drilling practices and fluids that work to clean the hole in a vertical well will not work in a deviated wellbore. This combined with a lack of understanding of hole cleaning within the industry makes for a recipe for disaster. Hopefully, this section and Chapter 7 of the Trouble Free Drilling Manual will change this.
1
WHAT WORKS HERE 2
MIGHT WORK HERE WILL NOT WORK HERE
3
Schlumberger Private
4
0
35
65
90
Hole Inclination
Figure 11: Highlights the fact that what works in a vertical section will probably not work in the deviated portion.
1.4.2.2. Recap: The differences between vertical & directional wells. 1.
Gravity works against us.
During drilling, the velocity of the drilling fluid must exert a force high enough to counteract the effects of gravity, which will tend to make the cutting drop to the bottom of the well. Usually, enough velocity is achieved by the drilling fluid to perform this task efficiently in vertical wells. On the other hand, directional wells pose a more difficult problem. Influenced by gravity, the cutting will still try to drop, but due to the inclination of the well it does not have to travel too far before it reaches the lower side of the wellbore. In this situation, the velocity of the drilling fluid has to be higher in order to keep the cutting moving up towards the surface.
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Particle Velocity
Particle Velocity
Mud Velocity Mud Velocity
Vertical Well
Directional Well
2.
Schlumberger Private
Figure 12: Shows particle (cutting) and mud velocity direction in a vertical & deviated wellbore.
Pipe is eccentric.
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The drill pipe sits where the cuttings accumulate, on the low side of the hole What are the Effects? - Non-uniform hole shape -
Adhesion of the cuttings in the bed
-
Increased torque & drag
How does Mud Respond? - The mud on the low side is overloaded with cuttings and they drop out. Mud rheology at low shear rates is critical for good hole cleaning. - Forms a new boundary layer of no flow between the cuttings bed and the mud.
DRILL PIPE
Figure 13: Diagram showing pipe eccentricity in the well bore.
Schlumberger Private
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3.
Flow profile changes.
The pipe eccentricity changes the flow profile in the hole. Unfortunately with the pipe stationary e.g. not rotating, it does not work in our favor!
Schlumberger Private
Figure 14: Shows the difference in the flow profile (red arrows) between a vertical & directional well. No cuttings are present in this example.
10 ft/min
150 ft/min 100 ft/min
100 ft/min
50 ft/min
0-3 ft/min
50 ft/min
DP
0-3 ft/min
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Figures 15: shows the flow profile in a directional well with the DP lying on the low side. The top section of the wellbore has a high-energy flow zone and the bottom has a lowenergy flow zone. This creates a top part with fast moving thin mud and a bottom zone with high solids, slow moving mud. This slow moving high cuttings concentration mud is unable to carry the solids up the wellbore and they “fall out” creating cuttings beds on the low side of the hole.
1.4.3. How do we achieve good hole cleaning in a directional well? There are three main factors that affect the hole cleaning capability and they are all interdependent on each other. They are: 1. Pipe Rotation. 2. Flow rate. 3. Low-end mud rheology (discussed in section 1.7)
Figure 16: Visualisation of K & M’s hole cleaning conveyor belt.
1.4.4. Pipe Rotation. Pipe rotation is critical in cleaning the hole. There are some differences in opinion on the mechanism that causes the improvement in hole cleaning, but there is no doubt that it has a huge impact. The different theories are:
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To achieve good hole cleaning the correct rpm’s, flow rates & mud parameters must be chosen for the given hole size. K &M technology group likens the process to that of a “conveyor belt”. If the correct parameters are chosen, the cuttings are thrown up from the low side of the well bore, on to the “conveyor belt” and transported out of the hole.
1. Mechanical agitation: at low rpm’s the drill pipe rolls up the walls and slides back down. At a certain “threshold” rpm, the pipe breaks out of the cutting bed and will rattle around the wellbore and mechanically agitates the cuttings. Chapter 7 of the Trouble Free Drilling Manual promotes this theory, and suggest that a typical threshold rpm for 12 ¼” & 8 ½” hole, occurs around 50 & 75rpm. 2. Hydraulic action: The pipe rotation creates fluid movement in the bed and the whirl moves pipe around the wall creating additional velocity at the sides. This velocity causes frictional drag and lifts the cuttings to where the mud is moving. K & M explain it as the viscous coupling? In reality it is probably a combination of the two and experimental data has supported this. 1.4.4.1. How fast do we need to rotate the pipe? There are different “rules of thumb” out there in the industry. K & M promote that in 12 ¼” & 9 7/8” hole sizes, step improvements in cuttings returns are seen at 100120rpm and at 150-180rpm. The thresholds are not based on a theoretical model, but rather on actual operational experience in high angle well bores. Schlumberger Private
150 - 180 RPM
Relative Cuttings Return Volume
100 –120 RPM
Fine-tuning of pipe RPM from 60-80 RPM is generally not meaningful
Pipe RPM Figure 17: Graph showing relative cuttings return vs. drill string surface RPM for 12 ¼” hole. Note the step changes at 120 & 180rpm.
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Table 4 is K & M’s recommended drillstring rpm for different hole sizes. This table is supposedly based on field observations, but it has been difficult to validate. We feel the minimum rpm’s are a more realistic target and if the string is rotated faster e.g. to the desirable rpm’s, then other problems are created e.g. more equipment failures etc. Hole Size
Desirable RPM
Minimum RPM
17 ½”
120-180rpm
120 rpm
12 ¼”
120-180rpm
120 rpm
9 7/8”
120-150rpm
100 rpm
8 ½”
70-100rpm
60 rpm
Table 4: Recommended drill string RPM for different hole sizes.
Chapter 7 of the Trouble Free Drilling Manual sets the thresholds much lower, at 50 –75rpm for 12 ¼” & 8 ½”. This is based on field experience with pressure while drilling tools in deviated well bores. In reality the effect of drill pipe rotation is dependent on a number of interrelated factors. These are covered comprehensively on Page 84, Chapter 7: Trouble Free Drilling Manual. SPE 56406 is a good research paper on the affect of DP rotation on hole cleaning and is a recommended read.
MD/RPM/Flow In/Cuttings
Rotary Cuttings Mobilization in 12-1/4” Horizontal Section
PWD g/cc
ECD 1.68 14.02
3000
2000
Steer
1.67
Cuttings agitated by pipe rpm
2500
Drill
Steer
1500
Steer
1.66 13.88 1.65
Drill
1.64 13.67 1.63
ECD Increase in ECD
1000
1.62 13.52 1.61 1.6
500
13.35
1.59 0 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00
MD,m
RPMx10
Cuttings flux, kgx10
1.58 13.19 0:00
PWD EMW
Figure 18. The graph shows the increase in ECD and cuttings returns at surface (blue line) when the drill string is rotated after a period of sliding. The increase can be attributed to pipe rotation agitating cuttings off the low side of the well into the mud stream.
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In general we should be aiming to rotate the pipe as fast as possible within the limits of our downhole tools and surface equipment. For larger hole sizes e.g. > 9 7/8”, this should be higher than 100rpm. 1.4.4.2. Planning Rotation. Pipe rotation must be planned in advanced. It is no good wishing you could rotate at 120rpm when you have a directional assembly in the hole with a 1.5deg bend. The best way of ensuring that you can rotate at the required rpm is to build the well trajectory and directional plan around this condition. This means working closely with the directional company to come up with the optimum solution. In many cases the design will already be fixed, and you will not have a free hand. In these situations the risks in the design need to be highlighted and comprehensive procedures/control measures put in place to mitigate these risks (see section 3.3.2.2). Factors affecting pipe rotation: 1. 2. 3. 4.
Dogleg severity requirement & tortuosity of the wellbore Bottom hole assembly. Topdrive or rotary table torque rating. Connection rating – mainly constrained to ERD wells.
1.4.5. Flow Rate Turbulent flow rules in hole cleaning. Unfortunately for us we very rarely achieve it, and we have to face the fact that we have to clean the hole in a laminar flow environment. The good news is that the industry is fully aware of the importance of pumping at high enough flow rate in a laminar flow regime to clean the hole. However, there is a problem. What is that optimum flow rate for the particular conditions?
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Static Static
50 50 fpm fpm
150 150 fpm fpm 100 100 fpm fpm
Figure 19: Shows an MI flow tube. The test shows the changes in flow regime with increasing flow rate – all other parameters have been held constant. The results clearly show a cuttings bed at 50 fpm (feet per min) to turbulent flow and no cuttings bed at 150fpm.
1.4.5.1. Experimental Research Experimental data has also confirmed the importance of flow rate in improving the hole cleaning efficiency in deviated wells. Figure 21 is an example of the research.
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Figure 20: The chart shows experimental results of cutting bed erosion rates with varying flow rates. The experiments were conducted on a 30ft 8” flow loop with 4 ½” DP. In this case the flow loop was set at 87deg and there was no pipe rotation. Initially cuttings were injected into the annulus until they built up to an equilibrium height. Injection was stopped and the bed erosion rate was measured. The results clearly show the impact of increasing flow rate, and in this example there is a significant step change between 250gpm to 300gpm. It is interesting to note that at the lower flow rates it is virtually impossible to clean the hole. The chart is taken from SPE63050.
1.4.5.2. How fast do we need to pump? The industry is a wash with tables & rules of thumb for optimum flow rates/annular velocities in different hole sizes. Whilst these can give you an idea of what to pump they don’t take into account the other factors that affect the hole cleaning efficiency i.e. rpm, rheology, inclination etc. The next two tables give optimum flow rates for different hole sizes and inclinations. Hole Size
Desirable Flow rate
Minimum Workable Flow rate
17 ½”
900 – 1200 gpm
800 gpm with ROP at 20m/hr
12 ¼”
800 – 1100 gpm
650 gpm with ROP at 10-15m/hr 800 gpm with ROP at 20-30m/hr
9 7/8”
700 – 900 gpm
500 gpm with ROP at 10-20m/hr
8 ½”
450 – 600 gpm
350-400 gpm with ROP at 10-20m/hr
lpm= 3.785 x gpm
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Table 5: Shows K & M’s recommended flow rates for different hole sizes.
Hole Size Flow rate (GPM) 0 to 35 degree 35 to 55 degree 55+ degree
26” 1200 – 1300
OPTIMUM FLOW RATES 17-1/2” – 16” 12-1/4” 900 – 1200 800 – 1100
8-1/2” 450 – 600
MINIMUM FLOW RATE (GPM) VERSUS HOLE SIZE AND HOLE INCLINATION 700 GPM 700 GPM 650 GPM 400 GPM 1250 GPM 850 GPM 700 GPM 450 GPM 1100 GPM
750 GPM
500 GPM
6-1/8” 350 – 500
250 GPM 300 GPM 400 GPM
Table 6: Shows the PERFORM manuals recommended flow rates for different hole sizes and inclinations. ECD & hole erosion (unconsolidated sands) need be considered for the smaller hole sizes (8 ½” & 6 1/8”) before the optimum flow rates are used. Typically smaller hole sizes will clean effectively at the minimum flow rates.
The optimum flow rates in both tables concur, and these rates should be used as a good rule of thumb.
1.4.6. Equilibrium Bed Height This next section is discussed in Chapter 7 of the Trouble Free Drilling Manual, but it’s off critical importance in understanding the term “ a clean hole” that we will recap the topic here. If you asked most drilling engineers in the industry how do you get a clean hole they will tell you that by circulating for a time ‘x’, at a flow rate of ‘y’ and pipe rotation of ‘z’ you will affectively clean the hole. If either ‘y’ or ‘z’ is reduced, then an increase in ‘x’ is required to get back to a clean hole. In the industry “4 x bottoms-up” is seen as a good rule of thumb on how much circulation time is required to achieve good hole cleaning in a directional well. However, experimental data indicates (ref SPE56406) that the cuttings bed height is reduced during hole cleaning circulation prior to tripping, but under many conditions will not disappear completely (see figures 21 & 23) Figures 21 & 23 show two tests that have been carried out in the cuttings transport simulator at Tulsa University (Ref SPE56406). Stage 1 represents the accumulation process, where the cuttings concentration in the annulus increases from zero until it reaches a constant value. In stage 2, the cuttings injection rate is equal to the cuttings collection rate and the cuttings mass in the annulus remains constant (equilibrium). Pipe rotation starts in stage 3 and continues until the end of the test. Erosion of the bed begins and continues until a new steady state (equilibrium). This is the beginning of stage 4 in which the cuttings mass in the test section remains constant. At the end of stage 4, the cuttings injection rate is stopped, resulting in further bed erosion. The erosion is shown in stage 5 where the cuttings concentration decreases to its lowest value. Figure 21 shows that under the given conditions, not all the cuttings are removed from the annulus. However, Figure 22 shows that under the same conditions, rotary speed of 90 rpm does clean the hole. 34
Experimental Hole Cleaning Graphs.
Bed height reduces, but does not disappear completely. On the rig the shakers would indicate the hole is clean!
Figure 21: Test graph for 50rpm. Taken from SPE56406. After cuttings injection is stopped, the bed height reduces, but does not disappear completely.
Bed height reduces to zero with an additional 40rpm.
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Figure 22: Test graph for 90rpm. Taken from SPE56406. The additional rpm reduces the bed height during cutting injection and cleans the hole completely once injection is stopped.
Significant cuttings bed remains after injection is stopped.
Figure 23: Is taken from the same SPE paper and shows the affect of a reduction in flow rate has on the cuttings bed height. In this case a significant bed height remains after cutting injection is stopped.
What does it mean if we can’t get the hole completely clean when circulating prior to a trip? Well it’s simple, the risk of stuck pipe increases. The amount of risk depends on a number of factors. These are: -
The height of residual cuttings bed. Clearance between downhole drilling equipment and wellbore. Tripping practices i.e. pulling speed, circulations etc
The bed height is dependent on the three main factors: rpm, flow rate and low-end rheology and these have been discussed already.
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The amount of clearance between the BHA and wellbore is extremely important because in most cases we leave cuttings beds in the hole. The trick is to have enough annular clearance around the BHA to allow the cuttings bed to pass by without increasing the height of the bed e.g. a steady state situation. However, if the bed height is increases, cuttings build up around the BHA and the risk of pack-off increases and stuck pipe incidents will occur. In this scenario the BHA needs to be designed to maximum annular clearance and this will be discussed in more detail in section 1.6 Acceptable cuttings bed – the hole is not 100% clean, but the bed height is low enough to allow easy passage of the assembly without pumps or rotation.
Unacceptable cuttings bed – the hole is not 100% clean, but the bed height is too high to allow passage of the assembly. The cuttings build up around the x-over between the BHA and DP, and the stabilizers. If pulling out continues the hole will pack-off. In this example the remedial action is to go back down two stands and circulate the hole clean.
Figure 24: Schematic a BHA tripping through open hole.
Lastly good tripping practices are required to stop cuttings building up to a height that can cause the BHA to pack-off. A major factor is the speed at which the BHA is pulled out of hole and the ability to recognise a build-up before it is too late. Recommend tripping practices will be discussed in section 3.5
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1.5. Directional Planning 1.5.1. Trajectories. 1.5.1.1. Introduction The well trajectory plays a major role in stuck pipe prevention and many root causes of stuck pipe incidents can be attributed to poor trajectory design. Sadly in many cases the rig is blamed for most stuck pipe incidents, but in reality it was set up for failure even before it started drilling. The good news is that a well planned trajectory and directional philosophy can mitigate/reduce the stuck pipe risks in the well, and allow the rig plenty of margin for error before a stuck pipe incident occurs. 1.5.1.2. Different types of trajectory. The main types of directional profiles are shown on the schematic below.
Derrick.ico
LIMESTONE
SHALE 1 SANDSTONE 1 d
c
a
b
INTERBEDDED
SANDSTONE 2 Figure 25: Shows the different types of trajectory profile.
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J Type (a) 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. J profiles minimize the total depth and required directional work and are the most common profiles in the industry. Points to note: − Kick-off depth & step out determines tangent angle. − Shortest total depth − Care needs to be taken if tangent angle is between 45-60deg – in the cuttings avalanche zone. − Minimises directional work. S Type (b) The S profile is similar to the J profile, but instead of continuing on a tangent, it drops off back to vertical or near vertical to penetrate the objective. This can be used for the following applications: − − − −
Exploration drilling when the well is deviated it. The geological & TVD uncertainty is reduced at the top of the reservoir. Differential sticking risk. The reduction in inclination and directional work can reduce the differential sticking risk. This would be applicable if sandstone 2 in Figure 25 if it had a high differential sticking risk Pay zone cementing may be more reliable. ECD’s through the pay zone may be reduced.
Points to note: − Higher torque and drag compared to the J profile. − Higher tangent inclination compared to the J profile. Continuous build (c) This is based on the natural profile that the drill string would take between two points. The profile is characterised by low build rates of 0.5/1º / 100ft. This profile is not widely used within the industry, but can be applied in certain situations. These are: − −
When building from vertical to horizontal. Reducing the build rates in the build allows you to run with a low bend setting on the motor and allows an increase in the string rpm. Instability in upper zones. This would be an advantage if Shale 1 in figure 25 were unstable. The continuous build profile would allow you to minimise the inclination through the shale, and then increase the build rate after the shale has been drilled (pseudo-continuous).
Points to note: − Additional total depth − Low torque, but in many cases higher drag. − May need additional hydraulic capability.
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Double build (d) This is a variation on the J profile, but instead of building once it builds twice. Like the continuous build profile it is not widely used within the industry, but can be applied in certain situations. These are: − − −
Borehole instability in the upper sections. The double build profile allows you to minimise the inclination through these unstable formations i.e. if shale 1 is unstable in figure 25. Slower ROP in the upper formations. The double build minimise the along hole depth through these formations. Depleted zones in the overburden formations. The double build profile allows you to minimise the inclination through these formations i.e. if sandstone1 in figure 25 has a significant differential sticking risk.
Complex builds (3-D). 3-D wells have both azimuthal & inclinational components. They are used in the industry to: − − −
Avoid collision with other wells. Steer around geological hazards. Drill in a preferred direction to minimise the affect of certain geological hazards e.g. dipping formations, stress orientation.
It is important to remember that the rates of build and turn for any given assembly are not the same. Typically a directional assembly will achieve higher doglegs building then it will turning. 1.5.1.3. Horizontal Wells Horizontal profiles are used in development drilling to increase reservoir exposure.
Figure 26: Shows a horizontal profile for a shallow oil producer. The profile has been designed to incorporate an ESP pump positioned in the tangent section. The blue circle indicates the critical hole cleaning section in the well.
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The trajectories are typical constrained by production requirements and they have a significant stuck pipe risk. To add to the problems many horizontal wells are drilled in cheap operating environments, in to shallow oil reservoirs. Typical these wells are drilled with light underpowered rigs (many cases with a kelly) and inexperienced crews. Hole cleaning and its associated problems is the main stuck pipe risk in a horizontal well and the trajectory can be key in minimising the stuck pipe risks. The main areas of concern are: Build-up section: Typically this section has more hole cleaning problems than its horizontal counterpart. The explanation for this is pretty simple, the build-up sections are drilled in larger hole sizes, typically 12 ¼”, and they require higher flow rates and rpm’s to clean the hole efficiently. The build rate has a huge influence on the directional philosophy in the build-up section and as a general rule should be minimised at much as practically possible. The trajectory in figure 26 is a case in point, and is an actual well in the Middle East. In this particular scenario the final dogleg severity from the end of the tangent at 45º inclinations to horizontal was 7.5º/30m. To achieve this dogleg a minimum motor bend setting of 1.5º was required. This setting restricted the string rotation to a maximum of 60rpm whilst drilling and circulating. This restriction reduced the hole cleaning efficiency and the affect was compounded when the well was drilled with an underpowered rig, which could only circulate at a maximum flow rate at section TD of 2.6m3/min. The section experienced numerous hole cleaning related problems, and one catastrophic stuck pipe incident occurred (sidetrack required) during tripping. Even on the sidetrack it took 3days to trip out of hole. The investigation concluded that the main root cause of the stuck pipe incident was the underpowered rig combined with high dogleg severity requirement in the final build section. How do we reduce the build rate? − Move the surface location away from the sub-surface target & kick-off higher. This is subject to the surface restrictions in the area that you are drilling in and only applies to land drilling. − Move the subsurface target further away from the surface location & kick-off higher. This needs to be discussed with the production guys, but sometimes a solution can be found. Tangent sections within the build: The key to the tangent section is to try and keep the inclination below 45deg. If the tangent is required for the placement of an ESP (doglegs < 2deg/30m to avoid pump failures) then you must ensure that the tangent length is kept to an absolute minimum. Experience has shown that the inclusion of a tangent section for an ESP into a straight build profile can tip the balance and severely increase the drilling times and the stuck pipe risk. This is highlighted by the graph in section 1.2 figure 6
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Horizontal Section: Typically this section tends to be less critical then the build section. The reasons are quite simple: − Smaller hole sizes. Typically 8 ½” or smaller. − Straight section with minimal direction work. BHA’s can be setup for higher string rpm’s e.g. typically bend settings of 0.75deg. − Smaller hole sizes mean cuttings are agitated with less string rpm. Typically 70rpm in 8 ½” hole. − Lower flow rates are required to achieve efficient hole cleaning.
1.5.2. Directional Strategies The recent trend within the industry has been to aim for a one run philosophy from shoe to TD. This has evolved due to an increased reliability in downhole equipment, the advancement in PDC technology and the “drilling the limit” culture. The problem with this philosophy in directional wells is that the best BHA for the build section is not necessarily the best BHA for the tangent section. A good analogy is formula one motor racing. Ferrari does not try and go the hole race without pitting. Instead, he and his team meticulously form a pit stop strategy that over the hole race is much faster than if he didn’t stop at all. A well-planned strategy will not only be faster from shoe to TD, but will minimize the stuck pipe risks. 1.5.2.1. Example Figure 27 includes a build-up section and a tangent section. There are several different ways to drill this section: 1. One run with a conventional motor assembly. The assembly will be set up to achieve the dogleg requirement in the build-up section. The bit will be selected to last for the whole run, typically a PDC that is not too aggressive to allow for directional control. The planned dogleg will dictate the bend setting of the motor, and this impacts the build tendency of the assembly in rotary mode e.g. typically the higher the bend setting = greater the rotary build. This impacts the amount of corrections required in the tangent section and can cause a tortuous well path and poor performance. The bend setting can also impact the amount of string rpm for hole cleaning in the tangent section. 2. One run with a rotor steerable assembly. If the dogleg severity is < 8 deg/30m then a rotary steerable assembly can be used. The merits of rotary steerable tools will be discussed later in this section, but as a general rule if the economics can be justified then this is the optimum solution. A two run strategy can still be used with a rotary steerable tool; the difference between the two runs would be the bit selection.
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3. Two runs with a conventional motor assembly. The first BHA would be set-up to drill the build section. The bit selection would focus on directional control and maximizing ROP. To maximize steer ability i.e. reduce reactive torque and help the directional driller, a roller cone bit would be a good option for the build section. It also has the advantage of making you pull the assembly for bit hours, ensuring that you are not tempted too continue drilling with the build assembly in the tangent section. The second BHA would be used to drill the tangent section. It would be set-up to maximize string rotation and ROP. A bend setting of 0.78deg could be used and an aggressive PDC run to improve ROP. Out of the two conventional strategies it is extremely likely that option 3 would be the fastest from shoe to TD. It is the role of the drilling/well engineer to work closely with, and steer the directional drilling company, typically D & M, to develop this strategy. The worst mistake an engineer can make is to give the directional planner two points, the surface and sub-surface target and tell him to get on with it.
Derrick.ico
LIMESTONE
SHALE 1 Build-up section
SANDSTONE 1
INTERBEDDED Target
Tangent
SANDSTONE 2 Figure 27: Schematic showing a standard J profile.
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1.5.2.2. Drilling the plan The directional plan is a guideline for the WSS & directional driller. It is not meant to be stuck to religiously and a bit of common sense and local knowledge needs to be incorporated. A good directional driller should factor the following into the plan: −
−
Build/drop tendency of the directional assembly in rotary mode. If the assembly is known to drop at 0.3deg/30m a good directional driller will aim to be above the line (J type) when he comes out of the build. This way he can allow the assembly to natural drop back to the line in rotary mode. The effect of the formation on the build/drop tendency (see figure 28). This allows the directional driller to anticipate changes and keeps him or her in control of the situation.
When the directional drilling and/or WSS decide to drill on the line with a motor assembly they: − − − −
Increases the amount of sliding. Increases the tortuosity of the wellbore Increases the torque and drag. Reduce the hole cleaning efficiency.
Figure 28: Shows build tendencies in a 12 ¼” build up section. Recording the dogleg severities in different formations allows the directional driller to plan ahead and stay in control of the drilling.
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1.6. Directional Assemblies. 1.6.1. Conventional Steerable Assemblies: The majority of directional wells around the world are still drilled with conventional steerable assemblies. The main issues with respect to hole cleaning/stuck pipe are: 1. No rotation when sliding. Cuttings are not thrown on to the conveyor belt. Figure 18 clearly shows this. 2. RPM restrictions are imposed with increasing bend setting. This is to avoid fatigue failure of the bearing housing. The limit might not be high enough to clean the hole. 3. Annular clearance between the wellbore and the sleeve or integral stabiliser.
80 models from 2 1/8 in. to 11 1/4 in.
PDM Bend Setting Sleeve or integral stab.
Figure 29: Shows a typical motor assembly.
1.6.1.1. No String Rotation When Sliding As discussed in the hole cleaning section pipe rotation has a huge impact on the hole cleaning efficiency. Unfortunately for us conventional steerable assemblies cannot be rotated whilst steering and the result of this is a cuttings build-up in the annulus during this period. This disadvantage has been one of the main drives behind the development of rotary steerable systems. 1.6.1.2. Bend Setting & the affect on string RPM. Conventional steerable design is driven by the dogleg requirements of the trajectory. This translates simply to: Higher dogleg = higher the bend setting = greater the restriction in RPM.
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This is important to remember when designing the trajectory. If for example a 12 ¼” section has been designed with a build-up rate of 8deg/30m it’s likely that the motor bend setting will have to be either 1.5deg or 1.83deg. The D & M Powerpak Motor Uniform Operating Procedures show that the maximum string RPM that can be applied to the string during drilling of this build-up section is 40rpm – well below what is required for cuttings agitation. To compensate for the lack of rotation you can: 1. Increase the flow rate. In most cases we won’t be able to increase the flow rate to a sufficient rate that would make up for the lack of rotation. 2. Ensure rotation of sufficient speed is achieved in the tangent section after the buildup section. This only applies if there is a tangent section after the build. 3. Change the trajectory. This means reducing the build rates so that a lower bend setting can be used. In order to do this the surface location might have to be moved. 4. Putting in dedicated hole cleaning procedures. This could involve clean-up trips during the build-up section and having dedicated assemblies for different parts of the section i.e. one assembly for the build-up and a different assembly for the tangent section. In wells with inclinations over 50deg it is very unlikely to get stuck whilst drilling. In nearly 95% of the cases we get stuck pulling out of hole and it is important to maximise circulation prior to tripping. This means maximizing the RPM & flow rate even if you have been restricted whilst drilling the build section. See appendix 7.17 & 7.18 for the RPM tables. Intouch Content ID: 3016498: PowerPak Motors Uniform Operating Procedures (v 1.4). 1.6.1.3. Junk Slot Area. Field experience and research has shown that it is very difficult to get a deviated hole 100% clean. Therefore we have to assume that there is a cuttings bed lying on the low side of the hole when we trip. The height of this bed will depend on how efficient our hole cleaning has been. In order to successfully trip out of the hole the cuttings must pass around the BHA without increasing the bed height e.g. a steady state situation. However, if the bed height increases, cuttings will build up around the BHA and the risk of pack-off and stuck pipe incidents increase. The three main factors that influence this are: -
The height of residual cuttings bed. Clearance between downhole drilling equipment and wellbore. Pulling speed.
The bed height is governed by the equilibrium conditions of our rig and well design. Tripping speed is in the hands of the driller and he must be made aware that the hole is probably not 100% clean prior to the trip (even though the proper practices have been followed), and that any resistance is the build-up of cuttings around the BHA – this is an 46
extremely important message to get across. Junk slot area needs to be planned in advanced, and is especially important when the well is being drilled with a sub-optimum flow rate & rpm. In this situation the junk slot area needs to be maximized. Where is the least amount of annular clearance? Typically this is between the sleeve stabilizer on the mud motor and the wellbore. Figure 32 shows the difference between a 12 ¼” FG, 9 5/8” motor sleeve stab & a 12 ¼” FG, 8 ¼” motor sleeve stab. It can clearly be seen that there is a significant reduction in clearance between the two. How to increase the clearance? Note: We will focus on 12 ¼” hole because it tends to be the critical hole size. 1. Run an 8 ¼” mud motor assembly instead of 9 5/8” mud motor assembly. This will increase the annular clearance, but it may reduce the performance. Another problem is that 8 ¼” assemblies tend to build more angle than a 9 5/8” assembly when rotating in a tangent section. To compromise a two assembly approach could be used i.e. 8 ¼” for the build-up & a 9 5/8” for the tangent. 2. Manufacture some 9 5/8” integral blade stabilizer bodies to increase the clearance e.g. 9 5/8” instead of an 11” diameter. At the moment D & M do not supply these, but they can be easily manufactured with enough lead-time. 3. Run a slick assembly. The main issue is a strong drop tendency in rotary mode?
Sleeve stabilizer
Figure 30: Shows the different stabilizer options for a mud motor. Integral blades are normal used on small motors e.g. <6 ½”
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9 5/8” MM sleeve stab.
8 ¼” MM sleeve stab. Clearance
11” dia.
9 3/8” dia.
12 1/8” Sleeve stabilizer in 12 ¼” hole. Figure 31: Scale drawing of a 9 5/8” & 8 ¼” motor sleeve stabilizer for 12 ¼” hole. The diagram shows a significant increase in junk slot for the 8 ¼” motor sleeve stabilizer. This increase could be important if we are trying to trip out of a dirty hole (see figure26).
