Drillstring Design
To use a torque and drag program for drillstring design, the following information is required by most programs:
• A survey file containing depth, inclination, and azimuth
- BHA and drillstring ODs, weights per foot, and lengths for each unique section
- Weight on bit, torque at bit, mud weight, friction coefficient, and calculation interval (may not be an option)
The output shows calculations for pickup hookload (tripping out), slackoff hookload (tripping in), rotating off bottom hookload and torque, and drilling hookload and torque. Some programs may also include a calculation for sliding hookload and torque, as well as for reaming and backreaming hookload/torque. Many programs use an effective OD for the drillpipe which accounts for the effects of tool joints on the torque calculation.
Two approaches to the problem of drillstring design can determine what grades, sizes, and quantities of drillpipe are used for drilling the well.
HOOKLOAD AND MARGIN (lbs)
-50000 0 50000 100000 150000
HOOKLOAD AND MARGIN (lbs)
-50000 0 50000 100000 150000
- HOOKLOAD AND MARGIN (kN) Figure 12 Typical Hookload Plot from Torque & Drag
One method is to determine what is available in the drilling contractor's current inventory. These components are used in the appropriate intervals, and any additional requirements are met with rental pipe as needed. The second approach is to do the drillstring design first. Determine what the pipe requirements are, and then select a drilling contractor based on their ability to provide the required drillpipe, rig, and equipment to meet hookload and torque requirements.
The first step in the design is to calculate the torque and drag for the deepest bit run. A drillstring should be used consisting of the BHA followed by drillpipe all the way back to the surface. Experience has shown that the worst case for torque and drag is usually at TD. However, checks should also be made for shallower casing points. The oriented drilling mode (sliding) will create the highest compressive forces, so this is analyzed first. The string is designed from the bottom up since the friction is cumulative from the bottom up.
The output will show the total cumulative axial load at specified increments from the bit back to the surface. At the bit, these compressive forces will be equal to the desired weight on bit, and will increase to a maximum (negative) at some point in the curve section. These forces will then decrease back to zero at the neutral point and increase positively to the surface. The location of the neutral point is a function of the well profile. For long radius wells with a tangent, it will usually occur in the tangent. For medium radius wells, it will usually occur somewhere in the vertical portion of the well (above the kickoff point).
The critical buckling load is calculated for drillpipe in the proper hole size and with the appropriate mud weight*. Starting at the bit, the compressive forces from the torque and drag output are compared to the critical buckling force for the appropriate inclination until the critical buckling force is exceeded. This defines the depth where heavier drillpipe is used (usually heavyweight). This depth is then increased by the anticipated length of the bit run. This insures that the heavier pipe is in this interval at the beginning of the run as well as at the end.
The next step is to replace the drillpipe from this critical depth (adjusted for bit run length) to the surface with heavyweight drillpipe. This is done to determine in one step how far up the heavyweight must be run. The program is rerun, and the output is inspected to determine the location of the new neutral point. Since the heavyweight contributes significantly to the overall string weight, the neutral point will move down the string.
To be conservative for critical buckling load, use the heaviest mud weight. For the purposes of torque and drag, use the lightest expected mud weight.
COMPRESSION TENSION INCLINATION
Figure 13 Compression
COMPRESSION TENSION INCLINATION
Figure 13 Compression
The final step in this initial phase of design is to replace the heavyweight with drillpipe from the neutral point to the surface and rerun the program. This will leave the neutral point unchanged but reduce the total hookload at the surface. At this point, the designer must consider whether to replace some of the heavyweight with drill collars in the vertical section of the hole. This may be necessary if the amount of heavyweight available on the rig is insufficient. The contractor may be hesitant to rent more if he has drill collars available. This will cost him nothing to use and can typically provide the same weight in roughly half the number of joints. However, proper consideration must then be given to the impact this will have on hydraulics. Care must also be taken to prevent the drill collars from entering the curve section during the bit run, due to the high bending stresses.
TENSION INCLINATION
Figure 14 Tension
Once the string is designed for buckling avoidance in the sliding mode, the other cases of pickup, slackoff, and drilling are checked for:
- Tension margin. The calculated total pickup hookload is increased by 100,000 lbs (or 50,000 lbs if modeling stuck pipe with 50,000 lbs tension at the bit). This new value must not exceed the tensile strength for the particular grade and class of pipe used (API RP7G) to ensure adequate tension capability. If the adjusted value of hookload exceeds the tensile strength, determine the depth at which the limit is exceeded. Replace the drillpipe from that point to the surface with a higher grade/class or larger size of drillpipe; or reconsider the well profile plan.
- Torque margin. The drilling torque must not exceed 80% of the make-up torque anywhere in the string for the connections at that depth (API RP7G).
- Slackoff hookload. The slackoff hookload must be a positive value to allow sufficient weight to get to bottom. A specific value greater than zero
- e.g., 50,000 lbs) may be required by some oil companies. The weight of the travelling assembly can be used to push the pipe down if necessary.
- A maximum allowable weight on bit must be specified for rotary drilling to ensure the drillstring is not buckled while rotating.
As mentioned above, consideration must be given to the length of the bit run. The location of the heavyweight drillpipe in the well must be monitored and predetermines the length of the bit run. In conventional drilling, more pipe is simply added at the surface as depth increases. The number of different grades of pipe should be kept to a minimum since the increased pipe handling required by the heavyweight will be exacerbated by a design calling for several grades of drillpipe. Should this phase of the design determine that the well cannot be drilled for any reason, the well plan may need to be rethought. Consideration should be given to reducing the build rate and/or horizontal displacement required.
Start of End of
Run Run
Start of End