To find the optimum solution it is important to discuss the requirements & options with the directional drilling company in the planning phase. Other Factors The amount and type of stabilizers run has an impact. The philosophy should be to always minimize the number of stabilizers in the BHA and run straight bladed stabs instead of spiral stabilizers. If spiral stabs are used ensure the wrap is not more than 270deg. If a clean out trip is planned before running casing it is always better to lay down the directional assembly and run back in with a dedicated clean out BHA.
1.6.2. Rotary Steerable Systems (RSS). The single most important advantage that a rotary steerable system has over a conventional motor system is continuous rotation of the string at speeds over 120 rpm. As mentioned previously, continuous rotation at high rpm is one of the key factors for achieving good hole cleaning and rotary steerable systems are the solution. However, it is important to stress that a rotary steerable system alone won’t solve your hole cleaning problems unless the other key parameters are optimized. The main advantages with the use of rotary steerable systems are: 1. Continuous rotation maximizes hole cleaning efficiency and ROP. 2. Full inclination and azimuth control with a broad range of dogleg capability. 3. Not limited by weight stacking and buckling issues, as are motors. 48
4. Minimize tortuosity in the wellbore – smooth wellbore aids further torque and drag reduction. So why aren’t these tools used for all wells in all applications? There are currently two main limitations: 1. Cost: initially the costs of the tools were expensive, and because of this were rarely used in land operations. This is changing; the cost of the tools is coming down as new systems enter the market, and operators are becoming aware of the additional advantages and indirect savings that a RSS can bring to their operations. If the economics are cost neutral or slight negative then a RSS should always be run. One point to note is that Lost In Hole charges tend to be fairly high. 2. Reliability: RSS’s have not had a good reputation in this area. However, in the last 2 years tool reliability has increased dramatically as the service companies define and fix problems with the tools. D & M are leading the way in reliability compared to the competition and the mean time between failures for PowerDrive in 2003 was 13000ft between failure, or 350 circulating hours. 1.6.2.1. What to consider when running RSS? 1. Pressure drop required at the bit and by the tool is significantly higher than a mud motor. 2. Planned dogleg severity. Maximum dogleg is 7-8 deg/30m, but can be less in softer formations. 3. Junk slot area – same discussion as in section 1.6.13 4. Can I ream & back ream with the tool? 5. Does the whole system rotate? Some types of system have non-rotating parts that can cause problems when POOH and reaming. 6. Will there be an increase in ROP? If so, is the flow rate sufficient to still clean the hole?
1.6.3. Drilling tools and Equipment. The intention of this section is to discuss the downhole drilling tools that can help us mitigate stuck pipe hazards and improve our hole cleaning efficiency. Jars and accelerators will be discussed in section 4.3 1.6.3.1. Tools to improve the hole cleaning efficiency. When trying to improve any system it makes sense to try and concentrate on the factors that have the biggest influence. In the case of hole cleaning it is flow rate, string rotation and low-end mud rheology. If we assume that the mud type and solids control equipment control the rheology, then the only things we can influence with downhole equipment is the flow rate and string rotation/improved cuttings agitation.
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1.6.3.2. Drill Pipe. Drill pipe accounts for ± 60% of the pressure losses in the circulating system and the maximum flow rate, is governed by the circulating pressure loss in the system and the pressure rating of our mud pump liners. When the circulating pressure (system pressure drop) reaches the maximum pressure rating of the liner we have to do something if we want to continue drilling deeper in the same hole size. The normal procedure is to gradually reduce the flow rate to keep the circulating pressure just below the pressure rating of our liners. Obviously this has a negative impact on our hole cleaning efficiency, especially in critical sections of our well. To enable us to pump more flow rate for a given pressure we have to change one of the parameters that contribute to the circulating pressure loss in the system. If we assume the mud rheology, hole geometry and BHA configuration is fixed then the only option open to us is to increase the ID of the drill pipe. This means using larger drill pipe (see Figure 32). Many engineers believe the main reason to pick-up larger to drill pipe is it reduces the annular x-sectional area and thus increase the annular velocity for the same flow rate. Figure 34 shows that while this is the case, it is negligible compared to the increase in annular velocity provide by the increase in flow rate caused by the reduction in the drill pipe pressure loss.
Figure 32: This graph illustrates the advantage of using larger DP by comparing the standpipe pressure for an example well. Two hole sizes are considered, in each hole size three sizes of DP are used. For this example a maximum stand pipe pressure is assumed to be 3800 psi. The depth of the 17.5" hole is 6000' and the depth of the 12.25" hole is 10000'.
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Annular Velocities for 800gpm flow rate & varying hole sizes & 6 5/8" 600 An nul 500 ar Vel oci 400 ty (ft/ 300 mi n) 200
5" DP 6 5/8" DP In the small hole sizes ECD issues could start coming into play.
100 0 17.5
16.5
15.5
14.5
13.5
12.5
11.5
10.5
9.5
8.5
Hole Size (in)
Figure 33: This chart illustrates the difference in annular velocity when pumping at a constant flow rate of 800gpm and using different drill pipe sizes e.g. 5” & 6 5/8” and a variable hole size.
Other factors to consider when up sizing DP: a) Derrick set back area and size of the monkey board. Can they accommodate the larger pipe? b) Higher ECD’s, torque & hook load, especially in small hole sizes. c) Time required to lay down & pick-up new pipe e.g. laying down 6 5/8” DP & picking up 5” DP to drill 8 ½” hole. The additional time required should not be an argument against switching to bigger DP if it reduces the chances of getting stuck and enables the rig to drill within the box. d) Well control equipment for new size of DP. e) Lifting equipment e.g. elevators, lifting subs etc. f) Fishing tools. Do you have them available? Are they conventional sizes? etc. Further documentation on the advantages of using different DP sizes can be found in: InTouch Content ID 2021253: ERD Drill Pipe Feasibility Study: Technical report which analyses the interaction between different OD/ID combinations of 5", 5 1/2" & 5 7/8" plus tapered drill strings. It is used to identify the best drill pipe for future wells. Criteria being lowest surface torque, lowest ECD & lowest Standpipe pressure. 1.6.3.3. BHA components: BHA components e.g. directional drilling tools require large pressure drops to power the tools. The table below gives some representative figures.
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Tool
Pressure drop across tool
Powernap A962XP, 9 5/8” OD, 3:4 lobes, 4.5stg Powernap A962XP, 9 5/8” OD, 3:4 lobes, 6stg Power Pulse - 8 ¼” Normal Flow Power Drive – X5
305psi 580psi
506psi 100psi tool, 600-800psi back pressure from bit Turbine 1500psi Table 7: Pressure drops across different BHA components.
It is impossible to eliminate these pressure drops whilst drilling, but if additional flow rate is required at TD, prior to tripping, a multi opening & closing circulating sub (PBL) can be placed on top of the BHA to bypass the flow straight into the annulus. For further information on this tool go to: http://www.dsi-pbl.com A performance report on the use of a PBL sub for Shell Gabon between '97 and '98 is in Touch Content ID 3316624. Bit: Bit nozzle area does have an associated pressure loss, but the nozzles are normal sized to provide the required backpressure for the directional drilling tools and optimisation is limited. 1.6.3.4. Bladed Hole Cleaning Drill Pipe: Bladed drill pipe has been developed by different manufactures to improve the hole cleaning efficiency. The different types available are fairly similar in design and all promote the same advantages: − − − − − − −
Disturbs Cuttings beds to produce a clean hole Reduces Wall Contact Reduces Drilling Torque and Vibration Reduces Drag Reduces Casing Wear Prevents Differential sticking Prevents Buckling
Figure 34 shows two companies products: Hydro-clean from Smith & E.P.D.P from Stable Services Ltd.
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Figure 34: Shows two different types of bladed hole cleaning DP that are available on the market. http://www.smf-international.com/hydroclean/ http://www.stable-services.co.uk/
The following text is taken from Smiths website and is a brief explanation on how hydroclean works? “Compared to a conventional profile, which only agitates cuttings, the patented hydroclean profile is a combination of angles that work in harmony to provide a number of effects resulting in the cuttings being re-introduced into the flow stream. It works by creating a differential pressure that moves the particles from high pressure to an area of low pressure where they are held in place in the vortex created by the rotation”. K & M’s experience on these tools (from their ERD manual): “K & M’s experience with these tools has shown no obvious benefit to the string if good hole cleaning practices were already in place”. Industry Research has shown that under test conditions these products do improve the hole cleaning efficiency. SPE 59143 Improved Hole Cleaning and Reduced Rotary Torque by New External Profile on Drilling Equipment
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However, the general industry response is mixed. Some operators have had great success using these products, while others have not seen the improvements that they wanted. In practice it really is dependent on the specific conditions. The general rule is that if you do decided to run this pipe then you should follow the companies placement guidelines even if it means picking up a lot of additional pipe. In all cases the results should be compared with standard DP and the learning’s and results cascaded to the WE community. Schlumberger does have some experience with this type of drill pipe and the reports can be found at the following Intouch content pages: Content ID: 3278829 Multi drillstring ID changes attenuate signal: MWD signal attenuation when hydro clean DP pipe was alternated with standard HWDP. Content ID: 4060205 Use of Enhanced Drill Pipe and Torque reducing devices in KE5-01, AGIP KCO: Discusses the impact of the drill pipe in reducing torque and the reduction of the risk of differential sticking.
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1.7. Drilling Fluid Selection. 1.7.1. Vertical wells - Hole cleaning 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, packoff, aggravated BHA balling, etc) due to a combination of high ROP, insufficient flow rates, and insufficient rheology (especially low 6 & 3 rpm’s and YP). High-vis sweeps may need to be programmed to clean the hole properly.
1.7.2. Deviated & High Angle wells 1.7.2.1. Mud Selection Critical technical issues that need to be considered in drilling fluids selection process are detailed in the following table: Issue
Impact on Drilling Fluid Selection
Hole cleaning Capability
The mud property design, and rheology, must take into account the flow rate capability of the rig. Rheology will be heavily dependent upon the actual fluid used. In general, hole-cleaning capability can be attributed to a wellmaintained 6-rpm reading. Target 6 rpm readings should be 1.0 – 1.2 x hole size in inches.
Hole cleaning requirements And lithology
An inhibitive mud will require better hole cleaning conditions than a dispersive system. Dispersive systems allow long, large high angle surface holes to be successfully drilled, despite relatively poor hole cleaning parameters, because the cuttings are predominately dissolved into the mud. Note: that the lithology must be appropriate if dispersion is to be relied upon as an effective hole cleaning tool.
Wellbore stability
Required minimum mud weight and inhibitive performance of a drilling fluid are closely related. In most cases, with improved inhibition the well will require less mud weight for stability purposes. Therefore, the chemical interaction between the rock and drilling fluid has been minimized (or taken out of the equation) and the mud weight is now only required to maintain the mechanical strength of the rock.
Time Dependency of Formation
Hole sections are generally open much longer and must be tripped through more often than on conventional wells. Therefore, it is very important that the wellbore is either maintained in good gauge condition or is allowed to disperse in a mud making system. Shale hydration is a common problem in the industry that is amplified in ERD wells. It is important to be able to run with a minimum mud weight to slow down the hydration process and/or to minimize the chemical interaction with the wellbore. An invert emulsion (e.g. OBM or SBM) system keeps the water away from the rock and virtually eliminates the hydration process if the fluid’s water activity (Aw) level is designed properly for the formations being drilled.
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Well control
This is not only a mud weight issue. Factors such as gel strength properties (that 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 flow rates with increased mud weights must be considered.
Lubricity
In an ERD well, lubricity is an important factor in the total picture of hole cleaning. If a drilling fluid is providing better inhibition and keeping the hole gauge, then hole cleaning is greatly improved. This will lead to fewer cuttings in the hole (i.e. Cuttings beds), which will produce lower coefficient of friction (cof) factors. WBM lubricants are available and have proven effective at obtaining OBM-like cof. These systems are not as inhibitive as the OBM systems, and require continuous additions.
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 are shallow by their nature, and are commonly underpressured. This is critical, given that there is less capability to accommodate further increases in torque and drag, and there is less available jarring capability to deal with stuck pipe. Differential sticking can act on bha’s in degrees. Namely, just because an assembly is not differentially stuck, does not mean that there is not a degree of differential sticking acting on the assembly. These forces act to drive the cof in the well up and often play a role in the viability of the hole section. Selecting the proper fluid and/or fluid additives/lubricants to minimize the effects of the differential sticking is a key issue in high angle wells.
Accretion (Bit Balling)
This affects both drilling and tripping. The mud system’s anti-accretion performance has a dramatic effect on the bit and BHA selection, bit hydraulics, rig flow rate capabilities, tripping capability, well control (swabbing), and hole cleaning risks. New HPWBM, Glycol and Silicate WBM systems have been successfully used for the prevention and mitigation of accretion. These products preferentially attach/coat themselves to steel and have eliminated accretion tendencies in many wells. OBM is the most effective way to deal with accretion problems. Accretion is an important issue in high angle wells, because bit hydraulics is often compromised due to limited rig capabilities. Accretion should not only be thought of as the commonly viewed “global balling”, but also the “micro-balling that occurs at the cutters.
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 factor in many programs. The shallower the vertical depth of an high angle well, the more effect the pressure drop in the annulus will have on ECD. For example, in a 25,000’ (7,600.) Vertical well, a 1,000 psi annular pressure drop would only add a matter of ±0.8 ppg to the ECD. In comparison, a 25,000’ MD high angle well at 6,000’ TVD (2,440m TVD) will experience a ±3.3 ppg emw increase for the same annular pressure drop.
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In hindsight, the industry has many wells where ecd’s have exceeded 10 ppg emw while running casing, which explain the frequent lost circulation problems that are associated with some hole size/casing combinations. Typical ecd fluctuations in shallow 8 ½” high angle wells will run up to 5.0 ppg emw, unless the well has been specifically designed to limit ecd’s. The selected drilling fluids play an important role in managing ecd’s. Table 8: Technical issues that need to be considered in drilling fluids selection for deviated wells. However, many of the issues are equally valid for vertical holes.
Main mud selection criteria for drilling high angle holes are: hole-making ability (i.e. prevention of bit-balling), wellbore stability in shale’s, 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 readings 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, packoff and lost circulation, and well control. Minimizing barite sag tendency requires dedicated formulation of the mud for sag control (using sag control agents such as organophilic clays), proactive 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. 1.7.2.2. Mud Properties The mud weight required for both wellbore stability (as determined by off-set data) and well control should be maintained prior to drilling into formations. Field experience shows that it is usually possible to maintain a mud weight of 0.2 – 0.3 ppg below the calculated 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 calculated recommended mud weight) will inevitably lead to wellbore enlargement (with caving’s and reduced annular velocities complicating hole cleaning), packoff problems (with associated fracturing & lost circulation risks), hole collapse, and stuck pipe.
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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. Mud rheology should be optimized in accordance with hole cleaning simulations (e.g. Virtual Hydraulics*). 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. Use 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. gelation) 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 lb/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 costs). 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 well bores, strongly favouring 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 holes, as all cuttings are kept intact (i.e. no dispersion occurs) and must be removed from the hole.
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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 aggregated by low shear operations (e.g. slow pump rates and slow pipe rotation, tripping, logging, small wellbore influx, slow fracture breathing etc.), which should be minimized if at all possible. Mud treatment recommendations (e.g. maintenance requirements on sag control agents such as organophilic clays in the correct ratios) 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 during trips.
1.7.3. Differential Sticking Prevention of differentially stuck pipe is primarily established by selecting optimum mud properties (density and plastering properties), to control the pressure differential between mud column pressure and formation pore pressure and the composition and thickness of the filter cake. Good filter cakes can be obtained with any of the water-based muds; hence no obvious preference exists for any of the water-based muds. IOEM provides superior mud cakes with regard to thickness and lubricity. This mud type could, therefore, be considered in holes with an increased risk of differential sticking, e.g. deviated hole sections over pressure depleted reservoirs.
1.7.4. Reactive/time dependent shale’s. Borehole instability in shale’s is a major source of drilling trouble time, and is thought to be the cause of approximately one-third of all stuck pipe cases. Stability problems generally build up in time, starting with shale failure at the borehole wall, followed by transfer of shale fragments into the hole. Then, if hole cleaning is insufficient, problems such as "sticky" hole, packing off, and hole fill and stuck pipe will occur. Eventually this may result in losing the hole and having to sidetrack. Other negative consequences include high torque and drag, and poor cementations. The fundamental reasons behind shale failure are covered in Chapter 8 of the Trouble Free Drilling Manual. This section will summarize the best drilling fluids to use to minimize the impact of unstable shale formations. 1.7.4.1. Non water based fluids OBM Historically OBM has shown to be the best shale drilling fluid. The main reason for this is capillary effects, which prevent pore pressure invasion (See figure 35 & the Drilling Fluid Filtrate section, in Chapter 8 of the Trouble Free Drilling Manual).
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Figure 35: Non-water based systems are effective in preventing pore pressure penetration in shale’s due to capillary effects.
OBM also has very good lubricating properties and high temperature stability, making it very suitable for deep and long reach wells. However, due to environmental constraints it will not be possible to use OBM without cuttings re-injection in the near future and thus alternative muds have to be considered. Pseudo OBM Pseudo OBM’s behave similarly to conventional OBM, preventing pore pressure penetration in shale’s through capillary action at the pores. The systems are based on nontoxic biodegradable material such as esters or ethers. The main drawbacks to Pseudo OBM are the high costs and limited temperature stability of ester based muds such as Petrofree (140-150°C). 1.7.4.2. Water Based Fluids The effectiveness of water-based shale drilling fluids is dependent on the inhibiting principle (pore pressure penetration or hydration stress) and on the amount of chemicals used (cost). A mud that eliminates pore pressure penetration also prevents the effects of hydration stress since no fluid is allowed into the pores. A mud designed to prevent hydration stress by inhibition automatically implies a (de-stabilising) pore pressure invasion!! Examples of water-based shale drilling fluids are KCl/Polymer muds, viscous brines and Polyglycol systems (Aquacol, SSL-5). Brine systems All salts reduce hydration stress in shale’s, but certain salts are more effective than others. However, salts are not capable of reducing hydration stress to zero. The strongest inhibitive effect is seen from Potassium Chloride (KCl) mud, which is why KCl is used frequently as a basis for shale drilling fluids. Field trials with high concentration KCl
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mud indicate this mud to be less effective than Polyglycol muds. The drawback to most salt systems is that they do not reduce pore pressure penetration. Salt ions are simply too small to plug a shale pore system. Also, brine filtrate viscosity at saturation is generally equal to that of water, which is not enough to hamper pressure invasion. Exceptions to the above are Saturated CaCl2 brine and high-density formates, which both have a high filtrate viscosity causing a strong reduction of pore pressure penetration in shale’s. It should be noted that reduction of pore pressure penetration is dependent on filtrate viscosity and not "bulk" fluid viscosity. A high viscosity drilling fluid can have a low filtrate viscosity that will not affect pore pressure invasion. Polyglycol muds A number of systems advertised as shale drilling fluids are based on glycol and glycerol polymers. Examples of polyglycol muds are thermally activated mud emulsions like BW's SSL-5 and Milpark's Aquacol. An advantage of both mud systems is the environmentally friendly principle on which they are based. The muds contain low molecular weight polygylcols that will cloud out and form an emulsion above a certain temperature (cloud point). This emulsion creates a film on the shale surface that acts as a filter cake and thus reduces pore pressure penetration.
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1.8. Rig sizing and capability. The rig can play an import role in stuck pipe prevention and in many cases is a major contributing factor in getting us stuck. In most situations we do not have the luxury of drilling with the ideal rig with unlimited hydraulic capacity and the perfect solids control system. In reality we have to make some compromises and it is important to know the rigs limitations before we drill a well that it is out of the operating envelope of our rig. The rig capacity is a major factor in determining the size of the drilling box that we can safely operate in and the main components are: Hydraulic capability Rotary capability. Power capability. Solids control equipment. For additional information on this topic see: Intouch Reference Page Content ID 3956915: Rig Selection, Inspection and Operations Intouch MCA GFE Content ID: 3956721: Project - Rig Selection
1.8.1. Hydraulic capability: In general the 12 ¼” section on deviated wells will determine the rigs pumping requirements, but this is not always the case. It is therefore important to determine where the maximum pressures and flow rates will occur and then determine whether the rig can meet these requirements. Modelling the hydraulics and using the relevant offset data to calibrate the model allows us to do this. What determines the maximum flow rates and pressures of our system & how can we improve it? 1.8.1.1. Rig pumps (triplex). Bigger pumps can provide more flow rate for the same pump pressure than smaller pumps. The table below is taken from the National Oilwell website and it shows the range of triplex pumps they offer.
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Input Power
Max. Pressure
Length
Width
Height
HP (kW)
PSI (kg/cm2) GPM (LPM)
ft in (mm)
ft in (mm)
ft in (mm)
lbs (kg)
7-P-50
500 (372)
4830 (340)
160 (605)
11’ 10" (3614) 6’ 7" (2069)
4’ 6" (1384)
16750 (7600)
8-P-80
800 (597)
5000 (352)
222 (840)
13’ 6" (4105) 7’ 10" (2385) 5’ 0" (1524)
26970 (12235)
9-P-100
1000 (746)
5000 (352)
287 (1085)
14’ 8" (4477) 8’ 6" (2572)
5’ 4" (1626)
33200 (15060)
10-P-130
1300 (969)
5000 (352)
357 (1351)
15’ 7" (4740) 8’ 11" (2727) 5’ 7" (1702)
42550 (19300)
12-P-160
1600 (1193)
5000 (352)
444 (1682)
17’ 5" (5309) 9’ 6" (2890)
6’ 3" (1905)
54700 (24810)
14-P-220
2200 (1640)
7500 (527)
375 (1419)
18’ 2" (5544) 10’ 6" (3194) 7’ 1" (2139)
82000 (37195)
A-1400-PT
1400 (1044)
5000 (352)
382 (1446)
16’ 0" (4877) 7’ 11" (2407) 7’ 5" (2267)
40950 (18575)
A-1700-PT
1700 (1268)
5000 (352)
459 (1728)
16’ 0" (4877) 7’ 11" (2407) 7’ 5" (2267)
41350 (18756)
HD-1400-PT
1400 (1044)
5000 (352)
367 (1389)
16’ 0" (4877) 7’ 11" (2407) 7’ 5" (2267)
47780 (21673)
HD-1700-PT
1700 (1268)
5000 (352)
444 (1682)
16’ 0" (4877) 7’ 11" (2407) 7’ 5" (2267)
49030 (22240)
Model
Discharge
Weight
Table 9: Shows the different triplex mud pumps available from National Oilwell
Different pump liner sizes determine the working pressure and maximum flow rate of the pump and the amount of flow is inversely proportional to the pressure. The table below is taken from the National Oilwell website and its shows the different liner sizes for their 10-P130 Mud Pump. The industry rule is that the pumps can be run at 90% of maximum for continuous operations e.g. ± 120 spm. However, the condition of the pumps and the climate does play a role and a realistic figure for planning is 100spm. It is important to factor this limit into any sizing calculations because you will have overestimated your rigs pumping capability if you use the 140spm values. Liner size, inches (mm)**
6-3/4 6-1/2 6-1/4 6 5-1/2 5 4-1/2 (171.5) (165.1) (158.8) (152.4) (139.7) (127.0) (114.3)
Max. Discharge 3085 Pressure, psi (216.9) (kg/cm²)
4 Pump Max. Hydraulic* (101.6) Speed Input
3325 (233.8)
3595 (252.8)
3900 (274.2)
4645 (326.6)
5000 (351.5)
5000 (351.5)
5000 (351.5)
GPM* (LPM)*
GPM (LPM)
GPM (LPM)
GPM (LPM)
GPM (LPM)
GPM (LPM)
GPM (LPM)
GPM (LPM)
spm
HP
HP
651 (2463)
603 (2284)
558 (2111)
514 (1946)
432 (1635)
357 (1351)
228 289 (1093) (863)
140 spm †
1300 hp †
1170 hp
558 (2111)
517 (1958)
478 (1810)
441 370 (1668) (1401)
306 (1158)
196 248 (939) (742)
120 spm
1114 1003 hp hp
465 (1759)
431 (1631)
398 (1508)
367 309 (1390) (1168)
255 (965)
207(784)
163 (617)
100 spm
929 hp
372 (1407)
345 (1305)
319 (1207)
294 (1112)
247 (934)
204 (772)
131 165 (625) (496)
279 (1056)
259 (979)
239 (905)
220 (834)
185 (701)
153 (579)
124 (469) 98 (371) 60 spm 557 hp 501 hp
Vol./stroke, 4.647 4.309 3.984 3.671 3.085 2.549 gal. (Liters) (17.592) (16.313) (15.082) (13.9) (11.679) (9.652) * Based on 90% mechanical efficiency and 100% volumetric efficiency
2.065 (7.816)
836 hp
80 spm 743 hp 669 hp
1.632 (6.177)
Table 10: Shows the liner sizes for National Oilwells 10-P-130 Mud Pump. The 120 & 100spm rows have been highlighted, as these are the realistic maximum continuous pumping rates.
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The rig contractor will probably not be contracted to carry all the liner sizes. Check what is available, and if a different size is required then get the drilling contractor to order it. Additional pumps. An additional pump enables you to pump at a higher flow rate for a given pressure rating and can provide redundancy. The additional flow rate advantage is shown below: Pumping at 100spm with 6” liners (values taken form the table above) 2 pumps: maximum flow rate = 734gpm at 3900psi 3 pumps: maximum flow rate = 1101gpm at 3900psi There are some significant issues with adding an additional pump to the rig. These are: − Additional cost. − Power capability of the rig normal needs upgrading. − The additional flow rate might not give a significant advantage. 1.8.1.2. Surface Lines & Standpipe manifold. The surface lines & standpipe manifolds are normally rated to 3000psi, 5000psi or 7500psi. The important aspect is to check that the maximum pump pressure does not exceed the rating of the surface lines. This is unlikely, but can happen for example when you have a 3000psi system and > 1000HP pumps.
1.8.2. Rotary capability: To achieve effective hole cleaning the drill string should be rotating at a continuous rpm sufficient to clean the hole (see section 1.4). Torque calculations at the planned rpm should be made for each hole section and then compared with the rigs rotary system torque rating for that rpm. This is important as the maximum quoted torque normally drops off as the rpm is increased (see Figure 37). Different types and sizes of rotary tables are available i.e. series or shunt, gears or no gears, and they normally have a lower torque rating then there top drive cousins. It is important in the planning phase to get the amp vs. torque graph (see below) for your specific rotary table to determine the rigs torque capability especially when drilling a deviated/horizontal well.
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Figure 36: The charts are taken from the Transocean SedcoForex drilling practices manual and shows the evolution of pumping & torque capabilities with time.
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Figure 37: Shows the torque output curves vs. rpm for the 3 different TDS’s. The graph clearly shows that the maximum torque output changes with RPM. The message here is to check your torque rating at the required rpm for your topdrive or rotary table.
Example: Figure 38 shows an amps vs. motor torque graph for a 37 ½” table on a kelly drilling rig. The torque output of the table in the figure is extremely low, and in this specific example the rig had problems drilling deviated wells. In this case the original rig was designed for a 27 ½” table. The rig was then refurbished and a 37 ½” table installed. However no modifications were made to the substructure below the rig floor. As a result no room was available for a gearbox and the table was permanently in high gear. This meant when medium to high torque was experienced the table just died!
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Figure 38: Shows an amps vs. motor torque graph for a 37 ½” table. To establish the string torque, take the amp reading from the gauge on the rotary table. Project up from the x-axis until the line intersects the torque vs. amp line. Project across to the y-axis until the line intersects the motor shaft torque. Multiply this value by 3.6. This gives you the string torque. For the example shown the amp reading is 750. Following the red line it intersects the motor shaft torque axis at 3200 ft.lbs. This value multiplied by 3.6 equals a string torque value of 11520 ft.lbs.
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1.8.3. Power Capability: Rig power is one of the most important issues to consider in rig design specifications and they are many stuck pipe events that can be attributed to operating outside of the rig’s power capabilities. The maximum power requirements for the well should be calculated and compared to the rigs capability. Older rigs may have a certain capability on paper, but in reality this is not the case. It is important to confirm actual versus theoretical before drilling commences especially when the rig is close to its limits. This can be achieved by performing a load test on the power system & this should be part of any rig acceptance criteria.
1.8.4. Hoisting capability. Every engineer should be able to calculate the maximum hook loads in the well and compare them with the maximum loads for the hoisting equipment, drill pipe and derrick/mast. It can get a little more complicated in deviated wells where the drag comes into play, and friction factors have to be estimated. In this case it’s better to come up with a range of values by varying the friction factor in the model. Maximum over pull limits need to be calculated and based on the weakest component in the system. In most cases this will be the DP, but on light rigs the derrick rating can be the limiting factor. The minimum margin O/P should be at least 100,00lbs during drilling operations.
1.8.5. Solids Control Equipment: It is important that we have a basic understanding of the solids control equipment on the rig because the mud condition plays an important role in preventing stuck pipe incidents. This next section we give an overview of the solids control equipment on the rig and will give some operating guidelines. Figure 39 shows a schematic diagram of the surface mud system 1.8.5.1. Shale Shakers: Shale shakers are probably the most important device in the solids control system in terms of the amount of low gravity solids (LGS) removal. When one views the piles of discarded LGS accumulating beneath various pieces of solids control devices, the pile beneath the shale shakers is usually significantly larger than under any other group of devices. In fact, the pile is usually larger than all other devices combined. Shale shakers are vibrating screening devices that process returning drilling fluid laden with drilled cuttings or low gravity solids. The LGS returning in the fluid vibrate across the screen and are discarded from the end of the shaker deck. The fluid flows through the screen, along with fine LGS and is recovered for further processing and re-use. In general, when finer screens are used (screens with smaller holes in them), greater amounts of drilled solids are removed. However, when finer screens are used, less fluid will flow through the
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openings in the screens and less fluid can be processed. This relationship between fluid processing capacity and particle size removal must be understood in order to understand shale shaker operations.
Tank/Mixing Capacity Is the tank volume sufficient? What reserve volumes are required? What is the mixing capability of the system?
Shakers Does the rig have enough? Do you have the correct sized screens? What is the plan when they get overloaded?
Flowline. Dimensions – is it large enough? Access Points in case of blockage?
Cuttings Shoot Dimensions – is it large enough? Access Points in case of blockage?
Figure 39: Schematic of the mud system on the rig.
Table 11 shows the relationship between the amounts of fluid that can be processed by one shale shaker dressed with certain sized screens and the separation potential for that screen. This figure is an approximation compiled from a number of different sources and should not be used too literally, but is excellent for demonstrating the concept. Coarser screens, such as the API 40, can process a large volume of fluid (850 gallons per minute), but only remove particles larger than 410 microns. If the drilled solids coming to the surface to be processed contain particles smaller than 410 microns, the shakers will not remove them. The only way to remove finer particles with the shakers is to use finer screens; however, by using finer screens, the maximum flow over one shaker must be reduced or the screens will blind and fluid will be lost over the end of the shaker.
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Figure 40: Picture of a typical shale shaker.
API Number
Maximum Flow (GPM)
40 60 84 110 140
850 620 390 350 300
Separation Potential (microns) 410 250 180 140 110
160 175 210
275 250 200
100 80 70
Table 11: Relationship between flow capacity and separation potential.
Fluid flow to the shale shakers is fixed by the circulating rate of the drilling fluid. The circulating rate of the drilling fluid, after considering hole cleaning and hydraulic horsepower at the bit, will generally be between 35 and 50 gallons per minute per inch of bit diameter. This was an old rule-of-thumb prior to computer hydraulic calculations. This means that the desired circulating rate for 17-1/2” hole might be 900 gallons per minute. At that circulating rate, two shakers screened with API 60 screens could probably process the entire flow, but two shakers with API 84 screens would probably blind. If three shakers
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were available, then API 110 screens or API 140 screens might be able to process the flow. Since the separation potential with increasing API number is much better, the finer screens would make a more efficient removal of low gravity solids (LGS). In the past, most drilling rigs only had two shale shakers. Recognition of the increased separation potential with finer screens and the general trend towards drilling larger hole sizes (deeper drilling requirements) have caused many rigs, especially offshore rigs, to have as many as six or more shale shakers. One additional factor must be considered in the flow capacity equation. The amount of solids loading on the shale shaker screen can affect the amount of flow that can go through the holes in the screen. Thus, an adjustment to the maximum flow for solids loading must be made. Table 12 shows the adjustments for mud weight that should be made to the maximum flow rate. This table indicates that if drilling with a 12 pound per gallon (ppg) drilling fluid, and the maximum flow capacity of a shaker and screen was 500 gallons per minute, then the actual flow capacity (reduced due to high solids loading) would be 450 gallons per minute.
Mud Weight Reduction Range (ppg) in Flow 8.34 - 11.0 11.1 - 13.0 13.1 - 15.0 15.1 - 17.0 > 17.1
1.00 0.90 0.80 0.70 0.65
Table 12: Reduction in maximum flow capacity for high gravity solids loading
What screens should be run? Example 1 What screens could be run in 26” hole with a 10.5 ppg maximum mud weight if only two shakers were available? The flow rate desired for this hole size is likely to be 1,300 gpm (50 x 26). Since two shakers are available, each would have to handle half of the flow or 650 gpm. From table 11, the capacity of an API 60 screen seems just slightly too low, while the capacity of an API 40 screen is sufficient. Since the mud weight is low, no correction factor is needed. Example 2 What screens could be run in 14-3/4” hole (maximum size drilled with bi-center bit) with a 13.5 ppg maximum mud weight if four shakers were available?
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The flow rate desired for this hole size is likely to be 750 gpm (15 x 50). If this flow were divided between four shakers evenly, then each shaker would need to handle slightly less than 200 gpm. But with the solids loading likely to be fairly severe, a reduction from the maximum flow would indicate each shaker would have to handle about 20% more fluid in order to process the desired amount of fluid and solids. This means that each shaker would have to handle 235 gpm (750 / 4 / 0.80). From table 11, API 175 screens could be run. Example 3 How many shakers would be needed on a rig intending to drill the following hole sections? Section 1 is 26” hole with maximum 10 ppg mud (API 140 screens desired) and section 5 is 8-1/2” hole with 17.5 ppg mud (at least API 210 screens are desired). For section 1, the anticipated circulating rate would be 1,300 gpm (26 x 50). No solids correction is needed, so the flow per shaker is obtained from table 11. API 140 screens can tolerate 300 gpm per shaker. This means that the total number of shakers required would be 5 (1300 / 300). Note that four shakers could only process 1,200 gpm. For section 5, the anticipated circulating rate would be 425 gpm (8.5 x 50). Since the mud weight is very high the maximum flow needs to be adjusted for solids plugging on the screens. In this case the adjustment is 0.65. This means that the overall flow is increased to 654 gpm (425 / 0.65). From table 11 the flow per shaker is 200 gpm; therefore the number of shakers required would be 4 (654 / 200). The answer to example 3 is that the rig would need five shale shakers to carry out the envisioned program (given these two sections alone). This provides an easy way to quickly estimate screens that can be run on a shale shaker without having field data available. Naturally, this estimation technique is not completely accurate. Many factors, including shaker type, screen type, fluid properties, etc, could drastically alter screen performance. 1.8.5.2. Hydrocyclones and Mudcleaners Hydrocyclones are accelerated gravitational separation devices. The accelerated gravity comes from centrifugal force caused by the fluid spinning inside the hydrocyclone. Hydraulic head being supplied by the feed pump causes this spin. Since an artificial gravitational force is being applied to the hydrocyclone, solid particles tend to settle. In this case settling means movement toward the shell of the hydrocyclone. Solids laden fluid near the shell of the hydrocyclone is expelled from the hydrocyclone through a nozzle at the bottom. The bulk of the fluid gets sucked into a vortex spiralling upward in the cone and is removed at the top of the cone. Hydrocyclones come in a variety of sizes. The largest common hydrocyclone is 12 inches in diameter. Another common large size is 10 inches. These large hydrocyclones are commonly called de-sanders. Another very common size is 4 inches. Four-inch hydrocyclones are referred to as de-silters. There are also hydrocyclones in the 2 inch and 3 inch range. The amount of fluid that is processed through the hydrocyclone cone is
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dependent on the size. Table 13 shows the processing rates of some common hydrocyclone cone sizes.
Cone Diameter Flow Rate Through (inches) One Cone (gpm) 2 4 10 12
25 50 500 500
Figure 13: Hydrocyclone cone processing rates.
The particle size separated by the hydrocyclones is also dependent on the cone diameter. Larger cones (de-sanders) will typically remove particles above 80 microns. The smaller desilters will remove particles above about 40 microns. With these removal targets, desanders are operating on about the same range particle as finer shale shaker screens. Desilters may remove slightly finer particles. Hydrocyclone discharges are characterized by high fluid to solid particle content. Whereas shale shakers usually remove about equal volumes of solid and liquid, hydrocyclones may remove 3 parts liquid to every part solid (sometimes as high as 5 times). Typically, the removal amount, volumetrically, by a hydrocyclone is about 10% of the feed stream, but this is highly variable based on operating conditions. On drilling rigs, a bank of de-sander cones is usually two or three 10” or 12” cones. A bank of de-silters is usually eight, twelve, or sixteen 4” cones. A bank of eight 4” cones will process about 400 gallons per minute and discharge a volume of concentrated solids at about 40 gallons per minute. Hydrocyclones are intended for operation when un-weighted, water-based mud is used. Barite and polymers will be concentrated in the discharge stream. Thus, there will be an economic consideration about when to stop using the hydrocyclones when mud weight is increased or expensive polymers are added. A mud cleaner is a bank of hydrocyclones mounted above a shale shaker equipped with fine screens4. Obviously, the screens on the shaker deck must be able to handle the fluid and solids being discarded by the hydrocyclone bank. One of the weaknesses in mud cleaner design is the inability of the screen to process the full discard. A typical response to this is to either pinch back the hydrocyclones to operate inefficiently or to choose a screen with larger screen openings to allow full processing. The original concept of the mud cleaner was to remove particles in the range between API 200 screens (74 micron) and API 80 (170 micron) screens. The mud cleaner was equipped with API 200 screens because barite is removed with finer screens. At the time of their development API 80 screens were the finest practical screens that could be run on shale shakers. This remains one of the primary reasons for using a mud cleaner; however, since shale shakers have improved so much, the use of mud cleaners is declining.
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A second purpose of a mud cleaner is to recover expensive base fluid in un-weighted mud. If, for example, expensive potassium chloride fluid is being used, an extremely fine screen could be run on the shaker deck and fluid (along with very fine particles) could be recovered. The particles removed by the hydrocyclones (including barite) would be discarded. This is obviously an economic decision. 1.8.5.3. Centrifuges Decanting centrifuges act to separate solids from liquid by imparting high centrifugal force on the slurry5. The bowl spinning at high rotational speed causes the high centrifugal force. The feed slurry enters through the center of an internal auger and is released into the bowl through the feed ports. Since the centrifugal force acts to push solids to the outside of the bowl, a conveyor (auger) pushes them towards the solids discharge end of the centrifuge. Liquid drains (decants) from the opposite end. Figure 41 shows a drawing of a centrifuge operation.
Figure 41: Centrifuge operation drawing.
Centrifuges are not intended to operate on the entire flow stream or circulating rate as other pieces of solids control equipment are. Instead, a high-speed centrifuge will operate at about a maximum of 150 gallons per minute (gpm) with un-weighted (9 ppg) mud. As mud weight is increased to the 16 ppg range, throughput capacity decreases rapidly to the 20 gpm range. There are some relationships that should be understood in centrifuge operations. Increasing G-force improves separation of solids from the liquid feed slurry. In one series of tests, 90 pounds per minute of cake (solids) were removed at 900 G, while 75 pounds per minute of cake were removed at half the G-force. Cake removal is adversely affected by increased viscosity. Under the same conditions of 900 G described above, increasing the
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yield value from 8 to 24 decreased the cake formation from 90 pounds per minute to 75 pounds per minute. Maximum flow capacity is obtained with minimum pond depth, but maximum separation occurs with maximum pond depth. The best combination of separation and flow capacity is dependent on the size of the particles to be removed. For fine particle size removal, deeper ponds are more efficient than shallow ponds. In one set of tests, 50 pounds per minute of cake were generated with about 130 gpm flow rate and a two inch pond, while the same rate of cake generation required 160 gpm flow rate with a one inch pond. For coarse particle size removal, shallower pond depths are preferred. The higher flow capacity associated with shallower pond depths allows more cake removal. One use for centrifuges is to process un-weighted mud. This is the only device that can remove fine particles that other solids control devices cannot remove. It also does this with a minimum of liquid carryover in the discard. The lower limit of particle size that can be removed with a centrifuge is said to be two microns, but a more practical field limit (unless extreme care is taken) is probably 8 microns. Another use for centrifuges is to process hydrocyclone underflow. In this use, hydrocyclone discharge is diverted to a small feed tank for the centrifuge. The centrifuge is used to recover liquid from this feed. Of course, the centrifuge will also recover ultra-fine or submicron particles. Equalizers will be needed to match the processing rates of the hydrocyclones and centrifuge. This process is especially economic when high value liquid phase is being used, as with potassium chloride fluid. The centrifuge can also be “reversed” to recover solids and discard liquid phase. In this mode, coarse solids are recovered and fine solids are discarded with the liquid. This mode is used because colloid sized particles are especially damaging to drilling properties and can cause differential sticking, slow penetration rates, and high fluid treatment costs. This process is also called barite recovery because barite is a sized material with most of the particles above 2 microns. The recovery of the barite can sometimes be justified on an economic basis. Two-stage centrifuging can also be used, but is controversial. In the first stage, solids are recovered. In the second stage, the fluid and fine particles (discarded from the first stage) are processed and some small amounts of solids are discarded. Fluid and colloid sized particles are recovered. With current screening technology, two-stage centrifuging is generally less desirable than running fine screens on the shakers and using a tolerance mud system. 1.8.5.4. Solids Control Operating Principles Overview Shale Shaker −
Perforated plate screens usually exhibit longer screen life than other hookstrip screens. They provide the most support and are repairable.
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− − − −
− − −
−
Screen life is inversely proportional to plate opening size. If premature wear is apparent in the pool region, install panels with smaller perforated plate sizes at the feed end of the shaker where loading and wear is greatest. Reduce deck angles to improve solids conveyance, reduce loading and eliminate solids grinding at the feed end. If premature backing plate failure is experienced, check that all deck rubbers are in place and in good condition. Check for a buildup of solids between the screen and the support areas on the shaker deck. When possible, run the same screen mesh over the entire deck of a single deck shaker. When running different mesh cannot be avoided, the coarser mesh should be run at the discharge end. Do not vary the mesh size by more than one increment from feed to discharge. Select the finest screens, which will give 70-80% fluid coverage on the shaker. Use sufficient shakers to achieve a separation target of at least API 140 (100 microns). Always run the coarser screens on the top deck of a tandem deck shaker or on the upstream shaker. The upper deck screen should be at least two API sizes coarser than the bottom deck. It has been observed that running screens, which are too fine on the top deck can actually impede cuttings conveyance on the lower deck. Select screens for which the new API designations are known to ensure predictable performance.
In order to improve cuttings dryness, try the following: −
−
Increase deck angle. This is the simplest solution. Fluid loss along the hookstrips is reduced. Solids conveyance will decrease with steeper deck inclinations, which increases the contact time to remove excess moisture. Protection against whole mud losses due to flowline surges is also improved. Change to coarser screens. This has two effects. First, the fluid endpoint on the shaker will recede. Second, the average discharged cuttings size will increase; however, this action will result in poorer separation efficiency and higher costs. Try running a coarser screen at the discharge end before converting the entire deck to coarser screens.
In order to combat sticky solids (Gumbo), try the following: − − −
Use scalping shakers ahead of fine screen shakers. Circular or unbalanced elliptical motion shakers or shakers with short basket lengths are recommended as the scalping shakers. If space is limited, tandem deck linear motion shakers may be used. Use downhill or flat deck angles. Gumbo will not convey well uphill. Gumbo will not stick as persistently to wet screens. When spray bars are necessary to keep the screens wet, use low flow rate nozzles, which produce a fine mist with an umbrella or fan-shaped discharge. These nozzles operate at less than 0.5 gpm. No more than two are normally required. Do not use high volume or high-pressure sprays on a continuous basis. This will degrade the gumbo patties and drive the solids through the screens.
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For polymer mud systems try the following: − − −
Pre-hydrate and pre-shear the polymer before adding into the active mud system to eliminate “fish-eyes” and blinding at the shaker. Select high efficiency screens to maximize the flow capacity of the shakers. Expect an overall reduction in shaker flow capacity of as much as 40%.
Hydrocyclone − − − − − − − − − − − − − −
Operate enough hydrocyclones to process over 100% of the circulation rate or to handle the maximum solids loading rate. The hydrocyclone overflow should be discharged to a compartment downstream from the feed compartment. Use bottom equalization between compartments. Mechanically stir all hydrocyclone removal and discharge compartments to ensure uniform feed. Mud guns should not be used because they can reduce hydrocyclone efficiency by bypassing a portion of the mud. Do not allow cones to operate with plugged apexes or inlets. Spray discharge at the cone underflow is desired. Rope flow will cause premature wear and is less efficient. Rope flow indicates that either more hydrocyclones or finer shaker screens are required or that the underflow apex size is too small. Because 2-in, cones are extremely susceptible to plugging, consider using the 3-in, cone instead. It has twice the capacity and equivalent performance. Do not bypass the shale shaker or operate with torn screens. The hydrocyclone manifold should be located above the mud level in the active system to prevent accidental loss of mud by siphoning when the cones are not operating. Replace flanged-type hydrocyclones with the quick-connect type to improve servicing time. Replace worn, malfunctioning cones immediately. If no spares are available, remove the cone and blank off the feed and outlet lines. Have a working pressure or head gauge on the manifold feed inlet. Install a siphon breaker on the overflow manifold exit. Size suction and discharge piping to provide flow velocities in the range of 5-10 ft/sec. Use one centrifugal pump per hydrocyclone manifold.
Centrifuge (processing un-weighted fluids) − − − − −
When processing the active system, the centrifuge feed should be taken from the desilter discharge compartment or downstream. The concentrate should be returned to next downstream compartment. Provide enough centrifuges to process at least 25% of the circulation rate. Large, high-G units are usually required. Run at maximum bowl RPM to achieve highest G-force and best separation. Operate the centrifuge just below the flood-out point. The best-feed rate and pond depth will depend on the size distribution of the drilled solids. Use shallow ponds and high feed rates when coarse solids predominate. Conversely, deeper ponds and lower feed rates are more efficient when fine-drilled
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− − −
solids are to be removed. Field experimentation is necessary to optimize centrifuge setup. Always wash out the centrifuge on shutdown. If the centrifuge is to be used on both un-weighted and weighted fluids, rig up to allow either option. Both the concentrate and solids streams should be rigged up to allow each to be discarded or returned to the active system. The solids discharge chute should be angled at greater than 45° to prevent solids buildup. If this is not possible, a wash line may be necessary to assist in moving the solids. On land-based operations, use the reserve pit as a source for wash fluid. Do not create unnecessary reserve pit volume by using rig water.
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1.9. Software & Modeling Tools. Software packages and modeling tools can help identify, analyze and mitigate stuck pipe risks in both the planning and execution phase. This section will list the tools available and give a brief description of each. The real time monitoring programs will be discussed in the real time trend analysis section. It is the engineer’s job to select the applicable package and use it correctly. Remember: GARBAGE IN = GARBAGE OUT The table below gives a brief summary of the software available: OFFSET WELL ANALYSIS SOFTWARE Identify relevant offset wells Offset well data gathering Define objective for data Analysis Offset well data presentation
RiskTRAK RIG STATE – can take, LAS and ASCII files SPAID – Looking at events PETREL – Borehole visualization, Osprey Risk
MODELING SOFTWARE Software Drilling Office
Sticking Risk Assessor Osprey Risk Stickance Prespro RT PERFORM Toolkit
Components DrillSAFE
Hydraulic RockSolid PPW Wireline
Remarks • Tripping Load Analysis • Drill string buckling Analysis • Drilling Torque Loss computation • Rotating Axial plot with torque • Side Forces Analysis • Friction factor Calibration • BHA tendency / Vibration analysis • Cuttings load analysis & ECD modeling • Well bore Stability Analysis • Pore pressure modeling • MDT stickiness analysis Risk Identification. Differential sticking Real time MI Hydraulics
MONITORING AND ANALYSIS SOFTWARE Sticking Pipe Indicator (SPIN) Stuck Pipe Analysis (SPAID) Pore Pressure Window (PPW) Real time Hydraulics Real time Torque and Drag DrillSAFE Drilling History Super Smart Alarms
IDEAL Software Stickance Drilling Office Software PERFORM Toolkit PERFORM Toolkit Drilling Office Software Drill Viz PERFORM Toolkit
Table 14: Lists the available Well Engineering software tools.
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1.9.1. Osprey Risk Osprey Risk is a software for rapid creation of detailed drilling operational plan that provides economics and risk analysis. The User inputs trajectory and earth properties parameters along the borehole path (Pore Pressure, Fracture Gradient and Rock Strength)
Figure 42: An example of an Osprey Risk Output Page
The software uses an automated, integrated, comprehensive well planning system to provide − A technical well design, including hole geometry, casing and tubing design, bit, hydraulics, drillstring, etc. − A risk analysis including the risk of Stuck Pipe and Wellbore instability − A detailed operational activity plan − A probabilistic time and cost estimate for the project This enables a quick decision support to evaluate different well construction scenarios and high volume prospect screening in a time frame unimaginable using other tools. The major workflow components are: − −
Input Data: Provides the data the system uses to generate a well design. Wellbore Geometry: Computes such outputs as mud weights, casing points, and Wellbore sizes, and provides casing and cement design. If you have the advanced workflow, this set of tasks also provides a Wellbore Stability interface. 80
− −
Drilling Parameters: Defines actual drilling activities and their requirements. Results: Provides outputs of Osprey Risk task flow in a variety of formats.
System tasks are arranged in a single workflow in which the output of one task is included as input to the next. The user can modify each output, which permits fine-tuning of the input values for the next task. An example of Osprey Risk output is illustrated in figure 43. The table below shows the different Osprey risk categories and how they relate to the different stuck pipe mechanisms. The main problem faced with the Osprey Risk analysis is that the different risks types tend to cloud each other out. It then makes it difficult to evaluate the risk of the individual stuck pipe mechanisms such as hole cleaning.
Risk Category
High Criteria
Explanation of risk
Weighting
Hydrates
> = 3000ft
Based on water depth.
1
DLS
>= 6deg/100ft
3
Tortuosity
> = 90
Inclination
> = 65deg
Trajectory has a doglegs greater than 6deg/100ft. Summation of the doglegs severities in the well Inclination
Horizontal Displacement DDI
> = 1.0
Ratio of displacement / TVD Directional drilling index??
3
PP low
< 8.33ppg
Low pore pressure
5
Rock soft
< 2 kpsi
4
MW Frac
< = 0.2ppg
MWW
< = 0.5ppg
WBSW
< = 0.4ppg
Shear Failure
HS length
MW <= PP <= SF or SF <= MW <= PP or MW <= SF <= PP > = 8000ft
Soft clay’s have low UCS values. MW is close to the fracture gradient Frac & pore pressure close together Advanced model. Shale stability Advanced model. Shale stability
Hole Big
> = 24”
> = 6.8
Stuck Pipe Mechanism Only applicable for deep water and gas influxes. Hole cleaning Mechanical sticking
3
Hole cleaning Mechanical sticking
2
Hole cleaning Differential sticking Hole cleaning
3
5
Hole cleaning?? Mechanical sticking?? Differential sticking?? Gumbo/sticky shale’s Not really a stuck pipe driver.
4 4 4
Long hole section length
2
Large OH diameters
1
Caving's – pack-off. Hole cleaning. Caving’s – pack-off. Hole cleaning.
Hole cleaning Borehole stability with WBM Hole cleaning
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Hole Small Hole csg
< = 4.75” (on) < = 6.5” (off) < = 1.1
Csg – Csg
< = 1.005
Csg – Bit
< = 1.05
Csg – MOP
< = 50
DS – MOP
< = 50 kips
Kick Tol
< = 50 bbls
Q crit
< = 1.0
ECD Frac
< 0.0ppg
Cuttings
45 – 65 deg
Small OH diameters
3
Mechanical sticking
Ratio of area of OH / area of casing size (OD) Casing ID / Next maximum casing size Ration of casing ID / next bit size Margin of over pull on casing Margin of over pull on casing Kick tolerance is < 50 bbl Flowrate/critical flowrate Upper bound limit – ECD Avalanche area for hole cleaning
4
Annular clearance for running casing.
3
Mechanical sticking
3
Mechanical sticking
2
2
Chances of getting free Chances of getting free Not applicable to stuck pipe. Hole cleaning
5
Losses
2
Hole cleaning
3 1
Table 15: Shows the different Osprey Risk categories. The rows highlighted in yellow are directly related to stuck pipe.
1.9.2. Drilling Office. The Drilling Office software is an integrated well planning and execution package which comprises of a number of fully integrated modules that allows the drilling team to plan, execute and evaluate Wellbore construction activities. The software components useful for Stuck Pipe prevention planning include: − − − − − − − − −
Trajectory design Torque and Drag analysis BHA design/tendency prediction Casing design Circulation Pressure losses ECD prediction & Hole cleaning Analysis Wellbore Stability analysis Pore Pressure analysis RiskTRAK/DrillMap/Drill Viz
1.9.3. Modeling Hydraulics Hydraulic design plays a very important rule in the prevention of Stuck Pipe. The available model usually involves a comprehensive set of algorithms that assist in analyzing planned or actual well trajectory.
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It gives an overview of the various component pressure losses and equivalent circulating densities (ECDs) calculations. The design calculates pressure losses over a range of available pump flow rates, and output includes Hole cleaning analysis. Critical pump rate needed to completely remove cuttings are also calculated. An example of Hydraulics design output is shown below.
VIRTUAL HYDRAULICS®
SnapShot ©1996-98 M-I L.L.C. - All Rights Reserved
Casing Program Depth 307'
Csg/H Dia
Angle
Depth (ft)
0
30
60
Density (lb/gal) 90
10.5
11.0
MD: 9300 ft TVD: 6355 ft Bit Size: 8.5 in. Date: 23.01.2002
Drilling 8.5" to TD ROP 220 ft/hr Flow 668 gal/min
11.5
12.0
PV, YP, LSYP 12.5
0
25
50
Temp (°F) 75
0
200
AV (ft/min) 400
0
250 500 750
Operator: Well Name: Location: Country:
CTOC Cakerawala Offshore Kelantan Malaysia
Hole Clean Ind 0VG0.25G0.50 F0.75 P 1.00
Pressure Loss (%) 0
25
50
75
100
309
8.835"
Drill String 1000
Bit Annulus
2000
DRILLING FLUID NOVADRIL
PV 3000
3831' 3135.3'
9-5/8"
ECD
Ann
11 lb/gal 120 °F
SYSTEM DATA 4000
347
8.835" ID 5000
YP ESD
DS
Flow Rate Riser Pump ROP RPM WOB Nozzles Nozzles
668 gal/min 0 gal/min 220 ft/hr 150 rpm 10 K lb 12-12-12-12-14 14-32
PRESSURE LOSS (psi)
6000
7000
LSYP 8000
9000 9300' 6355'
Mud Weight Test Temp
8.5"
10000
Modified Power Law (@R6/R3) 2496 Drill String 310 MWD 191 Bit 100 Bit On/Off 465 Annulus Surface Equip 78 51 U-Tube Press 3690 Total System ESD ECD +Cut Csg Shoe 10.78 11.64 11.80 TD 10.78 12.19 12.35 VRDH - Version 2.5 File - CAK_3_1!.MDB
Figure 43: Example of M-I Virtual Hydraulics output
The Drilling Office Hydraulics application provides the tools to estimate pressure losses throughout the entire circulatory system, optimize motor performance and bit nozzles, and give an indication of hole cleaning capabilities. It also computes swab and surge pressures and takes into account the effect of pressure and temperature on mud density and rheology. The model outputs in both tabular and graphical form the Critical Transport Rate (CTR): the pump flow rate necessary to completely suspend cuttings in the annular flow. Also displayed are the measured depth and inclination of the most critical section. The model also allows the sensitivity of the CTR to the ROP to be explored.
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Figure 44: Example of Drilling Office Hydraulics Input
1.9.4. Modeling Swab and Surge Swab and Surge effects during drilling can impact the stability of the wellbore, which could result in stuck pipe incidents. It is therefore important that the drillstring tripping speed is modeled during the planning phase. Swab and Surge modeling exist in the Drilling Office software. Here modeling can be done for Closed-Ended Pipe and, if Open-Ended Pipe, with Pumps On or Pumps Off. Note that with Open-Ended Pipe and Pumps Off selected, the Acceleration/Deceleration field is disabled. This field corresponds to the time necessary to get to the tripping speed from rest and vice versa in a linear approximation (e.g., if it takes 5 sec to reach a tripping speed of 3 feet/sec, then the acceleration is 0.6 feet/sec^2). The same value is used to calculate additional Swab / Surge pressures resulting from acceleration to the tripping speed when RIH or from deceleration from the tripping speed when POOH.
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Figure 45: Snapshot of Swab and Surge panel in Drilling Office
The Stand Length is the length of pipe tripped in between connections, whether 90 feet when tripping a stand of drill pipe or 30 feet when tripping a single joint at a time or 40 feet when running casing. The Connection Time is used to calculate the Total Tripping Time, whether for a User-Defined Tripping Schedule or an optimized Margin-Based Tripping Schedule, and corresponds to the time necessary to make up every connection. The Swab/Surge module Office yields its own reports and plots. These reports and plots consists of Swab/Surge pressures calculated for each tripping section and the corresponding Equivalent Mud Weights versus Bit Depth at the bit, at the casing shoe and, if applicable, at a Formation Marker and Sensor Location. Figure 46 is an example of Actual Swab versus Drilling Office Model. The plot below shows a combination of actual swab measurement with Drilling office model. It indicates that when the wellbore is in good condition (free from cuttings) the Drilling Office Swab and Surge Model can be used to accurately predict the swab pressures recorded during tripping out of the hole.
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Figure 46: An example of Actual Swab versus Drilling Office Model. The red line is the real-time data from the APWD and the dashed line is the modeled.
1.9.5. Drill Viz: - 3D Visualization. DrillViz, a Drilling office software component, is a three-dimension visualization and earth model-building tool. This tool is used to assist in planning, visualizing, and simulating drilling projects. DrillViz can show surfaces, volumes, well trajectories, drilling targets, and well markers in 3D view as well as ellipse of uncertainty, log curves and 3D image data along the well trajectory. It enables you to integrate and visualize your drilling data; it is a PC based application for the drilling engineer. With Drill Viz you: − Important surface/faults to view, move or reshape − View, edit and interact with drilling targets and drilling risks − Gain a greater insight into the spatial relationship of the downhole condition − View drilling problems captured in RiskTRAK. The snapshot below shows example of 3D visualization of wells on a particular field with depths of encountered drilling problems marked along the trajectory
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Figure 47: An example of 3D visualization of wells on a particular field with depths of encountered drilling problems marked along the trajectory.
1.9.6. Rocksolid – Wellbore Instability Analysis RockSolid provides various models/correlations for user to compute the mechanical properties from the basic inputs (dipole sonic and density logs and Elan interpretation). The module implements the Schlumberger Geomechanics methodology on a single well basis and allows specifically DCS engineers to compute and visualize stability of the wellbore at the planning stage The wellbore stability output is displayed as a function of well deviation and azimuth; mud weight window along the planned trajectory and mud weight. The software allows the user: To construct one-dimensional Mechanical Earth Model (1D-MEM) for an existing well To calibrate the 1D-MEM based on core and field data of the existing well To analyze the sensitivity of borehole stability vs. orientation and/or mechanical properties at a given depth for well planning and 1D-MEM study To analyze planned well stability using a 1D-MEM propagated from an offset well To predict in real-time the drilling well stability for wellbore stability monitoring and control
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A wellbore stability sensitivity module also provides a powerful function for users to diagnose wellbore stability problems; identify the risks; optimize borehole trajectory and visualize borehole failures. A good understanding of the output will be most useful in minimizing drilling surprises such as Stuck Pipe. Outputs should be reviewed with the WSS prior to any job. This should be included in Well Program to prompt WSS when to take necessary preventive actions An example of RockSolid output is shown below.
Figure 48: An example of RockSolid output.
This example shows the mechanical properties, mud weight window, zones and types of breakouts and possible borehole size due to the anticipated breakouts.
1.9.7. Stuck Pipe Analysis and Interactive Diagnostic tool – SPAID SPAID is an application package designed to help determining the likely cause of a Stuck Pipe. It takes the user through a sequence of questions, each one dependant on the last one answered and shows an estimate of the likelihood of the different possible causes of Stuck Pipe. Once the cause is determined, the software generates a report and provides a directed access to appropriate practices and procedures This knowledge in turn helps to make a better-informed decision about the nature of the Stuck Pipe problem and the appropriate actions to be taken
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The SPAID display has three main panels. On the left questions are displayed and responses can be entered. On the right, a set of indicators shows the current estimates of the likelihoods of different possible causes.
Figure 49: An example of a dialogue and estimate of possible causes is shown below
1.9.8. Sticking Risk Assessor for wireline jobs? The Risk Assessor is a simulation program to predict in advance the possibility of differential sticking of tool, differential sticking of cable and cable key seating. It was developed by SCR and accomplished by calibrating an experimentally verified theory to the Gulf of Mexico database of 10 years of MDT and RFT job. It can compute the sensitivity to drilling parameters overbalance, WBM, and mud solids Objective of the Sticking Risk Assessor Without Risk Assessment On Wireline, you don’t know your risk of getting stuck and lost time On TLC, you don’t know if you might have saved TIME and MONEY by running on Wireline With Risk Assessment Make better decisions (Wireline when risk of getting stuck is Low. TLC when Risk is High Reduce adverse consequences (Getting stuck on wireline and Running TLC needlessly Inputs to the Sticking Risk Assessor include: Tool/Cable: Length, Weight, Stationary Time, run number.
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Borehole: Openhole Interval, Diameter, Temperature, Deviation, Maximum Dogleg Mud: Type, Density, Fluid Losses, Lubricants, Low Gravity Solids, and “Stickance Factor” Formation: Differential Pressure, Compressive Strength etc. Input and Output should be reviewed with the WSS prior to any job. This should be included in Well Program to prompt WSS. An example of a Sticking Risk Advisor menu is shown below:
Figure 50: An example of a Sticking Risk Advisor menu
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2. REAL TIME ANALYSIS – HOW TO MONITOR THE PLAN?
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2.1. Introduction In this section we will focus on drilling trend analysis during the execution phase and we will show how this plays an important role in minimizing stuck pipe incidents. The analysis performed also provides vital data for future well planning, and should be a continuous process. Figure 51 below shows a graphical representation of the process:
SURFACE MEASUREMENTS
Stuck Pipe Identification Rig team DRILLING PROBLEMS.
Output
Office Team
Poor Hole Cleaning. Hole Pack-off. Cavings Mud Losses Poor weight transfer. High torque. High OP/Drag. Overpressure. Enlarged Wellbore Shocks/ Vibrations Drillstring/Failure Excessive/Backreaming
PERSONNEL
Risk Analysis Real time Interpretation
WSS WSDE Dir Driller Toolpusher Driller Mud Engr Mud Logger Perform Engr.
WOB Torque Pump Pressure RPM ROP Cuttings/Cavings Mud Properties
SURFACE SYSTEMS
Data Gathering
Drillers Console MWD logging unit Mud logging unit Mud Engineer unit
PLANNING PHASE Modeling of trends Risk assessments
DOWNHOLE MEASUREMENTS WOB Torque APWD Real time logs.
Figure 51: Shows a schematic of the real time analysis process.
The level of analysis performed will depend on the stuck pipe risks identified and the overall economics. However, there is one common thing, all analysis starts with looking at the basic drilling trends form the surface parameters.
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2.2. Surface measurements - Rig Floor measurements 2.2.1. Drilling Parameters Critical decisions in the drilling of a well are made on the basis of what the wellsite determines is happening downhole. Usually this judgment is based upon the interpretation of the surface information that is available. With the advent of real time monitoring systems such as PASON, this is no longer the sole responsibility of the driller. Theses days the WSS & other rig staff should play a major role in analyzing the drilling trends. The main sources of information and the changes, which they are most likely to represent, are shown in the table below. Wellsite Information and the possible causes of trend change. Sources of Information Differential Pressure
Circulating Pressure
Surface Torque
Trend Changes A reduced differential pressure indicates one or more of the following: − Reduced flow rate − Washout in the pipe − Extreme erosion of the bit (rare) − Reduced weight on bit An increase in differential pressure indicates one or more of the following: − Increased flow rate − Cutters have worn to the point that the bit face is in contact with the hole bottom − Excessive weight-on-bit − Large depth of cut - formation softer than expected − Hole Cleaning Increased Circulating Pressure could be due to one or more of the following: − Heavier mud weight or poor mud properties − Plugged or partially plugged bit − Increased flow rate − Annular restriction − Internal restriction − Inadequate hole cleaning Decrease in Circulating pressure would result from one or more of the following: − Lighter mud weight or better mud properties − Washout − Reduced flow rate − Air in the mud − Pump malfunction − Kick and Influx into wellbore − Varying – hole cleaning Increasing Torque can be caused by one or more of the following: − Hole angle changing − Washout − Formation change − Poor mud properties − Increased weight-on-bit − Inadequate hole cleaning
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Decreasing Torque caused by one or more of: − Formation change − Rotary speed change − Decreased weight-on-bit − Better mud properties − Bit wearing out − Addition of lubricants − Hole angle straightening out Varying or irregular Torque caused by one or more of: − Reaming with stabilizer − Dry drilling − Bit balled up − Sand formation − Junk in hole − Washout − Excessive Weight-on-bit − Rotary speed − Drilling Break (changing formation, sand/shale sequence, stingers While the pump stroke rheostat remains at same setting,
Pump Stroke
Penetration Rate
An increase in strokes indicates the same things as a decrease in circulating or differential pressure While the pump stroke rheostat remains at same setting, A decrease in strokes indicates the same things as an increase in circulating or differential pressure An increase in penetration rate may indicate: − Formation change − Drilling close to balance, i.e. mud weight does not substantially exceed borehole pressure. A decrease in penetration rate may result from one or more of the following: − Worn bit − Weight, rotary speed or hydraulics no longer optimized − Formation change − Crooked hole − Washout − Mud weight too high relative to formation borehole pressure − Poor mud properties thus effecting cuttings removal at the bit face and hole cleaning Varying penetration rate indicates one or more of the following: − Formation layers − Bit wearing out − Bit balled up − Wash out − Inconsistent application of Weight-on-bit
Table 16: Table showing possible reasons for changes in surface drilling parameters.
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2.2.1.1. Surface Trend Example: As the table shows there can be many different reasons for a change in a drilling parameter. This example shows that in many cases a change in trend can be an early warning sign for the onset of a future problem, in this case stuck pipe. If these early warning signs are picked-up, then remedial actions can be put in place to mitigate the risk. The first warning sign of the onset of Stuck Pipe occurred between 474m and 483m where the surface torque showed a continuous increase (for about 8mins) to a max of 1800 amps. Standpipe pressure also increased by 120psi (to 2280psi) with ROP of 52m/hr (172ft/hr) at 550gpm. Over pull off slips at connections showed 6klbs after the first connection at 454m, and 8klbs at 474m.
Over pull off slips at connections showed 5klbs after the first connection at 454m, and 8klbs at 474m
Increase in surface torque could be an indication of poor hole cleaning
Figure 52: Drilling chart
These warning signs were ignored and the next chart shows the result. As drilling continued, a stuck pipe incident occurred at 531m. Prior to this, there was an instantaneous torque spike up to 1800amps at around 515m, this later dropped to an av. torque value of 1400amps (normal trend 1200 amps) and maintained for 10 mins (between 515 and 523m) before dropping to 1100amps. The last warning before the stuck pipe incident was the overpull value, which had increased to 20Klbs.
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Torque spike followed by a reduction.
Stuck after connect. Hole packed-off
No circulation. Pump off, but still pressure holding on standpipe. Hole packed-off.
Figure 53: Drilling chart
What the example also shows is that it is not easy to identify changes in the drilling trend from the time plot. In order to make it easy for ourselves we need to plot the actual data against the expected or model trend. The main application for this is torque and drag analysis to monitor the hole cleaning efficiency and this leads us nicely onto the next section.
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2.2.2. Torque & Drag Analysis Torque and drag analysis is a very powerful tool to help identify the onset of hole cleaning problems in the wellbore, especially in deviated wells. To highlight this fact, K & M technology group promote torque and drag analysis as their major tool to predict poor hole cleaning. The steps in the process are 1. Model the theoretical torque and drags for the section using Drilling Office or other suitable software. Depending on the area the torques and drags can be calculated using single friction factors or a range of friction factors. 2. Produce torque & drag plots for drilling and tripping, and send them to the wellsite. 3. Take real time torque and drag readings at the wellsite and plot against the modeled data. 4. Monitor deviations from the modeled trends. 5. Implement remedial actions if poor hole cleaning is diagnosed. There are some extremely good examples of this type of analysis in Intouch, and a good example is summarized below: Intouch Content ID 3265546: Detection of hole cleaning problems using plot of Driller's P/U, S/O and rotating weights Reason for Best Practice: We have seen problems POOH on high angle wells due to "dirty" hole conditions in which APWD did not indicate a hole cleaning issue. We believe that very large caving's caused by wellbore instability was the problem but needed another method for detection. Best Practice Details: PowerPlan's DrillSafe application is used to calculate theoretical rotating off-bottom; Pickup and slack-off hook loads in each hole section. This data is imported in a MS Excel Spreadsheet (see attached) and while drilling the Driller's actual hook loads are entered and plotted versus the theoretical data. The attached example demonstrates that increases of 10% to pickup weights while drilling can indicate "significant" hole cleaning issues. In this example, the APWD data did not indicate a hole cleaning issue, the mud was in good shape and this was the third well that we had drilled with all drilling / engineering services. The shifts and trend changes seen on the P/U weights were identified as hole cleaning issues (wellbore stability related) and recommends for mechanical cleaning of the hole were made as various mud sweep programs appeared to have little effect in the high angle 12 1/4" hole. It should also be noted that Gamma Ray was added to the chart while drilling to check for formation changes. Other Intouch Submission on Torque and Drag Analysis: Content ID: 3951195: High Torques due to Hole Cleaning in Russia Novo 83 6545 Content ID: 4061655: Torque and Drag Analysis plot Content ID: 3881395: Brazil Petrobras EOWR Standard
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SLP (Self Learning Package) Torque & Drag: Explains the theory of torque & drag. http://intouchsupport.com/intouch/MethodInvokerpage.cfm?caseid=3978035 The next two figures show examples of torque and drag monitoring and are taken from the Intouch submissions above:
Actual deviates away from theoretical trend indicating hole cleaning problems.
Figure 54: Drag chart from Intouch Content ID: 3265546. The deviation of the pick-up weight away from the theoretical was interpreted as poor hole cleaning
Bit Depth, meters BRT
800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 3100 3200 3300 3400 3500 3600 3700
200
Pick Up Weight, ton
180
160
140
120
100
80
60
Actual T&D on KE 5-01, 16" section
Rot Weight, ton Slack-off Weight, ton DO Pick Up DO Rot. weight DO Slack off
#4 MRS89 + vorteX to 2357m
#5 HCM606Z to 2414m #6 MAX22 to 2440m #7 MRS89 to 2695m
#7RR MRS89 to 2952m
#8 MKS76SRO to 2977m
#9 to 3008m
#10 MRS89 to 3156 m #10RR MRS89 to 3302 m #11 MGR84BVP to 3436 m #11RR MGR84BVP to 3567 m
Weight indicator readout, ton
Figure 55: Intouch Content ID: 4061655 drag chart. What is interesting is that the theoretical and actual up & down weights do not match. However, the trends are similar. This is probably the result
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of using the wrong friction factor and highlights the need in some cases to produce a range of plots for different friction factors e.g. a broom plot. 3500 4 4
3600
5 5
3700 3800
6 6 6
7
3900 4000
8
4200
Measured Depth (m)
4300 6
4500
#12RR MGR84BVP from 3575 to 4266 meters ( 50 TVR )
10
#15 MGR89TVPX from 4266 meters ( 204 WWT & 30 TVR )
12
10
5
4600
10
10 10 10 10 10 10 WOB ( TONS ) 10 10 8 8 9 10
4100
4400
9 9 9 9 9
15
6
4700 4800
Legend: Silty Claystone
4900
Poorly cemented Sandstone
5000
Interbeds of silty Claystone and SDSTa/a
5100
Argillaceous Limestone
TOP DRIVE TORQUE LIMIT
Calcareous Claystone
5200
Off bottom-Driller's data DO - off bottom DO- TQ while drilling On bottom - Driller's Data Series8 Weight on bit k ftlbs Series9
Siltstone
5300 5400 5500 0
5
10
15
20
25
30
35
Torque Klbs.ft
Figure 56: shows a torque graph from Intouch Content ID 4061655.
A Drag chart is as useful for running Casing as it is for tripping a drill string (see figure 57). Close monitoring of the down weight and by occasional pull tests, the up weight will result in an early identification of additional resistance and a timely decision to start washing down.
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Deviation from the trend could indicate a hole cleaning problem
Figure 57: This example shows hook load chart for running a 9 5/8” casing string. Here, the actual hook load trend is plotted against multiple theoretical hook loads trends, which correspond to various friction factors as shown by the coloured lines. Ideally, this type of multi-friction factor plot should be used when monitoring torque and drags in the drilling phase
Taking Pick Up, Slack off and Rotating weights. T&D readings should be recorded at regular intervals and to be more effective in indicating trends, it should be carried during the following operations (see figure 59): − At every connection while drilling ahead − Before, during and after wiper trips, − After circulating bottoms up and after pumping sweeps, − With bit inside casing/liner, prior to drilling out/going back into open hole − As soon as practicable after a mud weight increase; mud type change, major rheology changes. − At TD after hole has been cleaned, − Before and after additions of torque reducers, such as lubricants and nonrotating drillpipe protectors (NRDPP), etc, − Monitor while tripping out/in, especially in open hole, In order to have accurate T&D plots there is need to get good quality T&D readings while drilling: The following are steps that would enhance the quality of T&D readings.
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1. After drilling down each connection, work the stand once to ensure good hole cleaning and any cuttings are clear of the BHA and to determine if the hole is “free” (situation may be different for different rigs/company procedures). 2. At the bottom of the first full stroke, a few meters off bottom, get rotating weight and torque at drilling RPM and flow rate. 3. Stop rotary and get pick up (P/U) weight on up stroke, 5-6 meters, at point of zero Drag, 4. Get the Slack off (S/O) weight on the down stroke at point of zero Drag, while returning the 5-6 meters to bottom (length of stroke to get proper P/U and S/O weights will vary depending on hole size, BHA, angle, etc). 5. If necessary get pumps off P/U and S/O weights, stop the pumps and repeat Steps 2 and 3 above, before the connection. 6. Working the drill string at the same speed every time will make the readings more consistent. 7. Do not take the average readings at connections – take the least affected, steady weight indicator reading in all circumstances – lowest on P/U and highest on S/O. 8. Also, take the circulating readings at the same flow rate (for each hole section) to avoid the potential influence/interference of hydraulic lift. 9. Actually, pumps off readings at connections are preferred as they give a truer representation of the FF and the expected readings while tripping. 10. While tripping out, just get the pick-up weights while pulling, and for tripping in, get the slack-off weights while running. Document depths and amounts of any S/O changes and over pulls – monitor for tight spots, formation changes, etc. 11. For running casing/liner, get the Slack-off weights while running, and to get the P/U weights, ensure the driller picks up sufficient length to get a good reading.
Figure 58: Example Torque and Drag Collection Sheet.
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2.3. Downhole Measurements Indicators and Signals Technological advances over the last decade have allowed us to record the actual downhole drilling parameters. The main measurements used to monitor the downhole hole condition are downhole weight on bit, and annular pressure while drilling.
2.3.1. Downhole Weight on Bit. Downhole Weight on bit provides a real time measurements of down hole weight (DWOB) and Downhole Torque (DTOR) and it can provide valuable information about what is really happening at the bit. It has been found that it is a good tool for monitoring hole cleaning. When hole cleaning is deteriorating, the downhole data deviates away from the surface values e.g. the Martin Decker shows the WOB is 15T, but the downhole data indicates that the downhole WOB is only 5T.
2.3.2. Annular Pressure while drilling (APWD). Annular Pressure While Drilling (APWD) provides real time measurements of equivalent circulating density (ECD), equivalent static density (ESD) and Annular temperature which, complemented with surface parameters, allows the wellsite to improve drilling practices for hole cleaning, borehole stability and well control In wells that have that have potential borehole instability or small margins between the fracture gradient and pore pressure, it is important to monitor the ECD and maintain it at tight limits both while drilling and while tripping. It is fair to say that operators have had mixed results using APWD to monitor hole cleaning efficiency. The main problem is the tool picks up changes in ECD caused by the amount of cuttings suspended in the mud. However, in deviated wells the cuttings are lying on the low side of the hole and not in the mud stream, and as such will not be detected by the tool until the equilibrium state changes see section 1.4.6. In many cases this is the point of no return and your BHA has packed-off - it basically acts as the final warning sign. If an APWD is run then the following should be done: 1. 2. 3. 4.
The ECD should be plotted against the theoretical. It should be used in conjunction with surface trend analysis e.g. torque & drag. The wellsite should be aware of it’s limitations and should not rely on it 100%. An experienced operator is on site to analysis the data.
2.3.2.1. Example 1: Using APWD The figure 60 overleaf shows part of the drilling mechanics log for the 9-MLS-102-RJS well. It shows the ECD running with a background of +/- 10.25 ppg for the given drilling parameters. At 2843.4 m the connection was made and the stand was back reamed. It
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appears that the speed at which they came back down with was too fast and the well was surged to a maximum pressure of +/- 11.5 ppg. This event appeared to have triggered a stability problem since the ECD no longer remained at it background of +/- 10.25 ppg but fluctuated between this background and 10.75 ppg. This was possibly due to caving’s falling in the hole after being destabilized buy the surge event, which took place earlier. Figure 61 shows that the destabilization of the formation continued until +/- 2858.8 m before the ECD stabilized again at +/- 10.4ppg after the pipe was reamed and the hole was circulated a bit. Drilling continued to TD at +/- 2868.2 m and the ECD continued to increase to 10.5 ppg before the hole became packed off when the pumps were turned off. The maximum ECD at this time was > 11.5 ppg which may have exceeded the tensile strength of the weakest point in the open hole, creating a fracture and lost circulation. From the log it can clearly be seen that two major avalanche event took place: one before the formation was fractured, and the other after with a maximum ECD of 11.25 ppg.
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9-MLS-102-RJS
9-MLS-102-RJS
Backreaming at connection and moving down too fast, creating a huge surge pressure of +/11.5 ppg. This was the start of the WBS issue. Well bore stability issue materialized on the ECD. Should be able to see on the shakers as well.
Wellbore stability problem continued until +/- 2858.8 m.
ECD now maintained a background of +/10.4 ppg and increased to +/10.5 ppg just before the section TD. Pumps turned off and 2 major avalanching event occurred. The first event fractured the formation and created a lost circulation event.
Figure 59: Shows the APWD response of the example.
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Schlumberger Private
Drilling ahead normally with a background ECD of +/- 10.25 ppg.
2.3.2.2. Example 2: The APWD (red & blue lines in the right hand column) does not give an early warning sign before pack occurs. It interesting to note that once packed-off the tool does not show the sudden increase in standpipe pressure (black line, right hand column). This suggests that the pack-off was below the APWD sensor.
Little drag at connection: Hole OK Pump pressure increases But little change in Annular Pressure (compatible scale)
Figure 60: This example shows little change in the APWD prior to pack-off.
In vertical wells the ECD change does directly relate to the hole cleaning efficiency and it has been used with great success to prevent the formation of clay rings in vertical wells see Intouch content ID’s 2021251 & 3945116.
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2.4. Real Time Software Packages 2.4.1. PERFORM PERFORM Toolkit is the combination of three real-time enabled applications: Drilling History, Real-Time Hydraulics and Torque & Drag (HTD) Drilling History (DH) is an application for viewing and analyzing time and depth based data both in real-time or through importing historical data. The HTD was developed for use at the well site to compute Hydraulics and Torque & Drag in real-time 2.4.1.1. Drilling History – Monitor, Analysis & Playback Drilling History is both monitoring and analysis tool supporting drilling relevant real time decisions. The BHA position on a lithology and/or Image at any given time is displayed side by side along with the traditional time log display. The components include a playback (DVD alike) controls in addition to time and date, Numeric display, Rig status, Statistics and Cross-plots. Data flow to this module is either seamless through InterACT or via a static file upload. All rig drilling activity and selected measurements are recorded and saved as media linked to the software module.
Figure 61: Drilling history analysis screen.
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The user can playback any missed activity over the past few minutes or days in relevant real time. The numeric controls allows the user to change the depth scale, the time scrolling speed and/or any relevant surface / down hole measurements among some other functionalities. This module can be extremely useful in a stuck pipe situation, drilling problems or even loss of circulation. Reviewing these events in a quick and easy to use interface has a direct impact on real time decisions. Displaying the last twelve hours activity in twelve minutes or picking up a single stand of drilling and analyzing it in details is like telling a story. This module provides the user with a tool to set their own preferences for the story they are interested in. 2.4.1.2. Real Time Hydraulics and Torque & Drag Analysis This module is a semi-automated real time application. It requires initial setup by an operator and minimum maintenance that doesn’t interfere with the data stream. Data streams from the surface and downhole sensors through the acquisition system and computed channels can be streamed out to InterACT. For the end user on the clients’ side, this is an informative answer product. The only interaction expected from the client end user is monitoring and/or replaying jobs. The main screen (user interface) on the application operator machine consists of real-time channels, parameters and computed channels. The operator has the ability to format the display independently of the way the end user setup. The module is based on automated interpretation algorithms fed with the right drilling measurements data in real time and the necessary parameters. The answer accuracy highly depends on the availability and quality of the input measurement sensors. Bit, Motor, Rotary steerable systems efficiency and performance indicators are the main outputs of this application. When downhole WOB and torque measurements are available, the Sticking Pipe Indicator (SPIN) answer products; Rotating friction and Drag coefficient will be computed by module and results similar to IDEAL SPIN+ can be plotted with early analysis of the onset of Stuck Pipe incident. In addition, ECD analysis and holecleaning indicators can also be plotted once the measurements are available.
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Figure 62: Real time torque and drag screen.
2.4.1.3. Rig State detection The drilling process can be impeded by a wide variety of problems. Accurate measurements of downhole conditions, rock properties and surface equipment allow many drilling risks to be minimized, but they are also crucial for detecting that a problem has occurred. At present, most problem detection is the result of human vigilance, but detection probability is often degraded by fatigue, high workload or lack of experience. Rig state detection is a component of PERFORM Toolkit which provides a way of computing the activity a rig is performing at any time, based on data from the surface sensors: Torque, Pump pressure, Hook load and Depth. An integer channel in the time data is created to store the computed Rig state events. The calculation can be performed either in offline mode (on previously loaded data) or in real time as new data is received. Figure 63 below illustrates the Rig detection.
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Pooh Pump Rih Pump
InSlips
Figure 63: illustrates the Rig detection.
Automatic interpretation of the Rig state should assist the following tasks: Event detection: A change in the Rig state will cause changes in some of the surface and downhole measurements. Without knowledge of these change points, a problem detection algorithm is forced to make the erroneous assumption that the input data has been at steady state for some time. Drilling problems that may be detected: − Stuck pipe − Lost circulation − Poor hole cleaning − Washout detection − Accidental sidetracking − POOH/RIH too fast - swab/surge − Over-/under-torque pipes Improved manual interpretation: Plotting the most probable rig state alongside other data channels should help focus the attention of an engineer looking at the logs. Data interrogation: Historical data could be extracted according to rig state, e.g. all data while drilling in sliding mode. Non-productive time: Automatic calculation of NPT. Correlation between NPT and earlier problems may be derived, e.g. time setting tool face angle correlated to earlier poor hole cleaning problems.
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2.4.2. Stuck pipe Indicator – SPIN Most Stuck Pipe incident occurs during tripping or connections when the pipe is stationary. However, there are often indications of an approaching problem in abnormal values of hook load or rotary torque prior to the Stuck Pipe incident. Abnormal values of hook load and torque can be difficult to diagnose just from comparison with offset wells. This is because hook load and torque are dependent upon the borehole trajectory and BHA configuration. However real time information systems can track hook load and torque throughout all drilling operations and use mathematical models to remove the effects of borehole trajectory and BHA configuration. Schlumberger IDEAL Wellsite information system includes a Sticking Pipe Indicator (SPIN+) model which combines surface and downhole weight and torque measurements with the BHA design and wellbore surveys to calculate expected Torque and Drag values These computations can be made continuously while on-bottom or off-bottom. The difference between the weight slacked off at surface and the downhole weight-on-bit can be used to compute the average axial friction factor, µaxial (DRAG) 2.4.2.1. What SPIN+ can do? − Detects conditions that could result in Stuck Pipe − Evaluates BHA performance − Optimizes ROP − Evaluate Hole Cleaning practices 2.4.2.2. What SPIN+ computes − Rotating Friction Factor - FRIC − Sliding Drag Coefficient – DRAG on a foot by foot basis − Computation starts 500-ft below rotary − Minimum wellbore inclination of 20-degrees − Automatic computation of hook load − Automatic friction vs. depth profiles for: − Over pull – Sliding and Reaming − Slack-off – Sliding and Reaming − Torque loss – Rotating 2.4.2.3. What SPIN+ requires to work − Surface Weight on Bit (Using a Clamp line Tension meter) − Surface Torque − Downhole Weight on Bit (DWOB) − Downhole Torque (DTOR) − Surveys all the way to surface (Inc & Az) − Drillstring description
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−
Mud Weight for Buoyancy Factor
2.4.2.4. Interpretation of SPIN+ model Results from the SPIN+ model are normalized data expressed in terms of friction factors. These friction factors are dimensionless in character and in principle are independent of hole size and depth. They are mainly a function of the friction between the rock and the drillstring so they are dependent upon mud type. Experience shows that During normal tripping without rotation, or sliding operations with mud motors µaxial friction (DRAG) = 0.1 to 0.3 During normal reaming or rotary drilling operation: µaxial (DRAG) = 0.0 to 0.05 µrotary (FRIC) = 0.1 to 0.3 During rotation in a clean borehole µaxial is close to zero because the rotation dissipates most of the axial friction unless the drillstring components become hung up on ledges. Drillers Action: Under normal drilling operations the friction factors do not change (or only change very slowly) with depth, BHA or trajectory. Abnormal values in Hook load or torque clearly appear as increases in µaxial (DRAG) or µrotary (FRIC) respectively. As soon as this increase are detected, the driller can be alerted to take appropriate remedial action such as a wiper trip, mud circulation or avoid leaving the pipe stationary. Also the driller can measure the benefit of remedial action by comparing the reduction in the friction factor after the operation with the value before it. In this way it is possible to determine which actions are beneficial and avoid performing unnecessary procedures if they do not bring about a significant reduction in friction. 2.4.2.5. Examples of Using the SPIN The example shown below is from a well in the Gulf of Mexico. The data come from a tangent section of a directional well in fairly homogenous shale. The rotary friction factor, Urotary (FRIC) was 0.2 and appeared to be normal. However, the surface weight on bit of 20klbs only resulted in 10klbs of downhole weight on bit. This corresponds to an axial friction factor, Uaxial (DRAG) of between 0.05 – 0.09, with increased with depth between X800 and X020. Thee result was a drop in penetration rate (ROP) from 50ft/hr to 40ft/hr. Without the downhole weight-on-bit measurement (DWOB), the decline in ROP would probably have been attributed to a harder shale formation or a worn bit. The axial friction (DRAG) was probably increasing either as a result of swelling shale, or cuttings build up. The diagnosis of increasing axial friction led the drilling 111
crew to perform an 11 stand short trip. After the short trip, the ROP increased to its original 50ft/hr achieved with a SWOB of only 10klbs, which was half the previous value. The DRAG was reduced significantly to a value less than 0.05, resulting in less chance of Stuck Pipe. Using SPIN to quantify the effects of hole conditioning technique
Figure 64: Output screen from SPIN.
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3. BEST PRACTICES
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3.1. Communication. 3.1.1. Introduction:
The importance of effective communication in preventing stuck pipe cannot be overemphasized. Preventing fishing, like any non-productive rig time, is a team responsibility. Everyone has a role too play. Effective communication ensures that these roles are understood and performed in a way that gets better results than with the most competent individuals working by themselves. The process begins well before drilling, continues through every step of the rigsite operations, and continues afterwards as lessons learned and experience gained are documented for use next time around The following are the kind of meeting that can be help.
3.1.2. Pre-Spud Meeting
The pre-spud meeting on the rig is a basic requirement and an essential communication tool before any well is drilled. The objective is to make sure that details of the well are understood by all concerned, and that required resources are available to carry out operations safely and professionally. This includes planning to prevent stuck pipe, but also to react promptly and effectively to Stuck pipe incidents if they occur. Participants should include key representatives of the operator, drilling contractor (including the Rig manager) and service companies. The drilling program should be received by the drilling team well in advance of the anticipated spud date. The main subject of the pre-spud meeting is usually a step-by-step review of the drilling program. This focuses on experience on offset wells, anticipated problem sections, and the steps to be taken to deal with them. Issues apparently unrelated to the drilling program must also be considered. Logistical support, major equipment maintenance, personnel issues and other factors can indirectly affect drilling performance and the ability to respond to a stuck pipe situation. Most importantly, the pre-spud meeting must not be allowed to become a routine, meaningless exercise. Properly conducted with prepared and active participants, it is one of our most powerful tools in foreseeing and preventing Stuck Pipe incidents. For pre-spud meetings as with meetings generally, the following checklist can be applied: − Are the objectives of the meeting clear? − Have the right participants been identified and invited? − Has everyone been given sufficient notice of the meeting and anything they should prepare?
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− − − − −
Is there a clear agenda? Is the meeting room set-up satisfactory? Is there enough time? Are the minutes of the meeting being recorded? Are follow-up actions identified and communicated to the relevant team members?
3.1.3. Pre-Section meeting Before drilling a well section or formation with a particular risk of Stuck Pipe, a brief additional meeting should be held. Here drilling parameters, anticipated problems and remedial actions will be discussed, and the role of each crewmember in applying these actions clearly re-stated. In many cases this presection/formation meeting can be integrated with the pre-tour meeting.
3.1.4. Pre-Job Meeting Before any non-routine drilling operation, a short meeting should be called on the rig floor to brief members on the operations and risks involved. Most important for a pre-job meeting is to highlight the safety aspects of the job but anticipated stuck pipe problems can be discussed as well.
3.1.5. Pre-Tour Meeting Before going on tour the drill crew will meet to be briefed by the Rig Superintendent or Asst Rig Superintendent on the ongoing operations, plans for the coming 12 hours, and any points to watch. The Driller coming onto tour must familiarize himself with standing instructions for drilling, written by the Rig Superintendent, and discussed at this meeting.
3.1.6. Handover on the Drill Floor Most Stuck pipe incidents occur within two hours of Driller’s shift change. Communication between the drillers and crews at handover is therefore crucial The incoming Driller must look at the IADC report, chart recorder and downhole measurements if available at the rig floor for information on drilling parameters and developing trends. But most importantly he must listen to the Driller going off tour. Any abnormalities observed e.g. over pulls, tight spots should be discussed, and the relief Driller should take time to observe and understand the drilling parameters before re-commencing his tour. The Driller must pass any relevant information to the rest of his crew, particularly the Assistant Driller and Derrick man, who will have their own handovers as well.
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3.2. Drilling in the box A “Drilling in the box” technique is suited for sticking mechanisms that involves hole cleaning. It is simply applying the systems approach used in the planning stages to the execution phase. It is a technique whereby drilling performance (i.e. ROP) is optimized to match the hole cleaning ability of the entire “drilling system”. Given the BHA that is in the hole, the directional requirements associated with this BHA, and the well path objectives, the ROP is effectively matched to the best drilling parameters that the rig can sustain. Real time monitoring and analysis of all available drilling data combined with close observation of cuttings return is used as a tool for ensuring that drilling is not progressing in a way that will result in drilling surprises for the system’s capability. When referring to the “system”, the following parameters are included. Note that these parameters are constantly changing, and therefore the system is changing, as well. No single aspect can be treated as independent, as any changes to one aspect will no doubt affect others. − − − − − − −
ROP Drilling Parameters (Flow rate, pipe RPM) Mud type and rheology Nature of cuttings (volume, size, shape and stickiness) will affect how they move up the wellbore) Hole size and angle of tangent section both of which may vary with time as the well progresses T&D BHA and drill bit design.
Figure 65: Visualisation of the “Drilling In the Box Concept”
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For successful implementation of this concept, it is important that all aspects of the “system” are considered. The schematic above helps to visualize this technique where each parameter and circumstance forms the walls of the box. “Drilling in the box” is a closed loop feedback approach, for mitigating stuck pipe hazards for a given situation.
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3.3. Hole Cleaning. 3.3.1. Introduction
Hole cleaning has been discussed in detail in Volume 1 and in the planning section of this manual. This section will concentrate on the implementation of the plan and what to do if we have to drill with sub-optimum drilling parameters.
3.3.2. Drilling When establishing hole-cleaning guidelines, it is important to review relationships among the parameters and to recognize that some can be both independent and dependent variables. Often, one parameter, such as formation type, will determine how to approach hole cleaning. For example, a typical horizontal well drilled through a very competent Austin Chalk formation might use a brine reservoir drill-in fluid. It follows that these parameters would be appropriate — turbulent flow, high annular velocity, low fluid viscosity and gels, with minimal effects from pipe eccentricity and rotation. On the other hand, an unconsolidated-sandstone, horizontal interval would dictate tight filtration control and laminar flow. Elevated low-shear rheology and flat gels would be suitable, especially if the eccentric pipe can be rotated. Listed below are practical hole-cleaning guidelines aimed at field use. They are grouped according to general (all wells), vertical/near-vertical wells and directional wells (including horizontal). 3.3.2.1. General 1. Use the highest possible annular velocity to maintain good hole cleaning, regardless of the flow regime. Annular velocity provides the upward impact force necessary for good cuttings transport, even in directional and horizontal wells. 2. Rely on mud rheology and gel strengths for suspension and transport capabilities. 3. Control drill to manage difficult hole cleaning situations only as a last resort. Penetration rate determines the annular cuttings load. The negative implications of limiting drill rate are self-evident. 4. Take advantage of top drives, if available on the rig, to rotate and circulate (back ream) when tripping out. 5. Continually monitor parameters affecting hole cleaning, and react accordingly. Always consider the consequences of changes on other operations. 6. Measure mud rheology under downhole conditions, especially in deepwater and High-Temperature, High-Pressure (HTHP) applications. 7. For deepwater wells with a large diameter riser, add a riser pump to increase riser annular velocity. 8. Avoid using highly dispersive mud’s that might help cleaning, but can create a mud solids problem.
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3.3.2.2. Vertical and near-vertical wells 1. Keep cuttings concentration less than 5% (by volume) in order to minimize drilling problems. 2. For efficiency and cost considerations, use a mud viscosity selected based on hole size and slip velocity calculations. Further increase yield point and LSYP only when hole-cleaning problems have been encountered or are imminent. 3. Maintain LSYP between 0.4 and 0.8 times the hole diameter in inches unless hole conditions dictate otherwise. Yield point and LSYP for highly dispersed muds typically are low, so higher annular velocities may be required. 4. Use periodic high viscosity & high-density/high viscosity sweeps to correct cleaning problems. Do not run sweeps unless hole conditions warrant. 5. Monitor the hole for symptoms of cuttings accumulation, fill and bridges. 6. Do not expect pipe rotation to help hole cleaning, especially in largerdiameter holes. 3.3.2.3. Directional wells 1. Hole-cleaning techniques to minimize cuttings-bed formation and subsequent slumping, which can occur in 30 to 60° hole sections. 2. Pump at optimum flow rates: Hole Size
Desirable Flow rate
Minimum Workable Flow rate
17 ½”
900 – 1200 gpm
800 gpm with ROP at 20m/hr
12 ¼”
800 – 1100 gpm
650 gpm with ROP at 10-15m/hr 800 gpm with ROP at 20-30m/hr
9 7/8”
700 – 900 gpm
500 gpm with ROP at 10-20m/hr
8 ½”
450 – 600 gpm
350-400 gpm with ROP at 10-20m/hr
Table 17: K & M recommend flow rates.
3. Utilize elevated-viscosity fluids from the start, because cuttings beds are easy to deposit, but difficult to remove. As the inclination increases the effectiveness of the viscosity decreases. 4. Maintain LSYP between 1.0 and 1.2 times the hole diameter in inches when in laminar flow. 5. Treat mud to obtain elevated, flat gels for suspension during static and low-flow-rates periods. 6. For optimum performance from FLO-PRO* fluids, maintain Brookfield viscosity above 40,000 cP. 7. Schedule periodic wiper trips and pipe rotation intervals for situations where sliding operations are extensive and bed formation is expected.
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8. Rotate pipe at recommended RPM’s for the given hole size to prevent bed formation and to help remove pre-existing beds. Fully eccentric pipe combined with proper LSYP values can provide best results. 9. Increase mud weight to correct wellbore stresses problems causing holecleaning problems. 10. Recognize that turbulent flow across the annulus may be difficult to achieve and maintain. 11. Consider drilling small-diameter, competent, horizontal intervals using turbulent flow. Low-viscosity fluids enter a state of turbulence at lower flow rates than viscous ones. Any beds which form can be eroded by the high flow rates required for turbulent flow. 12. Expect little help from viscous sweeps, unless they are accompanied by high flow rates and pipe rotation and/or reciprocation. 3.3.2.4. Drilling with optimum parameters. When drilling with optimum parameters we have to make sure that we do not drill ourselves outside of the box. This means drilling at the correct rate of penetration for our system, and monitoring the hole cleaning efficiency e.g. real time trend analysis. The following rules should be followed: 1. Drill with the correct parameters in the program: a. Flow rate b. Mud rheology c. RPM 2. Monitor the hole cleaning efficiency: a. Torque and drag b. Surface drilling trends e.g. circulating pressure c. Mud trends d. Cutting return over the shakers e. Downhole drilling parameters (if available). 3. Drilling at an ROP that keeps us within in the box. This is not an exact science and does not mean sticking at a constant ROP; some common sense has to be used. For example if a drilling break occurs and the ROP doubles, then ensure that the drilling system can cope. If not reduce the ROP and drill at a controlled rate. 4. If you stop drilling with the optimum parameters implement procedures to cope with the reduction in the hole cleaning efficiency. If this is not possible, stop drilling until optimum parameters can be returned e.g. if one pump is down.
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Operational Practice: Hole Cleaning. Situation: General good hole cleaning. Howto establish good hole cleaning: Use maximumRPMand flowrate as specified in the program. If you are not able to continue to proceed with recommended good hole cleaning parameters, be prepared to check the hole conditions before continue drilling. Drag trends are usually the best indicator of hole cleaning. Torque, cuttings return, pump pressure, and ECD are good secondary indicators of hole cleaning. In challenging sections (high inclination, long open hole sections etc.), the standard observation parameters might not be sufficient.
Control ROP up to maximumfor good hole cleaning. If the ROP is too high, neither high RPMnor high flowrate will be sufficient to bring the cuttings to surface at a steady high rate. The cuttings will accumulate in the annulus.
Use maximumRPM. High RPMis needed to keep the cuttings in suspension. When the cuttings are in suspension, the flowrate will catch themup and move the cuttings to surface.
Continous rotation helps keeping the cuttings in suspension. Continous rotation is best for good hole cleaning. If you use motor, reduce sliding to an absolute minimum.
Use maximumavailable flowrate. High flowrate is required in order to move the cuttings out of the well.
Figure 66: Schematic showing the operational practice for good hole cleaning.
3.3.2.5. Sub optimum parameters. In some IPM operations we are restricted by the well design and/or rig and we cannot drill with the optimum parameters e.g. flow rate &RPM. In these cases the following guidelines should be followed: 1. 2. 3. 4. 5.
Keep the mud in good shape and as per program. Monitor trends for excessive build up of cuttings. Reduce ROP. This may reduce the height of the cuttings bed. Minimise the amount of directional work e.g. steering. Opt for the conservative directional philosophy e.g. two runs instead of one. 6. Stop drilling and circulate the hole clean at maximum possible RPM and flow rate at different stages during the section. 121
7. Short wiper trips to clean the hole and disturb the cuttings bed. 8. Raise awareness with the rig team that sub optimum drilling parameters are being used and hole cleaning related problems could occur. Operational Practice: Hole Cleaning. Situation:Sub Optimum Parameters
What happens if you reduce the flowrate and/or RPM are below recommended parameters:
Do not reduce the flowrateor RPM below recommended setting!
1.) It is not sufficient flow or energy to remove the cuttings to surface. 2.) The cuttings will settle at the downside of the wellbore. 3.) Even if you have sufficient RPM or flowrate, the cuttings will settle. 4.) Be aware of the rathole or other types of washout. A lot of cuttings will accumulate in over gauged hole. Remember: It can be difficult to remove a cuttings bed that has been settling over a long period!
Figure 67: Schematic showing sub optimum hole cleaning.
3.3.3. Hole Cleaning pills Proper use of mud pills may improve hole cleaning in vertical and deviated wells. High viscosity (preferably weighted) pills are often effective in hole sizes larger than 8 ½” whilst low viscosity pills are beneficial in smaller holes. When using a low viscosity pill, it is important to maintain the normal high flow rate and minimise non-circulation time. Also it is often necessary for a low viscosity pill be followed by a high viscosity (weighted) pill in order to ensure adequate hole cleaning in the larger diameter vertical hole section. The specific pill volumes should be determined based on the hole size and the calculated effect on hydrostatic head. Typical volumes used are:
Table18: Sweep volumes for per hole size.
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Note: − The use of low viscosity, turbulent flow pills are not recommended in weakly consolidated formations as washout or hole collapse may occur. − Pumping pills can have a serious impact on the mud rheology and are sometimes counter productive. There are several types of hole cleaning pills that are in common use. The function of each of these pills is described below. 3.3.3.1. High Viscosity Pill Viscosifying additives are added to the base fluid of the mud and pumped around the well, the usual volume being 25 to 50 barrels. A highly viscous pill will be effective at sweeping cuttings out of a vertical hole. Studies observing circulation of viscous pills over cuttings beds at high angles have shown that the pill deforms over the bed without disturbing the bed. Therefore the use of a viscous pill to clean deviated wells is not recommended. 3.3.3.2. Low Viscosity Pill The base fluid with no additives is often used for this pill. The base fluid usually has a low viscosity and will therefore become turbulent at lower flow rates. A low viscosity pill will help to lift and remove a cuttings bed. Use of a low viscosity pill alone may not be successful. It will not be able to carry the cuttings up a vertical section of the hole or suspend the cuttings when the pumps are stopped. 3.3.3.3. Weighted Pill A weighted pill comprises base fluid with additional weighting material to create a pill weight 2 to 3 ppg heavier than the mud. This type of pill will aid hole cleaning by increasing the buoyancy of cuttings slightly. Heavier mud also tends to be more viscous. This type of pill is usually used as part of a tandem pill. 3.3.3.4. Tandem Pill (also called Combination pill) This consists of two pills, a low viscosity pill followed by a weighted pill. The concept is that the low viscosity pill stirs up the cuttings from the low side of the hole and the weighted pill sweeps them out of the hole. The weighted pill is sometimes substituted for a viscous pill. Tandem pills can be very effective at stirring up cuttings and should be used as a preventative measure for hole cleaning problems. If the hole is full of cuttings and a tandem pill is pumped, there is a chance the amount of cuttings stirred up can cause a pack-off. If holecleaning problems are being encountered, initially use high circulation rate, drill pipe rotation and reciprocation to clean the hole. After the hole has apparently been cleaned up, then use a tandem pill for further cleaning.
3.3.4. Circulating Prior to Tripping Circulating the hole prior to tripping is crucial in getting the hole clean enough to trip out. In most operations people and impatient and see circulating on bottom as lost time. They are too eager to POOH and stop circulating to soon. In most
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cases this is false economy as they then encounter stuck pipe problems during tripping that far out weigh the time saved on not circulating. 3.3.4.1. Rules of thumb: Table 19 gives rules of thumb for the minimum bottoms up circulations required for different hole sizes and angles. The figures assume that the circulation is taking place at the optimum parameters for hole cleaning. If this is not the case than the rules of thumb are not appropriate and additional methods will be required to get then hole clean for tripping. Hole Size 17 ½” to 12 ¼”
Inclination > 45 deg
Circulation At least 3-4 btm-up circulations at optimum parameters.
17 ½” to 12 ¼”
< 45 deg
8 ½” to 6”
> 45 deg
8 ½” to 6”
< 45 deg
At least 2 btm-up circulations at optimum parameters. At least 2 btm-up circulations at optimum parameters. At least 1.5 btm-up circulations at optimum parameters
Table 19: Table showing the rules of thumb for circulating on bottom at optimum parameters prior to POOH.
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Effective Circulation Volume vs. Angle 20,000' (6000m) tangent length, shallow KOP 7
This gives some feel for how much circulation is necessary for different angles
6
Min. Circulation Volume
5
• Note – only convey or belt circulation counts !
4
3
2
1
0 0
10
20
30
40
50
60
70
80
90
Angle
Figure 68: Shows the number of minimum bottom up circulations required for a 6000m tangent section at different tangent inclinations. The graph is qualitative, and it does not consider hole size. It should be used as a guideline only. The convey belt i.e. circulating at optimum flow rate and rpm, must be turned on thorough out the circulation period. Circulating 4 x btms-up at sub-optimum parameters = 0 btms-up for hole cleaning purposes.
3.3.4.2. Operational Guidelines 1. Bring pumps up slowly to the maximum flow rate. Observe pump pressure (fluctuating) for signs of pack-off see section 4.2.1. 2. Circulate at the maximum flow rate and rpm’s. 3. Keep reciprocating the string at all times to avoid creating a ledge. 4. Trip a stand every bottoms up to avoid circulating in the same spot for too long. 5. Monitor the shakers. 6. Be patient. Please note the term “circulating the hole clean” is a misnomer. In many cases you will never get the hole 100% clean, see section 1.4.6. What you are hoping is that you can get it clean enough to be able to trip through and run casing without problems.
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3.4. Connections & Surveying 3.4.1. Connection Practices: Sticking problems can occur when making connections. These have occurred in all hole sizes and have resulted in expensive Side tracking operations. The following guidelines should be used to minimize potential problems during connections. These guidelines assume top drive drilling 1. All Drillers should be familiar with these connection procedures. 2. Wipe the last joint prior to making a connection. If erratic or high torque is experienced prior to the connection, take time to ensure the cuttings are well above the BHA. 3. After making a connection break circulation slowly, checking for returns at the shakers. 4. Avoid starting and stopping the mud pumps suddenly. This may disturb the well bore downhole (shock loading effect). 5. Minimize the period without circulation during a connection. 6. If differential sticking is expected to be a risk; − Maximize pipe motion. − Consider rotation of string with slips set, whilst picking up the next stand. Beware of inducing slip cuts and, if you do, lay out that joint of pipe for inspection. Perform a risk assessment before attempting this procedure. 7. Connections should only be made if hole condition is good. Never make a connection with any over pull onto the slips. 8. Set slips high enough to allow downward movement. If hole conditions are sticky, extra stick up may be required. Take care not to bend the pipe. 3.4.1.1. Highly deviated wells Connection practices on highly deviated and ERD wells should be different than those on a vertical or low angle well. The recommended baseline connection procedure is as follows: 1. 2. 3. 4. 5. 6. 7.
Drill down the stand with the current rpm and flow rate Pick-up off-bottom and increases flow rate and rpm to their maximum Ream one stand out and back in (repeat if the hole is tight) Get Off-bottom Torque and String Weight Shut down the rotary Reciprocate the pipe and obtain Pick-up (PU) and Slack-off (SO) weights Shut down the pumps and make connection
The aims of the above connection procedure are to: −
Move cuttings away from the BHA to ensure a trouble free connection
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− −
Condition the new section of hole that has been drilled Collect Torque & Drag data in a consistent manner
3.4.2. Surveying - Stuck Pipe Avoidance While Surveying 3.4.2.1. Planning 1. Make sure the MWD or survey engineer is ready to survey before you stop drilling. Ensure the time taken to survey is not going to be excessive. Find out the maximum time required to go through the entire survey cycle and ensure this is both reasonable and is not exceeded. The average MWD survey takes from 3 to 5 minutes. It should be up to the person in charge on the rig floor to determine whether or not the pipe must be moved between surveys, or if another survey can be attempted. To cut down the survey time in a high risk area consider using power pulse instead of slim pulse. 2. Look at the survey requirements and discuss modified survey program through the high-risk zone i.e. are surveys required, can we use different tools? 3. Never allow the MWD operator to continue surveying without the Driller's, Directional Driller's or Tool pusher’s permission. 4. The depth or position on the Kelly of the next survey, the last survey result and the amount of reaming or circulating before and during the surveys should be written up on the rig floor. 5. To cut down the survey time in a high risk area consider using power pulse instead of slim pulse. 3.4.2.2. General/Operation 1. The pipe should be worked, reamed or circulated before taking a survey. The amount of pre-survey working, reaming, or circulating should be discussed with the Tool pusher and Wellsite Supervisor before drilling the hole section. 2. It is possible to rotate some MWD tools one or two minutes into the survey time. Ask the MWD operator for all of his options, especially if the hole is tight. 3. If the survey is required at a set depth, the Wellsite Supervisor may recommend more circulating before surveying. He may also recommend drilling a few more feet and then picking back up to that survey depth. All of these actions should be discussed at the pre-section meetings. 4. The position of the Kelly is of particular importance in preventing stuck pipe. The survey should never be taken with the Kelly completely down or immediately after the connection is made. There will not be enough room available to cock the jars and work the pipe should the hole become tight. A joint can be added or removed, but this wastes valuable time and may result in stuck pipe. 5. A good position to survey is the first or second tool joint of the stand. This position avoids taking a survey near the Kelly down position. The theory is to compensate for the stretch and compression of the drill string in order to operate the jars properly.
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6. Some wells require drill pipe screens to be placed in the box of the Kelly stand before the connection is made. The lower screen will then be removed from the box connection that is in the slips. The Wellsite Supervisor will decide if a screen will be run before tripping in the hole with an MWD tool. It is the responsibility of the crews to remove and install these screens and keep track of them at all times. The two-screen system works for most rigs. One screen remains on the drill floor while drilling and two while tripping, except when surveying whilst making a trip. During tripping the screen is installed only for the survey and is removed afterwards. 7. The risk of using screens should be carefully considered. Handling screens when drilling in stands with top drive presents a significant safety hazard. Some assets have stopped using them for this reason. The floor hands must clean out the screens after connections and report any washouts and abnormal amounts of junk that may plug up the screen or the MWD downhole. A plugging of either could reduce the ability to have full flow and increase the chance of stuck pipe. Screen in the standpipe/mud line can eliminate the possibility of misplaced drill pipe screens. 8. Ensure all screens are removed after circulating for a survey. If a screen is left in the string by accident it could prevent any wireline work that may be needed for a free point or back off. 9. Consider the effect hole condition may have on survey interval times when surveys are dropped before tripping. If hole conditions are poor the Kelly may need to be picked up to circulate or back ream during the trip out through open hole. The additional time this may take should be added when setting survey time intervals. 10. The effect of mud additives on the survey tools should also be considered. Some additives can increase the chance of packing-off inside the survey tool. This is especially true if the mud contains Lost Circulation Materials (LCM).
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3.5. Tripping The majority of stuck pipe events occur while tripping, especially in deviated wells where hole cleaning is an issue. It is therefore imperative that trips should be carefully planned and executed.
3.5.1. Considerations Prior To Tripping Planning the trip out of hole is extremely important in deviated wells. Things to consider in the plan are: 1. The hole will never be 100% clean even circulating at optimum parameters. 2. Identify trouble spots from offset data and previous trips and plan for them. o Where will we encounter a build up of cuttings? Do I need to circulate at different inclinations to mitigate hole pack-off e.g. 75, 60 & 45deg inclinations? o Troublesome formations e.g. tight formations, ledges. Will I need to ream through these areas? 3. ‘WHAT IF’ questions, e.g. − ‘What if’ I don’t move the string for 2 minutes − ‘What if’ I get stuck pulling out? − ‘What if’ I get stuck running in? 4. The preparedness and appropriate response by Drillers and Assistant Drillers when they encounter: − Swab and surges and the effect on hole stability − Excessive over pull or resistance and the decision to pick up the Kelly or top drive − Tendency of the hole to pack-off during circulation or when breaking circulation − Likelihood of key seats developing over intervals with severe doglegs − Decision to ream or back ream. 5. What is the maximum initial over pull limit over normal drag before the driller stops and goes back down? Normally it is the 30Klbs rule. 6. Optimising the mud system to facilitate tripping i.e. adding lubricates, condition mud for casing and cementing 7. Communicate the plan to the rig team. Hold a pre-trip meeting during the last part of the circulation.
3.5.2. Considerations During Tripping 1. Pull slowly and at constant speed. This allows the cuttings to flow around the BHA junk slot area and stops the cuttings building up around the top of the BHA and/or top stab. 2. Monitor drag. 3. Record the depth of the top of the BHA while circulating bottoms up prior to tripping. Take extreme care when the top stabilizer reaches this depth and for
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the following two stands, as this is the likely place the BHA will be pulled in to a cuttings bed if one exists. 4. Apply the 30Klbs over pull rule. This is a rule to used for initial over pulls over normal drag while tripping out of the hole. Do not initially pull more than 30k lbs. If over pull exceeds 30klbs consider all resistance in a deviated well as hole cleaning related. The first action should always be to go down 1-2 stands and circulate btms-up. If the resistance is still there after circulation then other measures such as reaming can be started. 5. Always bring the pumps up slowly and watch for pack-offs. The best way is to raise the flow rate is in pre-determined steps once the circulating pressure has stabilised for that step. 6. Pumping out and back reaming in a dirty hole increases the chance of packoff and stuck pipe. The initial response is: a. Circulate the hole clean to remove the cuttings. b. Pull dry until resistance is encountered – 30Klbs rule c. Run in 1-2 stands and circulate hole clean. d. Pull dry past initial resistance and continue out of hole. If resistance is still encountered consider back reaming as an option.
3.5.3. Reaming and back reaming. Reaming is a high-risk operation, which accounts for a large proportion of stuck pipe incidents. If reaming operations are conducted too fast solids from washouts and caving’s are introduced into the circulating system at a faster rate than the hole is being cleaned. This results in a pack-off. Do not assume that any resistance is always at the bit; stabilisers and drill collar contact may be indicative of a build up of loose material in the hole and a potential pack-off situation. The following guidelines are offered as a general list. 3.5.3.1. Planning 1. Have a contingency plan for all possible problems. E.g., what to do in case of a leaking wash pipe or leaking saver sub. 2. Always pre-plan a trip. Have an up-to-date mud log/PASON data on the rig floor. Know where high doglegs exist and note troublesome areas from past trips. 3. Have singles in the V-door in case downward motion is required to free the pipe after a connection. 3.5.3.2. Organisation 1. The shakers must be monitored continuously and the volume of solids being removed from the well bore should be recorded. 2. While drilling or reaming in problem formations have two people at the console: one man on the brake and the other on the pumps (spm dials). The man on the pump is there to react to the signs of hole pack-off (sudden increases in pressure).
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3. Ensure that the driller knows what actions to take in the event of problems. Are over pull limits, freeing procedures and reaming practices understood? Are written instructions for the driller prepared and updated regularly? 4. Mud loggers will record all parameters. Significant changes in trends should be reported immediately to the driller and well site supervisor, and then investigated. 3.5.3.3. Parameters 1. Use optimums parameters for reaming operations. This assists in identification of changes in torque and pressure trends. Ensure that the flow rate is sufficient to clean the hole. 2. Any indication of changes in parameters should be addressed immediately. Most drag problems can be reduced by time spent circulating the hole clean. 3. An increase in drag, torque or pressure may indicate that the annulus is loaded up, and a pack-off may be forming. Circulate and clean the well bore before continuing reaming. 4. If indications of a pack-off occur, immediately reduce the pump strokes (e.g. by half) to reduce the pistoning effect. If, after several minutes the hole does not pack-off, return to the original parameters and be prepared to circulate the hole clean. 5. Reaming speed and circulation time should be adjusted if the returning cuttings' volume rate is excessive. 6. If torque becomes erratic or any of the following occurs: a. The rotary is stalling out. b. The cave-in rate increases. c. Torque and pressure readings are increasing; be prepared to stop, circulate and clean up the hole. 7. Prior to heavy reaming, slow rotation (<80 rpm) should be used in an attempt to "walk” the pipe past ledges. 8. Reaming operations should be conducted with the same flow rate as drilling. Be aware of formation washout risk in unconsolidated formations. 9. Reaming weight and speed should be kept low (< 10 - 15k lbs either up or down). This reduces the chance of sidetracking the well and is less damaging to the drill string. Torque and weight on bit should also be less than the same drilling parameters through that section. 10. Control the speed of reaming operations (4 stands an hour can be used as a rule of thumb for the maximum speed). This should also reduce the mechanical damage the drill string does to the well bore. 11. Large volumes of settled cuttings or new carving’s can be introduced to the hole when reaming. It is critical that this material is circulated out of the hole. 3.5.3.4. General/Operation 1. If the hole packs-off, immediately shut down the pumps and slowly bleed the pressure under the pack-off down to less than 500 psi.
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2. While reaming in problem formations the hole may need to be wiped at regular intervals, if conditions require it. 3. Do not use the Soft Torque (torque feedback system used to reduce torsional vibrations) while reaming as it may disguise torque trends. 4. Make sure the pipe is free before setting the slips. 5. After drilling or reaming down, the cuttings should be circulated above the BHA prior to picking up. 6. The preferred practice is to always try to work the string past a tight spot as a first option. However, over pull limits must be known and used. Work up to the over pull limit in stages ensuring free movement in the other direction at each stage. 7. If the top drive stalls out during reaming operations there is a great deal of stored energy in the drill string, always release this torque slowly. 8. When back reaming do not over pull the pipe into the slips to connect the top drive. 9. When washing in, with a motor in the BHA, rotate the whole drill string at low rpm. 10. Back reaming is extremely hard on equipment, especially motors e.g. shocks and vibrations. 3.5.3.5. Example of excessive back reaming
• • • •
Circulation for 7 hrs Hole condition deteriorates with time High Shocks appeared. Large cuttings/cavings on surface. 132
Figure 69: Downhole and surface drilling data chart. The peaks in the resistivity have been interpreted as washouts caused by excessive back reaming.
This example illustrates the downside of excessive back reaming. Here the formations were relatively unconsolidated with a well inclination of 60deg. The rule of thumb again is to circulate after every 500ft. Back reaming was carried out for several hours due to the fact that the shakers were heavy loaded during the back reaming operation. While the driller thought the circulation and back reaming operation was actually cleaning the hole, the downhole measurement showed otherwise. ECD showed that the cuttings were being generated downhole from the back reaming operation across the unconsolidated formation. Resistivity measurements also started showing divergent signals indicating that the hole size was undergoing enlargement due to washout of the formation. 3.5.3.6. Example of effect on ECD of pumping out of hole.
ECD trend as pumping out was initiated
Figure 70: Downhole and surface drilling data chart.
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Figure 70 shows the evidence of high and unsteady ECD trends while pumping out of hole. The ECD value prior to POOH was 10ppg. But as operation progressed, ECD increased to a maximum of 11.5ppg. This indicates that the hole condition with respect to cuttings was not in good shape. The result was a tight spot and over pull while tripping out of hole.
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3.6. Differential Sticking The theory of differential sticking has been discussed in the Trouble Free Drilling Manual Volume 1, Chapter 9. This section will concentrate on prevention during the execution phase. To prevent differential sticking we need to minimise following conditions: 1. 2. 3. 4. 5. 6. 7.
Permeable formations – out of our control. Filter Cake – dependent on mud properties. Overbalance Wall Contact Static Pipe Time Side loads
MW
THICK WALL CAKE
PIPE
PIPE
Figure 71: Schematic showing differential sticking.
3.6.1.1. Permeable formations There is a higher risk of getting differentially stuck in a permeable formation then there is in a tight shale formation. If permeable formations are present, and the pore throat sizes are known (from core data) then plugging material can be added to the mud system to block the pore throat and reduce the permeability around the wellbore.
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In reservoir sections the plugging material must be removable to reduce the impact on production. 3.6.1.2. Filter Cake The filter cake should be thin, hard and impermeable. It is determined by the mud type and it’s properties. Focus during drilling should be on maintaining the mud rheology at its recommended values and this is highly dependent on the competence of the mud engineer and the type and condition of solids control equipment. Both laboratory studies and field use suggest that cellulosic lost circulation materials (LCM’s or Seepage Control Materials, SCM’s), lubricants and fluid loss reducing agents incorporated into the mud system can mitigate differential sticking potential (DSP).
Product
Supplier
Concentration (Vol. %)
BXR-L
Baroid
3.00
DL-100
Chemrich
3.00
Chemical Description Blend of asphalt and sulfonated asphalt in glycol carrier Sulfurized paraffinic material Surfactant blend
DRIL-KLEEN M-I
0.17
HF-100N
Hydra Fluids
10.00
Neutralized polyglycerol
IDLUBE XL
M-I
3.00
Organic acids/alcohols/ esters blend in glycol Calcium sulfonate
Lubrizol 1000 Lubrizol SCM’s
Various Suppliers
3.00 2 to 16 lb/bbl
Cellulosic fibers
Table 20: Various materials studied in POLYNOX, bentonite, and low-solids non-dispersed mud’s that can help mitigate DSP.
3.6.1.3. Overbalance Minimise the overbalance as much as possible. Do not allow the mud weight to slowly build up density whilst drilling and limit the amount of cuttings in the mud system. 3.6.1.4. Wall Contact The golden rule here is to minimise the wall contact as much as practically possible. Measures can include:
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1. Drill with small tubulars in large hole sizes e.g. small drill collars. Buckling & hole cleaning could be an issue in some circumstances. 2. Minimise the amount of drill collars in the BHA. Use HWDP for weight and drill with a downhole mud motor. 3. Use spiral drill collars and HWDP. 4. Stabilise the BHA to keep the tubulars away from the wall. 3.6.1.5. Static Pipe Differential sticking does not occur until the pipe remains motionless long enough for the lubricating layer to drain into the filter cake. Motionless pipe is unavoidable, as connections and surveys must be made. We must try to avoid any unnecessary static pipe and plan surveys carefully. 1. Follow the connection and survey guidelines in this chapter. Ensure that the survey is taken at least a joint off bottom to ensure the jar can be fired downwards. 2. Is directional control required? Do we need surveys through this formation? Challenge the program to minimise the amount of stationary time. 3. For unscheduled repairs continuously reciprocate the pipe and continue circulation (if possible). 3.6.1.6. Time It takes time to develop the differential sticking pressure necessary to cause a sticking force. The crews need to be aware of the first signs of the onset of differential sticking (increasing drag) and they need to know how to react e.g. re-establish pipe movement as quickly as possible. 3.6.1.7. Side loads Doglegs through permeable formations should be avoided, especially high in the open hole section. Long, heavy BHA’s in high inclinations will cause drag and impart a large side load on the low side of the hole. Good tripping practice calls for the pipe motion to be downward prior to setting the slips. This is partly to remove the excessive tension in the string that leads to higher side loads.
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3.7. Problematic Shale’s The theory of Shale stability and failure is covered in detail in the Trouble Free Drilling Manual, Volume 1: Stuck Pipe Prevention, Chapter 8.
3.7.1. Swelling Shale’s. Mud inhibition is the best way to combat swelling shale’s. Unfortunately, the fluids that provide this e.g. OBM, are normally prohibited in the shallower sections where they occur. Instead, we have to use partly inhibitive water based mud systems and good drilling practices to minimise the risk. An extremely good best practice on minimising the NPT caused by swelling shale’s is documented in Intouch Content ID: 3945116 - Clay Rings.
Figure 72: Picture from Intouch Content ID 3945116 of a clay ring at surface.
3.7.1.1. General guidelines 1. Minimise exposure time of the formation. 2. Minimise the number of stabilisers in the BHA.
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3. Drill with a high flow rate. The idea is to try and stop the cuttings joining together and forming a clay ring. 4. Good bit hydraulics. If drilling with a rock bit, use one with a centre jet. 5. Maintain the desired mud properties. 6. Good solids control equipment. 7. Stop drilling and circulate the hole clean at regular intervals.
3.7.2. Caving’s 3.7.2.1. What are Caving’s? Caving’s are rock fragments produced by wellbore instability and transported to surface in the drilling mud. Typical carving’s are centimetre sized fragments, but can range from 1mm to more than 10 cm. Small carving’s, called “coffeeground carving’s” can form from disaggregating of larger water-sensitive shale carving’s. Larger cavings are typically produced from naturally fractured formations. Natural fracture planes bound such caving’s. 3.7.2.2. Cavings Analysis Interpretation of caving’s morphology: − −
Helps determine cause of wellbore failure Helps determine optimal remedial action
Angular
Splinter
Platy
Figure 73: Photographs of the three main types of caving’s.
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Monitoring the volume of caving’s versus time: • Provides an early warning of wellbore instability • Signals need to improve hole cleaning • Indicates which drilling practices destabilize the wellbore
Figure 74: Caving’s vs. time graph
3.7.2.3. Angular Caving’s These multifaceted rock fragments result from shear failure of the wellbore.
Newly Created Fracture Surfaces
Wellbore Surface
Figure 75: Shows typical angular caving’s.
Key Characteristics − Facets are newly created fracture surface − Facets may be curviplanar
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− − −
Facets are nonparallel Failure-two regions on the wellbore separated by 180° Indicates compressive failure of rock
Scanline Fig. 17
A
B
A C
B
Wellbore Surface Figure 76: Borehole Images illustrating sections of wellbore that have suffered shear failure (dark bands A and B) which are the sources of angular caving’s. RAB* (Resistivity At Bit) images allow diagnosis of wellbore failure while drilling.
Remedial Action − If mud weight close to Pp: raise mud weight − If mud weight close to fracture pressure Maintain mud weight Decrease fluid loss Manage hole cleaning 3.7.2.4. Platy/Tabular Caving’s These caving’s are rock fragments bounded by pre-existing planes of weakness.
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Bedding planes
Natural Fractures
Figure 77: Shows various examples of blocky/platy caving’s.
Key Characteristics − Majority of caving surfaces represent pre-existing planes of weakness − One or more parallel surfaces are common − Surfaces tend to be relatively smooth and planar − Failure initiates on high side of wellbore when well is nearly parallel to a plane of weakness
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Figure 78: Schematic diagram of a well intersecting pre-existing planes of weakness (bedding, fractures). Platy-blocky caving’s originated on the high side of the hole due to gravitational instability.
W e l l De v i a t i o n A z im ut h
Bedding planes Natural Fractures
Figure 79: Schematic borehole cross-section (looking down hole) showing locus UBI image (right) high side damage is oriented 330°. Note: High side damage is well developed when wells are deviated along bedding or fracture dip direction.
Remedial Action − Maintain mud weight − Minimize fluid loss coefficient of drilling mud − Use crack blocking additives − Avoid back reaming − Manage hole cleaning − Avoid excessive rpm and drillstring vibrations 143
−
Employ gentle drilling practices
3.7.2.5. Splintered Caving’s These elongated platy rock fragments result from tensile failure of the wellbore. Splintered caving’s are believed to form as a poroelastic response to drilling too fast through low-permeability shale or drilling underbalanced.
Plume Structure
Figure 80: Plume structures in splintered caving’s.
Key Features − Typical lithology: low-permeability shale fragments − Caving surfaces show plume structure indicative of tensile failure e.g. drilling underbalanced − Entire circumference of wellbore may be damaged
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Figure 81: Surface structures commonly associated with extension (mode 1) fractures (after Kulander and Dean, 1985).
Remedial Action − Raise mud weight − Reduce rate of penetration 3.7.2.6. Geo-mechanics Wellbore stability studies are key in mitigating the risk of unstable formations. There define the stable wellbore pressure window (optimum mud weights) and optimum well trajectory, and identify and locate geological hazards. They can be constantly refined & updated throughout the drilling process (PERFORM) and are essential in high-risk areas (see section 1.2.1.5 & figure 82).
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Figure 82: Shows an output screen from a wellbore stability study.
3.7.2.7. Drilling Guidelines 1. Minimise Open hole time: Mud types that allow a certain degree of pore pressure penetration, will with time, cause formation pressures to gradually equalise with the mud pressure. Thus net effective rock stresses will increase around the borehole, bringing the shale either to or close to failure. Minimising open hole time will therefore reduce the chance of borehole stability problems. 2. Pressure fluctuations: Pressure fluctuations in the well can cause caving’s to be pulled into the hole or they can directly cause shale failure. At all times pressure fluctuations should therefore be minimised and care should be taken when tripping in/out or breaking circulation. Proper mud conditioning i.e. keeping the gels and the plastic viscosity within specified limits will help to decrease pressure fluctuations when circulating or pulling or running pipe. 3. Hole cleaning: Hole cleaning is very important to prevent sticking problems after shale failure has occurred. However, proper hole cleaning can also help to prevent shale instability! Insufficient hole cleaning will lead to large amounts of solids in the hole. This effectively increases mud pressures exerted
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on shale formations, which in turn causes an increase in pore pressure penetration and de-stabilisation of the shale’s. 4. Mud weight increase: Ideally, shale’s should be drilled with a mud system, which totally prevents pore pressure penetration, and if correct initial mud weights are used shale failure will be prevented. However, most WBM systems do allow a certain degree of pore pressure invasion and in those cases, the de-stabilising effect of pore pressure penetration can somewhat be reduced by increasing the mud weight gradually in small steps. Every weight increase provides a small increase in effective mud support, which stabilises the hole. However, this increased mud support is only effective for a limited time since the new mud pressure and formation pressure will equalise. Increasing the mud weight in small steps over a long time period is thought to be more effective in providing sustained mud pressure support than a single large increase. 5. Do not decrease the mud weight: When the mud weight is lowered in an open hole section which has previously been drilled with a higher mud weight, shale’s will be exposed to increased rock stresses and may fail, especially when pore pressure penetration has decreased the required mud pressure at which shale failure will occur. Lowering the mud weight before a hole is cased off increases the chance of borehole instability in shale’s! It should be realised that decreasing the mud weight after a hole is cased off can still cause shale instability in the pocket below the casing. These stability problems will only become apparent when drilling out the casing shoe and pocket. Thus, lowering the mud weight should be prevented whenever possible. 6. Drill string vibrations: The mechanical action of the rotating drill string against the borehole wall can cause shale fragments to be pulled into the hole and in some cases can initiate failure in brittle shale’s. Thus is it important to minimise vibrations in the drill string. Back-reaming i.e. rotating the drill string whilst pulling out of hole can also cause shale fragments to be pulled/pushed into the wellbore. It is therefore important to use back reaming only when necessary i.e. in tight whole situations. 7. Monitoring: More than one type of caving (mode of instability) can be produced in a single openhole section. The rig team must determine which mode of failure is most problematic and take the appropriate remedial action. It is important to respond to sudden changes in caving’s rate. A small constant volume of caving’s production is worth monitoring but may not require immediate remedial action. The use of caving’s morphology to diagnose wellbore failure caving’s is relatively new. When interpretation of caving’s is problematic, e-mail a digital image of the caving’s to a geomechanics specialist. Include a coin or ruler for scale and, if possible, locate the source on a (RAB, UBI, FMI*[Fullbore Formation Micro Imager]) borehole image or on an oriented 4-arm or 6-arm calliper.
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4. IDENTIFYING & FREEING STUCK PIPE The first three chapters of this manual have concentrated on stuck pipe prevention. In an ideal world we would not need this next section, which focuses on remedial action once we have got stuck. Unfortunately the world is not perfect. The flowchart below shows the stuck pipe process.
FREEING STUCK PIPE Stuck Pipe Identify SP Mechanism
Estimate Stuck Point
Start Working Pipe Calculate Optimum Fishing Time Cut Pipe & Fish End Time
Switch Freeing Method
Continue Working Pipe
Give up trying to free pipe
Pipe Freed
Sidetrack or P&A
Remedial Action
Figure 83: Flow diagram detailing the stuck pipe process.
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4.1. Stuck Pipe Identification Once a stuck pipe incident has occurred, an understanding of the mechanism is very important. The correct remedy, beginning with the first action to be employed depends on knowing the cause of the sticking event. Wrong or improper understanding of sticking mechanism and/or wrong application of first actions worsens many stick pipe incidents. In the event of a stuck pipe incident, the following steps should be considered. Evaluate the sticking mechanism and employ the most appropriate first action without delay. If this could not help free the pipe, employ a secondary freeing action (e.g. pumping pills etc), followed by series of jarring operations. A backoff operation is then considered and an attempt to fish carried out. How long the freeing operation takes is dependent on the economics of Fishing. Below is a detailed explanation of these steps
4.1.1. Stuck Pipe mechanism Identification Worksheet The Stuck Pipe mechanism Identification worksheet below will be helpful in determining the Stuck Pipe mechanism. Although the worksheet does not always provide a conclusive indication of the Stuck Pipe mechanism, it helps to eliminate mechanisms that are not contributing to the stuck pipe incident. When the stuck pipe mechanism is determined, attempt to free the string will follow a more focused approach.
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STUCK PIPE MECHANISM IDENTIFICATION WORKSHEET PIPE MOTION PACK-OFF / WELLBORE PRIOR TO STICKING? BRIDGE DIFFERENTIAL GEOMEETRY Moving Up 2 0 2 Rotating Up 0 0 2 Moving Down 1 0 2 Rotating Down 0 0 2 Static 2 2 0 PIPE MOTION AFTER STICKING? Down Free 0 0 2 Down Restricted 1 0 2 Down Impossible 0 0 0 PIPE ROTATION AFTER STICKING? Rotate Free 0 0 2 Rotate Restricted 2 0 2 Rotate Impossible 0 0 0 CIRCULATING PRESSURE AFTER STICKING? Circulation Free 0 2 2 Circulation Restricted 2 0 0 Circulation Impossible 2 0 0 TOTALS INSTRUCTIONS: Answer the shaded questions by circling all the numbers in the row with the correct answer. Add the columns, the column with the highest number indicates the sticking mechanism. INSTRUCTIONS: Answer the shaded questions by circling all the numbers in the row with the correct answer. Add the columns, the column with the highest number indicates the sticking mechanism.
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4.1.2. Stuck Pipe Summary Tables: 4.1.2.1. Table 21: Hole Pack-off. Problem
Settled Cuttings
Shale Instability
Unconsolidated, Fractured Formation
Cement (Blocks or Soft)
Junk in Hole
Causes
- Drilling too fast - Inadequate annular velocity or rheology - Cuttings accumulation (washouts) - Not enough circulating time - Drilling blind without sweeps - Drilling without circulating
- Drilling reactive shale with non-inhibitive mud - Drilling pressured shale with insufficient mud weight
- Drilling uncemented formations - Little or no filter cake - Drilling naturally fractured formation
- Cement blocks fall from around casing shoe, squeeze plugs or sidetrack plugs - Attempt to circulate while the drillstring is immersed in soft cement (flash set)
- Accidental junk falling in hole - Downhole equipment failure
Warning signs and indications
- High ROP with poor cuttings return - Increase in torque, drag and pump pressure - Overpull on connection and when tripping - Fill on bottom after connection and trips - Circulation restricted - Increase in LGS and mud weight
- Increase in FV, PV, YP, gels, and CEC - Increase in torque, drag and pump pressure - Overpull on connection and when tripping - Bit & BHA balling - Pore pressure increase - Fill on connection and after trips - Large cavings at shaker - Circulation restricted
- Solids-control equipment loaded with sand and cuttings - Seepage losses - Fill on connections and after tripping - Sudden increase in torque and drag - Circulation restricted - Large cavings at shakers
- Excessive casing rathole - Increase in torque and drag - Circulation restricted - Restricted pipe movement
- May occur any time - Metal parts at the shakers - Partial motion is possible
Prevention
- Proper mud rheology - Use maximum GPM for hole size - Control ROP if needed - Pump sweeps to clean the hole - Wiper trip after motor run - Increase drillstring rotation - Circulate longer
- Use inhibited mud - Increase mud weight - Minimize open hole exposure time - Use sweeps to clean the hole - Increase mud rheology
- Provide good filtercake quality - Use appropriate bridging materials - Avoid excessive circulating time - Use sweeps to keep the hole clean - Increase mud rheology
- Limit casing rathole - Allow sufficient time for cement to set - Reduce tripping speed opposite cement section - Calculate top of cement and start circulation two stands above - Control drilling in soft cement
- Use good practices - Keep hole covered - Check downhole tools on regular basis
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4.1.2.2. Table 22: Well Geometry Problem
Key Seating
Undergauge Hole
Stiff Assembly
Mobile Formation
Doglegs & Ledges
Collapsed Casing
Causes
- Drill pipe wears a keyseat in the formation - Often associated with doglegs - Drill collars jam into the narrow groove of keyseat
- RIH with a fullgauge bit and BHA in an undergauge hole
- BHA change from limber to stiff cannot tolerate changes in angle & direction
- Drilling plastic salt or shale formation
- Drilling hard/soft interbedded formation - Frequent change in hole angle/direction - Drilling fractured/ faulted formation - High dip angles
- External formation pressure (often opposite plastic formation) exceeds casing strength - Failed cement
Warning signs and indications
- Severe dogleg section - Pipe rotating at the same spot for extended period of time
- Undergauge bit pulled - Tight hole - Sudden loss of string weight
- New BHA is run in hole - Presence of doglegs - Sudden loss of string weight - Tight hole
- Increase in torque and drag - Overpull when tripping out of hole
- Overpull on connections & trips - Increase in torque and drag
- Drilling plastic formation - Cement chucks - Lost circulation - Tight hole inside casing
Prevention
- Minimize dogleg severity - Wiper trip/ream dogleg sections - Use keyseat wiper or reamer
- Gauge old & new bits - Ream last three joints at least to bottom - Never force bit through tight spot, ream
- Minimize BHA changes - Limit dogleg severity - Plan a reaming trip if a stiff BHA will be used
- Maintain sufficient mud weight - Select the proper mud system - Frequent reaming/ tripping - Use eccentric bit - Minimize open hole exposure time
- Minimize sharp and frequent wellbore course changes - Avoid prolonged circulation opposite soft formation - Minimize BHA changes
- Use proper casing strength opposite plastic formation
4.1.2.3. Table 23: Differential Sticking Problem
Differential Sticking
Causes
- The hydrostatic pressure exceeds formation pressure
- Porous permeable formation - High fluid loss
- Thick, poor quality filter cake - Pipe stationary too long
Warning signs and indications
- Circulation is not restricted when stuck - Increase in torque & drag
- Drilling with high overbalance - Poor filtration properties
- Overpull opposite porous formation - Hole sticky on connection
Prevention
- Minimize overbalance - Control downhole filtration - Minimize time pipe is stationary
- Minimize area of contact by using heavy-weight drillpipe & spiral collars - Maintain optimum hydraulics - Proper casing design
-
Improve filter-cake quality Minimize coefficient of friction, use lubricant Use proper bridging agents Minimize drill solids content
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4.1.3. Stuck Pipe Identification Trees 4.1.3.1. Figure 84: Stuck Pipe incident when ROTARY DRILLING Rotary Drilling Increased Torque
Is there a formation Change?
Are bit hours Excessive?
Are hole Drags Excessive? Have abrasive Formations been Drilled ?
N Have formations of Varying hardness been drilled?
N
N
N
Can drag be related to dogleg ?
Y
Y
Can hole problem be related to a formation change?
Stabilizers Hanging up On formation Ledges
Is Circulation restricted?
N
N Bit failure String Component failure
N
Undergauge hole causing stabilizers to hang up?
Y
Increase in Torque Related to formation Change
Y
If Tri-cone bit bearings worn
Y
Wellbore Geometry
Y
N
Cement Blocks Junk Casing Keyseat
Y
Inadequate Hole cleaning
Are Drags reduced when pumping?
Y
N
Have problem formations Already been exposed?
Y Fractured/Faulted Formations
Y Slow moving mobile Formations reactive formations
N Newly drilled Geopressured forms Unconsolidated forms Fractured/Faulted forms Fast moving mobile forms
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4.1.3.2. Figure 85: Stuck pipe incident when MAKING CONNECTION Moving pipe from static after making/breaking connections during drilling, tripping and reaming or after surveys
Drag trend increasing when moving string from static
Is circulation restricted? Are known problem formation exposed?
Y Reactive formations Fractured/faulted formations Mobile formations Unconsolidated formations Geopressured formations
Y
Are permeable formations exposed?
N
N
Y
Is drag reduced when pumping?
Y
Can drill string be moved?
Junk Cement blocks String component failure Stabilisers hanging up on ledges
N Y
Inadequate hole cleaning
N
Reactive formations Fractured/faulted formations Mobile formations Unconsolidated formations Geopressured formations
Junk Cement blocks Stabilisers hanging up on ledges
N
Differential sticking
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4.1.3.3. Figure 86: Stuck Pipe incident when CIRCULATING
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4.1.3.4. Figure 87: Stuck Pipe incident when RUNNING CASING
Running Casing
Increase in downwards resistance while running casing or after connection Can pipe be worked upwards?
Is circulation restricted? Hole packing off Reactive formation Unconsolidated formation
Y
N
Surface load limitation with respect to larger drag (especially directional well) Inadequate hole cleaning (Cuttings beds) Centralisers broken/bunching
N
Is circulation restricted?
Y Are dog-legs excessive?
Are permeable formations exposed?
N N
Y
Y
N
Y
Hole packing off Reactive formations Mobile formations Unconsolidated formations Inadequate hole cleaning
Wellbore geometry
Differential sticking
Formation ledges Fractured/faulted formation Inadequate hole cleaning Centralisers broken/bunching Casing too light (Has not been filled) Junk in hole
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4.1.3.5. Figure 88: Stuck Pipe incident when TRIPPING IN
Tripping In Increase in downward resistance
Is increase smooth or erratic?
Smooth
Erratic Is there excessive upward drag?
Is there excessive upward drag? Inadequate hole cleaning (Cuttings beds)
N
Y
Y Is drag reduced when pumping?
N
Hole bridged Can this be related to problem formations?
Is circulation restricted?
N
N
Was previous bit undergauge?
Y
N
Y
Formation ledges Wellbore geometry Cement blocks Junk
N
Was previous bit undergauge?
Y
N
Y Reactive formations Mobile formations Fractured/faulted formations Unconsolidated formations
Undergauge hole Are dog-legs excessive?
N Reactive formation Mobile formation
Inadequate hole cleaning
Wellbore geometry Formation ledges
Y
Y
Undergauge hole Has there been a BHA change on this trip?
Can resistance and drag be related to formations?
N Cement blocks Junk string Component failure
Y
Formation Ledges
N
Y
Wellbore Geometry
Fractured/faulted formations
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4.1.3.6. Figure 89: Stuck Pipe incident when TRIPPING OUT
Tripping out Increased drag or overpull
Is overpull smooth or erratic?
Smooth
Erratic Is overpull in new hole section?
Is overpull in new hole section? Are known problem formations exposed in new hole section?
Y Is circulation restricted?
Y
N
N Is circulation restricted?
N
Inadequate hole cleaning
Wellbore geometry Fractured/faulted formation
Is circulation restricted?
N Wellbore geometry Formation ledges
Are known problem formations exposed in hole section drilled by previous bits?
Are known problem formations exposed in hole section drilled by previous bits?
N
N
Y
Reactive formations (Bit/stabiliser balling) Mobile formations Unconsolidated formations
Y
Y Inadequate hole cleaning
Y
Y Is circulation restricted?
Y
Y
Y
N
N Cement blocks Junk
Formation ledges Wellbore geometry
N Can BHA be rotated free?
Y
Key seating
Y
Cement blocks Junk
Fractured/faulted formations
N
Y
Is downward motion possible?
Is circulation restricted?
Can BHA be rotated free?
N
N
Unconsolidated formation Fractured/faulted and Geopressuredformation
Is downward motion possible?
N
Reactive formations (Bit/stabiliser balling) Mobile formations Unconsolidated formations
Are known problem formations exposed in new hole section?
Y
N
Unconsolidatedor Fractured/ Faulted formations
Wellbore geometry Formation ledges
N
Formation ledges Wellbore geometry
Y
Key seating
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4.1.3.7. Figure 90: Stuck Pipe incident when REAMING IN Reamingin
Increasedtorque Increasedreaming weight required Is increase smoothor erratic?
Smooth
Erratic Iscirculation restricted?
Is circulation restricted? Areholedrags excessive?
Y
N
Y
N
Inadequatehole cleaning
Dodrags increasewhen not pumping?
Y Inadequate holecleaning
N
Are updrags excessive?
Was previous bit undergauge?
Y
Undergaugehole
N
Y
N
Y
Inadequatehole cleaning (Cuttingbeds)
Wellboregeometry (Side-trackinghole?)
Inadequate holecleaning
Waspreviousbit undergauge?
Y
Undergaugehole
Aredrags increasedwhen not pumping?
Mobileformations Reactiveformations Unconsolidatedformations
N
Y
N
N Wellbore geometry Formationledges Junk Cement blocks Bit failure
Unconsolidatedformations Fractured/faultedformations
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4.1.3.8. Figure 91: Stuck Pipe incident when REAMING OUT
ReamingOut
Increasedtorque &Drag
Is increase smoothor erratic?
Smooth
Erratic Iscirculation restricted?
Iscirculation restricted? Areholedrags reducedwhen pumping?
Y Inadequate Holecleaning
Y
N
Isdownward motionrestricted?
Y
N MobileFormations ReactiveFormations
N
Wellboregeometry FormationLedges StringComponent failure
Y
Unconsolidatedformations Fractured/faulted formations
N
Junk Cement Blocks Stringcomponent failure
KeySeating
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4.2. First Actions to free 4.2.1. Solids Induced - First Actions The stuck pipe mechanisms listed below (in order of occurrence) are solids related mechanisms and the same first actions apply. They are covered in detail in Volume 1 and the appendix of this manual. − − − − − − − − − − −
Hole Cleaning Unconsolidated Formations Reactive Shale’s Naturally Over-Pressured Shale’s Fracture and Faulted Formations Induced Over-Pressured Shale’s Tectonically Stressed Formations Overburden Stress Junk in the Hole Green Cement and LCM Treatment Cement Blocks
4.2.1.1. Excessive Over pull This is the most important first action. It is the stage when you are not completely stuck and you still have movement in the opposite direction. If the driller reacts correctly you can still retrieve the situation. The golden rule when excessive over pull is observed when tripping in deviated wells is to assume that it is hole cleaning related e.g. there is a build-up of cuttings (could be caving’s) around the BHA which is stopping you from coming out of hole. The first action tripping out: 1. Run back in hole at least 1 stand, but preferably 2. 2. Switch on pumps and bring flow rate up in stages to maximum rate. Rotate drill string at maximum rpm. 3. Circulate for at least one bottoms-up at maximum flow rate and rpm. 4. Monitor shakers. If large amounts of cuttings are coming over the shakers then circulate until the shakers are clean – consider pumping sweeps. 5. Stop pumping. 6. Pull past original stuck point. a. If no over pull then it was hole cleaning related. b. If the same over pull is observed then it is probably a mechanical or geometry related problem and the appropriate actions taken e.g. back reaming.
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What normally happens. The flow rate is brought up too quickly which increase the risk of pack-off.
SPM Pump strokes should be brought up to maximum flow rate in planned steps. The next step increase should only occur once the pressure has stabilised.
Time Figure 92: Graph showing how the SPM should be brought up in steps.
4.2.1.2. Packing Off - First Actions 1. At the first signs of the drill string torquing up and trying to pack-off, the pump strokes should be reduced by half. This will minimise pressure trapped should the hole pack-off. Excessive pressure applied to a pack-off will aggravate the situation. If the hole cleans up, return flow to the normal rate. 2. If the string packs off, immediately stop the pumps and bleed down the standpipe pressure [NB not possible with a non-ported float valve]. When bleeding pressure down from under a pack-off, control the rate so as not to "U" tube solids into the drill string in case they plug the string. 3. Leave low pressure (<500 psi) trapped below the pack-off. This will act as an indicator that the situation is improving should the pressure bleed off. 4. Holding a maximum of 500 psi on the standpipe and with the string hanging at its free rotating weight, start cycling the drill string up to maximum makeup torque. At this stage do not work the string up or down. 5. Continue cycling the torque, watching for pressure bleed off and returns at the shakers. If bleed off or partial circulation occurs, slowly increase pump strokes to maintain a maximum of 500 psi standpipe pressure. If circulation improves continue to increase the pump strokes. 6. If circulation cannot be regained, work the pipe between free up and free down weight. DO NOT APPLY EXCESSIVE PULLS AND SET DOWN WEIGHTS AS THIS WILL AGGRAVATE THE SITUATION (50k lb max). Whilst working the string continue to cycle the torque to stall out and maintain a maximum of 500 psi standpipe pressure. 7. DO NOT ATTEMPT TO FIRE THE JARS IN EITHER DIRECTION.
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8. If circulation cannot be established increase the standpipe pressure in stages up to 1500 psi and continue to work the pipe and apply torque. 9. If the pipe is not free once full circulation is established, commence jarring operations in the opposite direction to the last pipe movement. Once the pipe is free rotate and clean the hole prior to continuing the trip. HANG STRING AT FREE POINT WEIGHT
APPLY RIGHT HAND TORQUE
APPLY LOW PRESSURE TO STRING APPLY LOW UP/DOWN WORKING FORCES TO STRING
CONTINUE WORKING STRING
IS THERE EVIDENCE OF MOVEMENT OR CIRCULATION?
NO
CONTINUE EFFORTS BY GRADUALLY INCREASING PULL & PRESSURE UNTIL FULL CIRCULATION GAINED
INCREASE TORQUE IN STEPS & CONTINUE TO WORK STRING AT SAME LEVEL NO
IS THERE EVIDENCE OF SUCCESS?
CONTINUE EFFORTS BY GRADUALLY INCREASING PULL & PRESSURE UNTIL FULL CIRCULATION ESTABLISHED
YES
YES
INCREASE PUMP PRESSURE & CONTINUE WORKING PIPE
NO
IS THERE EVIDENCE OF SUCCESS?
INCREASE PULL & SET DOWN WEIGHTS
YES
CONTINUE EFFORTS BY GRADUALLY INCREASING PULL & PRESSURE UNTIL FULL CIRCULATION ESTABLISHED
CONTINUE WORKING STRING
CONTINUE EFFORTS UNTIL FREE
NO
IS THERE EVIDENCE OF SUCCESS?
YES
CONTINUE EFFORTS BY GRADUALLY INCREASING PULL & PRESSURE UNTIL FULL CIRCULATION ESTABLISHED
Figure 93: Decision tree showing the first actions when packed-off.
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4.2.2. Differential Sticking 4.2.2.1. First Actions First Actions in the event of Differential Sticking. 1. Establish that Differential Sticking is the mechanism, i.e. stuck after a connection or survey with full unrestricted circulation across a permeable formation (Sand, Dolomite and possibly Limestone). 2. Initially circulate at the maximum allowable rate. This is to attempt to erode the filter cake. 3. Slump the string while holding 50% of make-up torque of surface pipe (unless mixed string of pipe is being used). Use an action similar to what would be used with a bumper sub - see note below. 4. Pick up to just above the up weight and perform step 2 again. 5. Repeat 2. & 3. Increasing to 100% make-up torque until string is freed or until preparations have been made to spot a releasing pill
Freeing Differentially Stuck Pipe Differentially
Yes
Work/ Work Free ?
Stuck
Jar Pipe No
No
Spotting
Select alternate
Is U Tubing
method
Possible?
fluid at rig?
Yes
Yes
Is over balance
Yes
Mix Spot & Spacer
needed for
Prepare U Tube No
Well control/
U Tube
stability
Pump Spot & Spacer U Tube second Time
No
Pipe Free??
Yes
Pipe Free?? Yes No
Cut pipe/Fish/
No
Yes Pipe Free??
Sidetrack/P&A
Cond Mud & Drill Ahead
Figure 94: Decision tree for freeing differentially stuck pipe.
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4.2.2.2. Freeing stuck pipe with pipe release agents Once it is determined that the drill-string is differentially stuck, the annulus should be displaced with a spotting fluid from the bit to the free point. Surveys can determine the free point accurately, but running such surveys often takes a significant amount of time. A pipe-stretch method is a quick way to estimate the depth of the stuck zone. To increase the likelihood of success, the spotting fluid should be applied as soon as possible. Plans should be made to mix and spot a soak solution as soon as possible after differential sticking occurs. Jarring should continue while this is being done. The soak solution to be used depends on several factors. When drilling with waterbased muds, oil-base spotting fluids are preferred. If oil-base fluids present a contamination or disposal problem, alternative environmental spotting fluids must be used. Often, oils, oil-base mud, saturated saltwater, acids or surfactants can be used to spot and free stuck pipe, depending upon the situation. The line of M-I PIPE-LAX® products is specially formulated for this purpose. PIPE-LAX can be mixed with diesel oil, crude oil or kerosene to make unweighted spotting fluids. For weighted muds, PIPE-LAX can be mixed with VERSADRIL® or VERSACLEAN® muds corresponding to the weight of the mud in the hole. Well control must be one of the primary considerations when using pills of different density. Note that the use of pipe release agents involves unique procedures and technical/environmental considerations therefore it is essential that the drilling fluid / acid supplier(s) be involved early in the planning stage. Unlike U-tubing, there are no hydrostatic pressure restrictions on using pipe release agents (PRAs). Any PRA pill should be spotted within 4 hours of sticking for best results. After 16 hours there is little chance of the pill working so the method should not be considered. The graph below (figure 95) shows the probability of the pipe coming free against soaking time in hours. This can be used to calculate the time a pill should be left to soak before circulating out and backing off. As a rule of thumb, soak for a minimum of 20 hours and a maximum of 40 hours.
Figure 95: Shows the probability of the pipe coming free against soaking time in hours.
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Pipe release agents and formulations (Examples are from MI, but other products can be used.) The paragraphs below describe the MI PIPE LAX product range. PIPE-LAX SPOTTING FLUID 1. Determine volume needed. (Annular volume opposite drill collars plus 100 to 150 %). 2. Add 1 gal. of PIPE-LAX per barrel of oil in the spot. Mix thoroughly. 3. Periodically, pump 1-2 bbl of soak solution to collars covered while working pipe. Note: If premixed oil-based or invert oil muds are available and mud weight is needed PIPE-LAX can be added to these carriers and spotted. Advantage of using this type of solution is that the spotting fluid will not migrate while soaking. PIPE-LAX W SPOTTING FLUIDS PIPE-LAX W may be mixed as a weighted spotting fluid. Formulations using mineral oil with either M-I BAR or FER-OX are found in the tables below. These tables are designed to produce the minimum viscosity required to support weight material. Viscosity can be increase if needed by increasing the concentration of PIPE-LAX W from 4.36 to 4.8 gal/bbl. Note: If diesel oil in used decrease the concentration of PIPE-LAX W from 4.36 gal/bbl to 3.5 – 4.0 gal/bbl. Diesel oil provides higher viscosities, therefore, if it is necessary to reduce the viscosity of this solution, dilute with oil and add 0.25 to 0.5 lb/bbl VERSAWET®. Mixing order for PIPE-LAX W is as follows: 1. Mineral Oil 2. PIPE-LAX W 3. Water 4. M-I BAR or FER-OX
Table 24: PIPE-LAX FORMULATION USING MINERAL OIL AND M-I BAR (1 Final Barrel)
166
Table 25: PIPE-LAX FORMULATION USING MINERAL OIL AND FER-OX (1 Final Barrel)
PIPE-LAX ENV SPOTTING FLUIDS PIPE-LAX ENV spotting fluid is a low-toxic, non-petroleum solution for use in areas where oil or oil-base fluids are not permitted. It is a premixed solution, and needs to be weighted to the desired density. The solution should not be contaminated with water or mud, as it will result in excessive viscosity. Note: Water and/or mud contamination causes a significant increase in viscosity in PIPE-LAX ENV; therefore, ensure that all mixing pump and mud lines are drained the then filled with PIPE-LAX ENV prior to weighting up. Densities above 15.0 lb/gal (1.8 SG) require the addition of LUBE 167 prior to weighting up to reduce final viscosity (see mixing table below).
Table 26: PIPE-LAX ENV / Weighting Material Formulations (1 Final Barrel)
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Table 27 *Suggested dilution concentrations with LUBE 167 prior to weighting up are as follows:
4.2.2.3. Spotting HCl acid to free stuck pipe in carbonate Spot 20 – 50 bbl of 15% HCl acid around the suspected stuck area. It is suggested that downward weight be applied just prior to the HCl leaving the drill pipe. This will give you an indication as to when the pipe is free. Use enough HCl to allow for a second soaking if needed. A 10-bbl to 30-bbl spacer (water or diesel) should be used in front and behind the HCl acid solution. Note: Due to possible corrosion of the drill pipe an appropriate acid inhibitor should be used if this procedure is attempted. After the pipe is freed the HCl solution may be displaced, it can be incorporated into mud if the HCl has been completely depleted and the pH can then be adjusted. If the HCl is not depleted it is suggested that the solution be disposed of if possible and the pH adjusted as quickly as possible to reduce contamination. Adjust the pH with lime, or caustic soda. Precautions when using HCl acid: 1. Dilute concentrated HCl by adding the HCl to water. NEVER ADD WATER TO ACID! 2. Circulate HCl solution out through the choke at a slow pump rate, since CO2 gas may be present after the acid has reacted with the carbonate formations. 3. Use proper safety equipment when handling HCl. 4. Maintain enough caustic soda and lime on location to neutralize the solution when it is circulated out of the hole. 4.2.2.4. The U-Tube Method – to be used only after an exemption has been obtained. Another method is to reduce the height of the mud column in the annulus to below the bell nipple. This procedure is referred to as the “U-Tube Technique.” In this procedure, mud is displaced from the annulus by pumping a light fluid (such as diesel oil, water or nitrogen) down the drill string. After pumping the required volume of low-density fluid, the pressure (and some liquid) is bled off the standpipe. The heavier mud in the annulus is then allowed to “U-Tube” back into the drill string, resulting in a reduction in the height of the mud in the annulus. Caution should always be exercised when reducing the differential pressure. In this case, precise calculations should be made to determine the volume of light fluid to pump before allowing the annulus to U-Tube. This procedure should not be attempted with a small-nozzle bit in the hole due to the possibility of plugging the bit.
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Special considerations − − − − − − −
Factors that should be considered before employing this technique include The amount of open hole and likely effects of sharp reduction in hydrostatic pressure on stability of all exposed formations. Is there geological closure at the depth of the permeable formations? Is it likely to contain gas or oil? Are there any other permeable zones exposed? What effect will the reduction in mud have on them? How much confidence is there in the accuracy of formation pressure estimates The true vertical height of the permeable zone and the drawdown imposed on the top of the interval when the bottom is balanced. This could be considerable and result in a seriously underbalanced formation. Well control implications – HARC & Exemption will be required.
Procedure Below is a U Tube freeing technique for differential sticking mechanism. (Procedure assumes no float valve is installed). 1. Calculations. a. Calculate the heads of base oil or water and mud which when combined, balance the formation pressure at the bottom of the permeable zone b. Calculate volume in the choke line and drill pipe/casing annulus to give the head of base oil or water calculated in Step 1 c. Calculate the head(s) of mud that balances the formation pressure at the bottom of the permeable zone d. Calculate the volume of air in the drill pipe above the mud head after Utubing e. Calculate the total volume of base oil or water required i.e. the sum of volumes from step 2 and step 4 f. Calculate the maximum draw down that will be imposed on any other permeable formation (i.e. the uppermost permeable zone) after U tubing (See Appendix) g. Calculate the backpressure held on the choke after displacing base oil or water to the annulus. 2. Close the annular preventer (with minimum closing pressure) and reverse circulate (with minimum pump pressure) the volume of base oil or water calculated in step 5 down the choke line. Check the backpressure. 3. With down weight, assuming the pipe is off bottom, and right hand torque applied, vent the drill pipe above a full opening valve. Bleed of the backpressure rapidly through the choke, allowing the mud level in the drill string to fall. Monitor drill pipe to determine whether it is “sucking or blowing”. Monitor the weight indicator and rotary torque for signs of release and attempt to work downwards and achieve rotation. 4. If the pipe is freed, continuously move and fill the drill string with mud. Circulate out the base oil or water from the annulus and continue to circulate bottoms up (through the choke if there is a chance of gas being produced).
169
5. If the pipe remains stuck (note that release might not be instantaneous – draw down should be applied for at least 2 hours before the attempt is considered to have failed) the mud should be reconditioned and one more attempt made with a bigger reduction in hydrostatic – say to 50psi below formation pressure. 6. If this second attempt fails it is suggested that the pipe is severed immediately above the stuck point and the well sidetracked. The decision to abandon or continue fishing attempts will be dependent on fishing economics evaluation. For more information on drilling high over balance depleted zones see MI’s best practices document MI00724.
4.2.3. Mechanical & Well Bore Geometry Guidelines for freeing stuck pipe other than Pack-offs and differential sticking. 1. Ensure circulation is maintained. 2. If the string became stuck while moving up, (apply torque) jar down. 3. If the string became stuck while moving down, do not apply torque and Jar up. 4. Jarring operations should start with light loading (50k lbs) and then systematically increased to maximum load over a one-hour period. Stop or reduce circulation when: a) cocking the jars to fire up and b) jarring down. Pump pressure will increase jar blow when jarring up, so full circulation is beneficial. 5. If jarring is unsuccessful consider acid pills, if conditions permit.
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4.3. Jars & Accelerators 4.3.1. Jars There are two basic types of jar, mechanical and hydraulic. Hydraulic jars use a hydraulic fluid to delay the firing of the jar until the driller can apply the appropriate load to the string to give a high impact. The time delay is provided by hydraulic fluid being forced through a small port or series of jets. Hydraulic jar firing delay is dependent upon the combination of load and time. Mechanical jars have a preset load that causes the jar to trip. They are thus sensitive to load and not to time. It can be seen from these descriptions that the terms mechanical and hydraulic jar refers to the method of tripping the jar. 4.3.1.1. General Comments on the Successful Use of Jars. Jars are frequently returned to the workshops marked ‘failed’ and subsequently test successfully. The main reason for this appears to be the inability to fire the jars, often in the down direction. Estimating the force required to fire jars, when the user is under pressure due to the stuck pipe situation, is not always performed correctly. This chapter gives some insight into how jars operate and how to choose the correct surface forces to fire the jars. There are a number of reasons a jar might fail to fire: − − − − − − − − − −
Incorrect weight applied to fire jar - one or more assumptions in calculation incorrect. Pump open force exceeds compression force at jar (no down jar action). Stuck above the jar. Jar mechanism failed. Jar not cocked. Drag too high to allow sufficient force to be applied at the jar to fire it (usually mechanical jars). Well path is such that compression cannot be applied to the jar (no down jar action). Jar is firing but cannot be felt at surface. Right hand torque is trapped in torque setable mechanical jars. Not waiting long enough for the jar to fire.
Correct use of jars and the correct application of jarring is critical to freeing stuck pipe. Applying the most appropriate jarring action is key to aiding or worsening the stuck situation. If while pulling out of the hole, the string becomes stuck the natural instinct of a driller is to jar up. This is, after all, the direction he is trying to move his BHA, i.e. out of the hole. However, if the string is packed off above a stabiliser, a likely cause of stuck pipe while pulling out of the hole, the act of jarring up may make the situation worse by compacting the pack-off. Jarring should start in the opposite direction to that which got the string stuck Another reason for the frequent inability to fire jars is the miscalculation of the forces required at surface in order to get the jar to fire. Although the calculations are relatively uncomplicated, in the heat of the problem on the drill floor small
171
calculations can appear quite complex. It is often this type of situation that leads to the jars not firing. 4.3.1.2. Forces Required to Fire Jars All jars have a firing force envelope for each direction they fire in. A dual acting jar (one that can fire up and down) will have both an up jar force envelope and a down jar force envelope. The firing force envelope consists of two forces, one to cock the jar in preparation for firing, the second to fire the jar. A dual acting jar will therefore have two force envelopes, one for up jarring and one for down jarring. The jar envelope forces can be considered at the jar or at the surface. The jar firing force envelope at the jar is known. Jar Firing Force Envelope It is the job of the rig team to estimate / observe the surface instruments in order to choose the surface firing force envelopes. The forces that must be applied to the jar to cock and fire it when it is lying on a test bench are described by the jar force envelops i.e. forces at the Jar. In the example above: To cock the jar to fire up, a compression force of approximately 5k lbs is required. This is to overcome internal friction. Once cocked the jar will fire once the force at the jar reaches 90k lbs.
Figure 96: Jarring envelope
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To cock the jar to fire down, a tension of 5k lbs is required to overcome internal friction, once cocked the jar will fire down once 20k lbs compression is reached. The fixed limits of 90k lbs and 20k lbs are typical of mechanical jars. When using a hydraulic jar, it will fire as long as the jar’s internal friction is exceeded. The time taken to fire is inversely proportional to the force applied: the greater the force the shorter the waiting time. We have only considered the forces at the jar so far. The driller only knows the force at surface and must estimate the force at the jars. It is sometimes easy to see from the measured weight indicator when the jars are opening or closing. The measured weight indicator needle will stop moving for a few seconds while the string is still being moved up or down. It is a very good indicator that the axial neutral point is at the jar. It is often observed whilst drilling vertical wells but can be very difficult to observe in highly deviated, extended reach or horizontal wells. If this neutral weight indicator is observed, it is relatively easy to set surface jarring forces. The measured weight at which the neutral point is observed is recorded. The up trip force (mechanical only) is added to this value, together with any up Drag. Note: When stuck, any pull on the string results in an increase in drag over and above the normal up drag. The full amount of overpull applied at surface will not reach the jar. In deviated wells this must be compensated for by additional overpull.
If the pumps are running then the pump open force must also be subtracted from the firing force and added to the set down weight used to cock the jars. Note: The pump open force charts will be found in the manual for the jar being used. A copy of the current pump open force charts for the types of jars covered by this text is included after the description of each jar type.
Similarly the down trip force (mechanical only), the down drag and the pump open force are subtracted from the neutral point reading. If the neutral point at the jars cannot be observed then the calculated neutral weight at the jars must be used. 4.3.1.3. Pump Open Force The jar pump open force (also called jar extension force) is the effect of the difference in surface areas of the jar exposed to pressures on the out side and inside the jar. When a differential pressure exists between the inside of the jar and the outside of the jar it causes a force that opens the jar. Depending on the jar type the force acts on the cross-sectional area of the washpipe, or the washpipe and any floating pressure equalising piston exposed to the internal fluid of the jar. The effect on jarring can be considerable if for example 2000 psi is trapped inside the jar when the string is packed off below the jar. The pump open force chart for each type of jar discussed is included in these guidelines. The pump open force acts to: 173
Assist firing the jar up Assists cocking the jar after firing down Opposes firing the jar down Opposes cocking the jar after firing up As an example we can look at an actual situation that happened recently in the North Sea. Having struggled out of the hole pumping and with indications of pack offs the string finally packed off. Jarring commenced in a downward direction. There was 2000 psi trapped in the string and the pack-off was below the dual acting hydraulic jar. The parameters are shown in the table below:
Figure 97: Jarring example from the North Sea.
As can be seen with 2000 psi trapped in the string a 34 klbs pump open force resulted. Down jarring was attempted six times, each time the measured weight reading of 60k lbs was held for 30 seconds without any indication of the jar firing. Down jarring was aborted and up jarring commenced until the well was sidetracked. The three main problems this team had were: − Trapped pressure inside the string while trying to jar down. − Insufficient weight to allow down jarring (even without the pump open force opposing this action) − Insufficient time allowed for the jar to meter through its stroke.
4.3.2. Accelerator Description The functions of a drilling accelerator can be summarised as follows: − −
To compensate for the lack of stretch in a short string. To compensate for slow contraction of the drill string due to high hole drag.
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− −
Act as a reflector to the shock wave travelling up the string from the jar blow. Intensify the jar blow.
Drilling and fishing accelerators (also called jar intensifiers) are basically the same design. The Drilling equipment has an up-rated spline drive mechanism to enable the tool to withstand 300-500 rotating hours. The accelerator consists of an outer barrel and an inner mandrel. The inner mandrel slides in / out of the outer barrel. The two are connected by an interference fit between a piston chamber on the outer barrel and piston on the inner mandrel. The piston chamber contains a solid or fluid or gas that acts as a spring. When a force is applied to the accelerator the tool opens. The extension is dependent upon the applied force. When the extending force is released, the tool closes under the spring force of the fluid inside the piston chamber. Dual acting accelerators work in similarly with both the up jar and down jar.
4.3.3. Jar and Accelerator Positioning Jar positioning programs do exist but all are configured to position the jars for maximum up jarring effect, which is not always the desired direction for jarring. To make a full analysis of optimum jar position many factors must be taken into account. However, this is not normally done for drilling operations. Usually the jars are run in a position determined by field / personal experience or company policy. There are a number of issues that should be considered when positioning jars in a drill string. − − − − − − −
Likely places for sticking to occur. Most likely jarring direction required. Well bore contact / differential sticking risk. Position of the axial neutral point when drilling with maximum WOB. Depth of hole section. Drag in hole section. Minimum allowable measured weight for plastic buckling when not rotating.
4.3.3.1. Guidelines for Use of Jars in Vertical Wells In vertical wells the jar should be placed such that: 1. They are above the buckling neutral point even when maximum WOB is applied. 2. They are at least two Drill Collars above the jars. 3. They have differential sticking prevention subs fitted, if differential sticking is a risk. 4. No stabilisers should be placed above the jars. 5. Use Accelerators in shallow hole section. (Check that it will be possible to cock and fire the jar before running them)
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4.3.3.2. Guidelines for Use of Jars in Deviated & Horizontal Wells 1. Do not run the jars if they are buckled. (This is easily said, but complicated to work out. Jars should not be run below the buckling neutral point in 45° wells. In horizontal wells the jars can be run in the 90 degree section without much chance of them ever being buckled). The area in the string to avoid placing jars is the pressure area neutral point. This is the point in the string where the tension in the steel is zero and is always above the buckling neutral point. 2. If using two jars or two jars and an accelerator ensure the driller is fully aware of how to use this system. 3. Use jars with differential sticking prevention subs if differential sticking is a risk. 4. It is important to calculate the measured weight readings at which the jar will cock and fire. The drag in the hole may prevent the driller from seeing the jars open and close on his weight indicator gauge. 5. In horizontal well drilling, a common problem is the inability to get sufficient force to a horizontally placed jar to fire it down.
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5. STUCK – POINT OF NO RETURN.
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5.1. Free point Indicator & Backing-off 5.1.1. Free point Indicator Most pipe freeing efforts are dependent upon knowledge of where the pipe is stuck. One method of estimating the depth at which a string is stuck is the Free Point Indicating tool. 5.1.1.1. General Generally, the FPI tool consists of series of strain gauges which have the capability to sense changes in torque and tension. The tool is run through the drillpipe using regular logging cable. If the jars are still operating, minimize the number of stretch and torque readings above the jars to necessary calibration runs only. Attempt to establish the free point using FPI stretch measurements first. Attempting stretch and torque together early is time consuming and could result in trapped torque affecting stretch and torque readings. Once a preliminary free point is established from stretch measurements, verify that torque can be worked down to that point or lower for determination of deepest back-off point. 1. If the drilling jars are not firing, a rough free point depth can be estimated from drill pipe stretch calculations prior to wireline unit arriving on location. This rough depth is of limited value in deviated holes or holes with relatively shallow doglegs. It is accurate to only 200 to 300 ft in deeper holes, but can give useful starting depths for the FPI tool runs. Straight hole stretch values: o 3.5 inches stretch per 1000ft of free 5", 19.5ppf drill pipe with 50k Ibs over pull. o 5.0 inches stretch per 1000ft of free 6 5/8", 27.7 ppf drill pipe with 100k Ibs over pull. 2. If drilling jars are not stuck, fire up and un-cock jars prior to RIH with wireline tools. For remainder of free point determination and back-of, do not go below slack-off weight required to re-cock jar. 3. Run in hole with FPI tool to maximum depth possible within the drill string if the jars are operational or to 500ft below estimated free point from stretch calculations if the jars not operational. Run CCL correlation log to minimum 500ft above the suspected stuck point and correlate BHA/formation depths using a paper BHA model 4. After CCL correlation, begin running FPI stretch tests. Minimize intervals tested if good indication of stuck pipe point is known (e.g. jars firing). Stretch readings should be taken at mid-joint and the same amount of over pull should be taken each time (50k lbs recommended). The initial stretch test reading should be in a section known to be free, for use as baseline reading. 5.1.1.2. Stretch test procedure 1. Ensure pipe is in tension by pulling the up weight plus 10k lbs.
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2. Open the tool anchors. 3. Slack off cable according to Wireline company recommendations, typically 2 inches per 1000ft. 4. Pull 50k lbs tension in 10k lb increments and record percentage free on free point data readings and on pull and torque chart. 5. Repeat stretch test at each point to check that FPI reading is consistent. 6. Return to anchor setting point (up weight plus 10k lbs). 7. Pick up cable slack and close anchors. 8. Slack off to pre-stuck down weight then pick up to pull 10k lbs over up weight in preparation for the next check depth. 9. Move to next FPI point and repeat this sequence until the stuck point is identified. Establishing down to 30% free is sufficient. Once a preliminary free point is determined from stretch, commence torque FPI tests beginning at deepest 100% free stretch interval if believed stuck in drill pipe. Take a reading in the bottom of the drill pipe, the bottom of the HWDP and the top drill collar if a BHA free point indication is observed from stretch test. 5.1.1.3. The torque test procedure. 1. Ensure pipe is in tension by pulling the up weight plus 10k lbs. 2. Open the tool anchors. 3. Slack off cable according to Wireline company recommendations, typically 2 inches per 1000ft. 4. Apply RH torque (0.75 to 1 turn per 1000ft depth) to maximum of 80% of drill pipe make-up torque. Work torque down the string by pulling maximum 50k lbs over up weight and slacking down to the pre-stuck down weight. Current (Amps) to top drive, rotary or line puII on tongs used to hold RH torque will decrease as torque is transferred down the hole. When sustained working of pipe fails to reduce the amperage or the tong line pull, record the percentage free. 5. Release torque slowly, work pipe, and count turns returned to ensure that no trapped torque remains. Failure to work out all the trapped torque will give erratic torque readings subsequently. 6. Return to the FPI tool anchor setting point (up weight plus 10k Ibs). 7. Pick up cable slack and close anchors. 8. Move to next FPI point and repeat this sequence until the stuck point is determined. Establishing down to 50% free is sufficient. Note: If you are unable to work torque down to the stretch free point depth, it is unlikely that a successful back off can be made at that depth. Alternatives such as pipe cutter tool should be considered. Normally, an 80% free reading in both torque and stretch is recommended for best chance of successful back off. −
Upon completion of FPI tool torque measurements, review the BHA component depth vs. Lithology log [Paper BHA Model] to determine the best back-off depth. If possible the back-off point should be selected in an interval, which improves the chance of getting back onto the fish or as deep as possible if an immediate sidetrack option is selected. Potential washed out intervals and under gauge section are the worst back-off points to choose.
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−
Utilize the FPI tool to accurately determine the neutral point weight at proposed back-off depth prior to POH with the FPI tool to apply the required Left Hand torque for the back-off attempt.
5.1.1.4. Pipe Stretch formulas
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5.1.1.5. Allowable Simultaneous Torque and Pull On Drill Pipe.
5.1.2. Backing-off. Once the free point has been established then the next operation is to back off the drill string above the stuck point. Backing off is a tricky operation especially in deviated wells and can be the cause of large amounts of NPT. This section will highlight some of the salient points, but for more details see the Intouch Content ID: 3314294 - Schlumberger SIT Back Off Manual. 5.1.2.1. Basic Procedure Drillpipe or collars can be unscrewed downhole by exploding a charge known as a string-shot (prima-cord folded up inside a piece of tubular plastic) inside a selected tool joint connection, just above the stuck point. A connection should be selected which has been broken during the round trip prior to the pipe becoming stuck. A successful back off depends upon having the following: − −
Zero or slightly positive tension at the joint Sufficient left-hand, or reverse torque at the joint - 50% to 75% of make-up torque is suggested
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−
A sufficiently large explosive charge, accurately located at the joint.
Particular care should always be taken when applying torque or releasing it from the string. Keep the forces involved fully under control and keep men out of the potentially dangerous area. Torque should be worked down the string before the string shot is fired, this may take some time. If the string fails to back off after firing the charge, continue to work the torque down the string before trying another string shot.
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5.2. Fishing Economics The decision to cut our losses and sidetrack should be a purely economic one – unless there are extenuating circumstances e.g. there is a radioactive source in the hole. Unfortunately most engineers find it hard to give up and they continue to attempt to retrieve the situation when it was already lost many days before. After a certain effort has been put into freeing the pipe, the decision has to be made whether to back off or not. There are likely to be four options: -
Continue attempts to free the pipe Back off above the free point and run in with a fishing assembly Back off above the free point, plug and sidetrack Back off above the free point prior to abandoning the well.
The decision to back off and run in with a fishing string will be made if it is considered to offer an increased chance of success. As a general rule if the sticking mechanisms are: Solids induced – packed off, unstable, time dependent formations and Differential Sticking, there is little point in trying to run in with a fishing assembly. Normally, the best option in these cases is to plug back and sidetrack.
5.2.1. Fishing Economic Calculator IPM’s Fishing Economic Calculator (Intouch Content ID: 3318778) is the emotion free way of deciding when to cut your losses. It is based on historical data from the Gulf of Mexico and the North Sea and looks at the reducing probability of retrieving a fish over time. The basic formula is shown below: Economic fishing time = Cost of sidetrack * Probability of fishing success Daily costs while fishing Two output sheets from the calculator are shown below & opposite.
Figure 98: Fishing economics calculator output sheet.
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Figure 99: Fishing economics calculator output sheet. The red line is the optimum fishing time.
The optimum fishing time starts at the moment you get stuck, and includes working the string and/or spotting pills in an attempt to get free. It also includes the time to back off and run in with fishing tools. The common mistake with the calculator is that people start the clock running from when they have backed-off and are ready to run in with fishing tools, and not from the moment they get stuck. Engineers have also challenged the accuracy of the tool especially in cases where an expensive BHA is stuck with high lost in hole charges e.g. Powerdrive with LWD. Typically in these cases the optimum fishing time is around 3 days, which many engineers believe is too low. However, the historical data shows the probability of recovering from a stuck pipe event decreases exponential with time and as such the economical solution is to sidetrack.
5.2.2. Decision trees. Decision trees can be used to evaluate the best economic course of action during fishing operations. They allow the team to define the probability of success or failure and can be tailored to the specific well conditions and stuck pipe mechanism, rather than using the general rules used by the calculator. The most important thing to remember is that the probability of success or failure is an entirely qualitative number when making decisions trees, and this number has a massive impact on the results. It is therefore extremely important to compare the decision tree results with the results from the fishing calculator. Any differences need to be explained and quantified.
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5.2.2.1. Decision Tree Example. The decision trees are from a differential sticking stuck pipe event. RECOVERY: PROB. OF SUCCESS FISHING COST FOR: FISHING = % SUCCES + % FAILURE = 54.1 K + 214.0 K
Risked fishing cost. =
50% 3 Days
108.2 K
268.1 K
STUCK PIPE ACUMM COST
NOT RECOVERY: PROB. OF SUCCESS FISHING COST FOR: = COSTO OF FISHING + SIDETRACK COST = FISHING COST + SIDETRACK COST
22.9 K
50% 3 Days
428.0 K SIDETRACK = COSTO OF FISH + SIDETRACK PLUG AND TIME 319.9 K
CONCLUSION: CONTINUE FISHING
Figure 100: Decision tree to continue fishing for a differential stuck pipe event.
The first branch is the stuck pipe event itself and the accumulated cost. The tree then splits into two branches: fishing and sidetracking. The former has a further two branches: recovery and no recovery. The cost of sidetracking, recovery and no recovery is calculated. The probability of success is estimated and then the risked fishing cost calculated. Risk fishing cost = (cost of recovery x %success) + (cost of no recovery x %success).
This is compared to the cost of sidetracking and if the figure is lower then it is economic to continue fishing. As you can see the success factor has a major influence on the outcome. In this case it was economic to continue fishing. The second decision tree is from the same event, but the fishing operations would take 5 days and the probability of success has been reduced to 10%. In this case best economic course of action is to sidetrack the well.
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RECOVERY: PROB. OF SUCCESS FISHING COST FOR: FISHING = % SUCCES + % FAILURE = 11.6 K + 308.8 K = 320.4 K
STUCK PIPE ACUMM COST
116.3 K
NOT RECOVERY: PROB. OF SUCCESS FISHING COST FOR: = COSTO OF FISHING + SIDETRACK COST = FISHING COST + SIDETRACK COST
69.8 K
10% 5 Days
90% 5 Days
343.1 K SIDETRACK = COSTO OF FISH + SIDETRACK PLUG AND TIME 226.9 K CONCLUSION: SIDE TRACK
Figure 101: Decision tree to continue fishing for a differential stuck pipe event.
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5.3. Sidetracking 5.3.1. General Once the decision has been made to re-drill the section the decision has to be made on the depth of the kick point. This decision will depend on the trajectory, exposure time of formations above the stuck point, and hardness of the formations. It is also extremely important to abandon the original hole section in accordance with IPM standards. This is critical in situations where hydrocarbons or overpressured formations are present. In highly deviated wells the kick-off can be initiated by time drilling with a directional assembly (PDM or rotary steerable). For more information on this subject see Intouch Find: Open hole sidetracks.
5.3.2. Kick-off methods.
Igneous &
Sedimentary
Metamorphic 1
Jetting
4
5
Motor
6
7
8
Whipstock
Figure 102: Kick-off methods by rock type.
Here we can see a table of the primary codes of the IADC Code Chart. Codes 2 & 3 have been omitted, as there is little demand any longer for these products. The codes range from the softest formations on the left (code 1) to the hardest on the right (code 8). Against this scale we can place a line representing the formation hardness most suitable for jetting. These are the formations that are poorly consolidated and can be removed by hydraulic action alone. At the other end of the scale are the hardest of the sedimentary rocks along with the Igneous and Metamorphic rocks that are the hardest to deflect into especially when coming off a cement plug, which is much softer than the formation that we wish to drill into. It is here that the open hole Whipstock is most effective. Overlapping these two deflection methods is the most popular deflection method of all, the Motor combine with a kick-off plug. The thing that makes the motor so popular is its flexibility, though it may be noted that it is not as effective at the extremes as the alternative methods.
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5.3.3. Kick-off plugs 5.3.3.1. Introduction The objective of the kick-off plug is to establish a hard basis to allow the bit to sidetrack from the original well bore. The main problems associated with setting a kick-off plug are: 1. Too soft cement with respect to formation, unable to sidetrack a. Incorrect slurry design. b. Contamination of the cement with mud. c. Unstable base. See figure 104. d. Formations too hard. e. Not weighting the required time for the cement to set (see Table 28) 2. Incorrect cement top a. Poor displacement practices
Soft
Abandon the original hole in accordance with IPM standards. Figure 103: Shows schematic of kick-off and sidetrack.
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Figure 104: Schematic of the stability (left) and instability (right) of a dense cement placed above a lighter fluid.
5.3.3.2. Summary of important guidelines For successfully kicking-off, the cement must be harder to drill than the adjacent formation. Hence: 1. The plug must be placed in a soft formation rather than a harder formation. Consult drilling speed logs to determine the softest formation. This can be combined with UCS data from an offset well. Do not be afraid to kick off higher than planned. 2. The plug top must be as the designed depth: take special care to correctly design cement volume: Calliper log, enough excess volume (50 to 100%) 3. Plan the top cement +/-50m above preferred kick-off point. This will allow for the expected contamination at the top of the plug. 4. The cement length must be sufficient to allow successful kick-off: 150 meters minimum, to account for contamination at plug ends 5. The cement must have a high enough strength: a. Design a high CS slurry, i.e. reduced water or CemCRETE formulation b. Design the minimum safe thickening time, based on good BHCT value. c. Minimize eventual contamination, by proper placement. d. Allow ample time for cement to set (24 hours) Note: The OH section needs to be abandon in accordance with the IPM-WCI Standards 5.3.3.3. Where to place a kick-off plug
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The kick-off plug should NOT be positioned opposite an excessively hard formation. The plug should extend from a soft shale down to a hard formation where the bit can easily be kicked out in a new direction and not drift back into the original hole. Highly permeable zones and thief zones should be avoided to prevent fluid loss (and subsequent changes to the slurry properties) and complete slurry loss, respectively. The logs and drilling rate record should be consulted when selecting the plug interval. The kick-off plug should be long enough to: − − −
Account for mud contamination Provide a gradual deviation of the bit Ensure sufficient distance between the bit and the old hole when the bit has traversed the length of the plug.
5.3.3.4. Slurry volume Typical plug lengths range from 150 to 250m. When possible, utilize an open hole calliper to determine cement volumes. It is recommended to use calliper volume plus 10% to ensure sufficient plug volume. When a calliper is not available, the following guidelines are proposed: Hole size (in)
% Excess (WBM)
% Excess (OBM)
20-24” 17 ½”-14 ¾” 12 ¼” - 10 5/8” 9 7/8” - 6”
100% 50% 30% 30%
20% 15% 10%
Plan for the top of the cement to be 30-50m above the required kick-off point. This will allow for contamination and the top of the plug. 5.3.3.5. Slurries for kickoff plugs. High compressive strength slurries are required for kick-off plugs. A minimum of 3000 to 5000 psi is required, while a 7000 psi compressive strength is recommended, but not always achievable. If 5000psi cannot be achieved then the compressive strength should always be harder than the surrounding formation. Cement compressive strength should be tested at a temperature half way between circulating temperature and estimated bottom hole static. Thickening time should be set for between 1-2 hrs over actual job time. The temperature should be based upon MWD circulating temperature if available. Fluid loss can retard cement and lower overall compressive strength and is not recommended unless cementing in less than an 8 ½” hole across a permeable formation. If BHST is above 230 deg F, then silica is necessary to prevent strength retrogression, which can occur relatively quickly especially at 300 deg F and above
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API Class G Cement Mixed at 15.8 lb/gal Depth 10,000 ft, BHST 228OF, BHCT 180OF Retarder gal/sk
THICKENING TIME (hrs:min)
None
COMPRESSIVE STRENGTH (psi) 8hrs
16hrs
24hrs
1:20
3050
3500
4100
0.04
2:25
2500
3000
3700
0.08
3:40
1200
2200
3600
Table 28: Slurry Thickening Time and Compressive Strength Table for API Class G Cement.
Class H Cement 16.5 lb/gal
Effect of Mud Contamination*
Mud
Compressive Strength
Mud
Normal Slurry
Reduced Water
Contamination
(psi at 170°F)
Contamination
15.6 lb/gal
Slurry** 17.5 lb/gal
(%)
8 hr
16 hr
(%)
(psi)
(psi)
0
4,647
5,862
0
4,082
8,600
5
3,512
5,300
10
2,950
8,237
10
2,619
4,538
40
2,426
3,850
20
2,378
2,331
60
593
2,967
50
245
471
Table 29: Mud Contamination vs. Compressive Strength. * Compressive strength is 18hr at 230F ** Contains dispersant
High-density slurries Dispersants (normally TIC D065 or Liquid TIC D080) allow the water/solids ratio to be reduced while maintaining the slurry pumpable, thereby allowing the slurry to be mixed at densities up to 17.0 lbm/gal using Class A or C cements and 18.0 lbm/gal using Class G or Class H cements. Compared to standard-weight systems, reduced water slurries exhibit higher compressive strength and improved set-cement properties. The higher compressive-strength development is achieved at low temperatures in a shorter time period and can reduce WOC times. Reducing the water/solids ratio lowers the water loss and results in a set cement that is more dense, has less permeability, exhibits less shrinkage and has more resistance to contamination by well fluids.
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CemCRETE slurries. CemCRETE technology allows the design of lightweight slurries, which will develop very high compressive strength in a short period of time. The main advantage of these systems is that the interface between the lightweight CemCRETE slurry and the mud is much more stable because the density differential between the two fluids is significantly reduced. Such systems are much less prone to contamination and will not tend to channel through the viscous pill or the mud. 5.3.3.6. Viscous Pills To act as a solid base for the cement a 300 ft long Hi-Vis pill (or a viscous reactive pill) should be placed just below the cement plug setting depth. The viscous reactive pill is favoured when the hole angle is between 20 to 70 degrees, the critical angle for cement slump and the main cause of failure. Viscous pills rarely have a sufficiently high yield point to stop cement sinking through. This adverse condition can be minimised by keeping the density of the slurry no higher than 2 ppg above that of the viscous pill. Standard Viscous Pill (Hi-Vis Pill) A minimum volume equal to 300 ft in the open hole section is required. Water Based Mud (including Silicate Based Mud): To avoid contact with retarders, which could contaminate the cement and prevent it from setting, the viscous pill should be made up fresh in the pill pit using a simple gel slurry at 25 to 50 ppb. The pill should be as thick as possible, with a yield point of at least 70 lb/100 ft^2 at 120 °F. The density should be 45 pptf above the mud weight in use. Oil/Synthetic Based Mud: Transfer active mud to a pill pit and viscosify with organophylic clay (e.g. TRUVIS, CARBO-GEL) at 2-2.5 ppb to obtain a yield point of at least 70 lb/100 ft^2 at 120 °F. Increase the density by 45 pptf above mud weight in use. Note: Achievement of increased YP at surface may require prolonged shear. Note: Composition, density, rheology and volume of Viscous Pill must be stated on drilling and CC service report. Reactive Viscous Pill Clean out the slug pit and drain the lines. Ensure that the mix water and any fluid remaining in the lines have a calcium level below 400 ppm with chlorides below 2000 ppm. Treat the mix water (drill water) with 0.37 ppb soda ash (ppm calcium x 0.00093) to remove the hardness and adjust the pH to 9 by the addition of 0.5 ppb caustic soda. Prehydrate the bentonite (20-30 ppb) for at least an hour prior to the addition of D75 (5gal/bbl). If the bentonite fails to yield the drill water is likely to be contaminated. After D75 is added, the density should be raised to 45 pptf above the mud weight. Properties can be adjusted by the addition of bentonite or fresh water, with D75 added to maintain concentration. A 20 bbl pill is required for 12 1/4” holes and smaller. For larger hole sizes use 50 bbl. In hole sizes of 12 1/4” or less, a 20 bbl spacer ahead of the reactive pill is sufficient, with sufficient spacer behind to balance.
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5.3.3.7. Equipment. Utilize a 2 7/8” or 3 ½” cement stinger for all hole sizes 17 ½” or smaller. The 2 7/8” is recommended in most cases except for higher angles wells where the hole size is 12 ¼” or bigger, where 3 ½” is recommended. It is also recommended to use a stinger 1.5 times the expected plug length. The stinger should be blanked off at the bottom and slots cut in the sides of the bottom joint. Plug placement using open-ended pipe results in considerable disturbance to the fluids interface by the slurry changing its flow direction and is a major contributor to plug failure. Plug placement using a flow diverter tool at the end of the pipe minimizes this disturbance effect because the flow pattern of the pumped fluids exiting the pipe is a lateral and upward movement.
8 holes phased at 450 Bull Plug Figure 105: Schematic of plug diverter tool.
An alternative to the steel cement stinger, and one that is becoming more common is fiberglass tubing. The main difference between the two is that the fiberglass tubing is disconnected from the DP after the cement has been displaced and left to set in the cement. This avoids mud contamination when the stinger is pulled through the cement. 5.3.3.8. Plug Setting Guidelines. 1. Ensure the pit (for mixing the spacer) and the batch tank are thoroughly cleaned out and all the lines are flushed. Check the chloride content of the fresh water to be <1000 ppm. 2. Make up the pre-flush (wash and/or spacer) in mud pits as per recipe. 3. Prepare the cement mix water in the batch tank. Add the cementing chemicals to the batch tank as per the slurry recipe. Add the chemicals in the order they appear in the recipe. Add the retarder last just before batch
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mixing the slurry. Take samples of the mix water, at least one gal, so that tests can be carried out if problems occur. 4. Circulate at least bottoms up until the well fluid is balanced. Reciprocate and rotate the pipe while circulating if possible. 5. Hold pre job meeting to discuss job procedures and safety aspects. 6. Flush lines with water and pressure test surface lines to 3000 psi for 5 min. 7. Batch mix the slurry as per the slurry recipe. Switch off the circulating pump when the correct density is reached to avoid the possibility of over shearing the slurry and thereby shortening the thickening time. Take two samples of the cement slurry. 8. Pump ____ bbl of Pre-flush (Wash and/or Spacer) (from mud pit) with the cement unit at ____ bpm. 9. Pump ____ bbl of cement slurry from the batch tank with the cement unit at ___ bpm. (Volume depending on depth/length of plug) 10. Pump _____ bbl of spacer behind to balance the cement plug with the cement unit at ____ bpm. 11. Displace with mud with the cement unit to ensure the displacement volumes are accurate. Under displace by volume given in the table below.
Table 30: Under-displacement volumes for different DP sizes.
12. Pull out of plug as slowly as practical and do not rotate while pipe is in the plug, place stinger at 50 ft above top of cement. Watch for indicators such as drag or sticking while on the slips. Pulling too quickly and/or rotation will destabilize and/or contaminate the plug. 13. Drop drill pipe wiper dart (if run) and circulate the well clean (150% annulus volume minimum). As a general rule, it is NOT recommended to reverse out on top of the cement plug. The risks of losing returns, plugging off and contaminating the cement plug are thought to outweigh the time advantage that it affords. 5.3.3.9. Evaluation
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The success of kick-off plugs is evaluated by actually trying to kick-off: there is no way to question the validity of this test! If the kick-off plug is also acting as an isolation plug then it needs to be tested in accordance with IPM WCI – 006 Setting and Verification of cement plugs. 5.3.3.10. Additional Material Intouch has a dedicated cement plug reference page. Intouch Content ID: 3318658 - Cement Plug Reference Page
5.3.4. Kicking-off with a motor. Motors are the predominate method of kicking off a well for the following reasons: − − − − −
Plentiful Supply, usually already on location Cost effective for most applications Tenacious Able to meet objectives after the Kick-off is completed Highly flexible in controlling DLS.
When the success of a sidetrack is not a foregone conclusion (most cases) you must be aware of: 1. The Sidetrack is the objective of the current operation. Bit selection should be for the short term and not long term e.g. to kick-off from the cement plug. 2. Discuss the operation with the DD and the office. 3. Commitment to success. The Time drilling program. Be patient. Give the DD the time to kick-off successfully. The cost of setting a new plug is higher than drilling slower The likely outcome of our actions. Discuss all outcomes with the DD. The factors that have limited our success previously. 4. The contingency plan. 5.3.4.1. OH Whipstock. Whip stocks are highly effective tools designed to provide lateral displacement from the well bore. They do not give very large changes in dogleg but due to the fact that what is provided is done in a very small change in MD. They generate high DLS values. Though whip stocks are a niche market tool their range and diversity is on the increase. They are normally run in the following cases: 1. When hard formations are present and the soft formations suitable for sidetracking in are too shallow. 2. Where exact depth control is required. 3. No requirement to abandon to original hole
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Whipstock face.
New hole section.
Original hole section. Whipstock anchored with ECP. Figure 106: Shows schematic representation of OH whipstock.
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5.4. Reporting It is important to investigate stuck pipe incidents, especially catastrophic events. The investigation must get to the root cause of the problem and the lessons learnt must be distributed within the well engineering community. An example of the format of a typical stuck pipe report is detailed below. STUCK PIPE INCIDENT REPORT Reporting Guidelines Drilling Unit: Type of Rig: Drilling Contractor: Well name: Well Type: Directional profile: Well total depth: Hole drilled: Spud date: Dry hole days Exp/App wells: Dev wells:
state name of rig state semi, jack-up, drill ship, land. state name DOE well number after spud state EXP, APP, DEV, Re entry, Sidetrack Vertical, Directional with max angle, S Shape, Horizontal. state depth in metres Total length of hole drilled start of drilling Spud to start of anchor handling or start of rig down less time for testing E/A wells Spud to last operation prior to running production casing/liner or pre-wipe trip.
Test/comp days Exp/App wells: Dev wells: Well completion date:
From running production casing/liner or pre casing wiper trip to final lay down of test tools. From running production casing/liner or pre casing wiper trip, to suspend prior to skid. Record date well operations completed i.e. rig release.
Sticking incident Date/time: Depth: Hole size: Hole Angle: Mud weight: Overbalance: Mud type:
Record details. Depth stuck in metres or feet. Record details. Record details where stuck. Weight in SG or ppg of mud in hole at time of sticking. Record overbalance in psi. State mud systems in use in hole.
Full Details of Incident and Action Taken Complete detailed summary of events and actions taken throughout including recording the following points where relevant: − Time string free after becoming stuck 197
− − − − −
Amount of over pull to free If pill pumped, type volume, density, spacers, displacement rate and time after pipe stuck etc., Time attempts to free were aborted i.e. sidetrack start time Fish left in hole Amount of hole lost.
Interpretation of Cause and Lessons Learnt This should be completed following a review of what happened to identify the mechanism and cause of the incident i.e. Mechanism: Differential sticking, Cause: BHA poor design, mud weight too high, etc. Consider any human factors relating to the time of the incident i.e. Crew change, New Rep etc. In addition the actions taken following the incident should be reviewed to establish what other problems occurred if any and state lessons learnt to be applied to future wells. Planned Action / Recommendation Consider what action needs to be taken to improve awareness and avoid such an occurrence i.e. Incorporate within stuck pipe course/workshops, review of BHA design needed, more training in specific areas. Lost Time State lost time in total to recommence operations from where stuck pipe incident occurred. This will include all time associated in performing a sidetrack and redrilling relevant hole section to original depth. Record time spent to free pipe or until attempts aborted i.e. where decision taken to sidetrack. Cost Record:
Total cost in US dollars Total cost of fish in US dollars
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6. Acknowledgements IPM Philip Church
Author
Gokhan Yarim Alejandro Trejo Graham Ritchie
Reviewer Reviewer Reviewer
D&M Tony Pink Maximo Herdandez
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7. Appendix
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7.1. Unconsolidated Formations
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7.2. Mobile Formations
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7.3. Faulted & Fractured Formations
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7.4. Naturally over pressured shale collapse
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7.5. Appendix 4: Induced Over-pressured shale collapse.
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7.6. Reactive Formations
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7.7. Hole Cleaning
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7.8. Tectonically Stressed Formations
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7.9. Differential Sticking
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7.10. Key Seating
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7.11. Undergauge Hole
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7.12.Doglegs & Ledges
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7.13.Junk
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7.14.Cement Blocks
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7.15.Green Cement
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7.16.Stuck Pipe HARC Analysis.
Comment: Comment: Taking into account all Contributing and Escalating Factors, describe all Controls applicable to each Hazard, both Prevention and Mitigation Controls. If PPE is a Control, it must be described.
Hazard Analysis and Risk Control Record Revision:
Final – Rev 001
Task/Process Assessed: Stuck Pipe – Drilling/Workover/Intervention
Date:
13 Oct 2003
Location:
All IPM managed projects
Assessment Team:
Ritchie/Struthers/McEwan/Bourque/Cuvillier/
Population Affected
Non productive time, operating cost, lost in hole charges, cost of redrill and cost of deferred Stuck pipe leading to fishing production on operations and/or sidetracks development wells. to redrill hole
Risk Level
Loss Category/
Intolerable (-12)
Possible (3)
Natural Phenomenon, Gravitational Potential Energy (mechanical sticking) & Pressure (Differential sticking)
Catastrophic (-4)
Drilling/ Tripping
INITIAL RISK
Severity
HAZARD Hazard Description and Worst Case Consequences with no Prevention or Mitigation Measures in Activity Steps Place
Likelihood
Operation:
Comment: Choose the Loss Categories from the HARC – Risk Toolbar
CONTROL MEASURES
Comment: From instructions in App 4, identify Likelihood of an undesired event with no Prevention Controls in place for each Hazard. Use the HARC – Risk Toolbar to insert the Likelihood.
List all Current and Planned Control Measures, ta Contributing and Escalating Fact Current and Planned Prevention Measures to reduce Likelihood • Identify stuck pipe incidents in offset well analysis • Consider potential for stuck pipe in well design and directional planning e.g. inclination of tangent section for hole cleaning, casing seat selection, etc. • Minimize open hole exposure time (WBS) • Consider geomechanics study & “No Drilling Surprise” services • Consider Perform engineers for critical wells • Run RPM to identify specific risks • Consider rig suitability for well design • Highlight risk at pre-spud meeting and hole section reviews • Highlight stuck pipe risks in the Drilling program
Current an Measure • • • • • • • • •
Comment: From instructions in App 4, identify Likelihood of an undesired event with all current and planned Controls in place for each Hazard. Use the HARC – Risk Toolbar to insert the Likelihood.
Consider L BHA (e.g. Consider L Ensure fis all tools R Confirm fis Ensure fis down hole Design dri adequate Run jar pla the jar pos Have stuc available f Consider e stuck pipe
Comment: Classify the Initial Risk Level from the OFS Risk Assessment ... [1] Comment: Classify the Residual Risk Level from the OFS Risk ... [2] Comment: From instructions in App 4, identify potential Severity of an... [3] Comment: From instructions in App 4, identify potential Severity with ... all[4] Comment: Comment: Separate the job into individual tasks, or the process into ... [5] Comment: Choose the Hazard Categories from the HARC – Risk ... [6] Comment: If Personnel: Name all types of personnel at risk. Remember ... [7]
216
Intolerable (-12)
Possible (3)
(continued)
Non productive time, operating cost, lost in hole charges, cost of redrill and cost of deferred Stuck pipe leading to fishing production on operations and/or sidetracks development wells. to redrill hole Natural Phenomenon, Gravitational Potential Energy (mechanical sticking) & Pressure (Differential sticking)
Catastrophic (-4)
Drilling/ Tripping
• Design mud program to minimize the risk (optimize overbalance, minimize fluid loss, consider adding CACO3 for permeable sections) • Run Drilling Office hydraulics & hole cleaning while drilling to determine minimum flow rates and ECD • Implement engineered hole cleaning practices to avoid “pack offs” • Highlight risk of cuttings beds (45 – 70 deg) and include procedures for dealing with cuttings beds • Perform torque & drag analysis to assess the impact of the drillstring selection and BHA design on sticking potential. • Conduct stuck pipe training with the rig team • Ensure rig team have access to the Stuck Pipe handbook • Consider using a top drive, spiral drill collars, rotary steerable, bi-center bits. • Issue drilling procedures and written instructions to the driller (e.g. max overpull on trips) • Keep pipe moving while across porous/permeable formations • Monitor trends (drag, reaming) • Implement drag charts for tripping • Implement Trip charts highlighting tight hole • Ensure stuck pipe risks highlighted in Driller’s handover • Assess Driller competency in stuck pipe avoidance
• • • • • • •
Have back available Plan conti radioactive If stuck, ru sticking m Evaluate r pipe hand Run IPM f spreadshe fishing tim Implemen corrosion environme If stuck, co experience
Note: These m Industry pract ALARP
217
Comment:
Hazard Analysis and Risk Control Record Revision:
Final – Rev 001
Task/Process Assessed: Stuck Pipe – Drilling/Workover/Intervention
Date:
13 Oct 2003
Location:
All IPM managed projects
Operation:
Running Casing.
Assessment Team:
Ritchie/Struthers/McEwan/Bourque/Cuvillier/
Stuck casing potentially leading to additional casing string or redrill of section
List all Current and Planned Control Measures, ta Contributing and Escalating Fact
Risk Level
Severity
Comment: Choose the Loss Categories from the HARC – Risk Toolbar
CONTROL MEASURES
Current and Planned Prevention Measures to reduce Likelihood • •
Non productive time, operating cost, lost in hole charges, cost of redrill and cost of deferred production on development wells.
• • • Intolerable (-12)
Natural Phenomenon, Gravitational Potential Energy (mechanical sticking) & Pressure (Differential sticking)
Population Affected
Possible (3)
Running Casing
Loss Category/
Catastrophic (-4)
Hazard Description and Worst Case Consequences with no Prevention or Mitigation Measures in Activity Steps Place
INITIAL RISK
Likelihood
HAZARD
Comment: Taking into account all Contributing and Escalating Factors, describe all Controls applicable to each Hazard, both Prevention and Mitigation Controls. If PPE is a Control, it must be described.
• • • • • •
Limit maximum dog leg severity Design casings (including landing strings) to maintain adequate overpull Ensure sufficient clearance with previous casing and open hole Consider bi-center bits, special clearance couplings Run casing centralization software to determine maximum drag Ensure adequate centralization across potential differential sticking zones Consider running reaming shoe and being able to rotate casing in the event of bridges Consider using casing fill up tool to minimize stationary time and allow casing to be washed to bottom Ensure hole and mud in good condition prior to running casing Implement drag charts for running casing Keep pipe moving while across porous/permeable formations !
Comment: From instructions in App 4, identify Likelihood of an undesired event with no Prevention Controls in place for each Hazard. Use the HARC – Risk Toolbar to insert the Likelihood.
Current an Measure
Comment: From instructions in App 4, identify Likelihood of an undesired event with all current and planned Controls in place for each Hazard. Use the HARC – Risk Toolbar to insert the Likelihood.
Applicable meas • Casing pa hanger • Run expan extension • Consider c well desig
Comment: Classify the Initial Risk Level from the OFS Risk Assessment ... [8] Comment: Classify the Residual Risk Level from the OFS Risk ... [9] Comment: From instructions in App 4, identify potential Severity of an ... [10] Comment: From instructions in App 4, identify potential Severity with ...all [11] Comment: Comment: Separate the job into individual tasks, or the process ... into [12] Comment: Choose the Hazard Categories from the HARC – Risk ... [13] Comment: If Personnel: Name all types of personnel at risk. Remember ... [14]
218
7.17.PowerPak Motors with Adjustable Bends Drill String RPM’s: Curve
219
7.18.PowerPak Motors with Adjustable Bends Drill String RPM’s: Tange
220
Page 216: [1] Comment Note Classify the Initial Risk Level from the OFS Risk Assessment Matrix for each Hazard. Use the HARC – Risk Toolbar to insert the Initial Risk Rating. Page 216: [2] Comment Note Classify the Residual Risk Level from the OFS Risk Assessment Matrix for each Hazard. Use the HARC – Risk Toolbar to insert the Residual Risk Level. Page 216: [3] Comment Note From instructions in App 4, identify potential Severity of an undesired event with no Controls in place for each Hazard. Use the HARC – Risk Toolbar to insert the potential Severity. Page 216: [4] Comment Note From instructions in App 4, identify potential Severity with all current and planned controls in place for each Hazard. Use the HARC – Risk Toolbar to insert the potential Severity. Page 216: [5] Comment Note Separate the job into individual tasks, or the process into phases, and record in sequence. Page 216: [6] Comment Note Choose the Hazard Categories from the HARC – Risk Toolbar — Describe all Hazards identified and their effects for each task (from Hazard Catalogue in App 2 and experience). Page 216: [7] Comment
Note
If Personnel: Name all types of personnel at risk. Remember to include people outside the work party who may be affected. Page 218: [8] Comment Note Classify the Initial Risk Level from the OFS Risk Assessment Matrix for each Hazard. Use the HARC – Risk Toolbar to insert the Initial Risk Rating. Page 218: [9] Comment Note Classify the Residual Risk Level from the OFS Risk Assessment Matrix for each Hazard. Use the HARC – Risk Toolbar to insert the Residual Risk Level. Page 218: [10] Comment Note From instructions in App 4, identify potential Severity of an undesired event with no Controls in place for each Hazard. Use the HARC – Risk Toolbar to insert the potential Severity. Page 218: [11] Comment Note From instructions in App 4, identify potential Severity with all current and planned controls in place for each Hazard. Use the HARC – Risk Toolbar to insert the potential Severity. Page 218: [12] Comment Note Separate the job into individual tasks, or the process into phases, and record in sequence. Page 218: [13] Comment Note Choose the Hazard Categories from the HARC – Risk Toolbar — Describe all Hazards identified and their effects for each task (from Hazard Catalogue in App 2 and experience). Page 218: [14] Comment
Note
If Personnel: Name all types of personnel at risk. Remember to include people outside the work party who may be affected.
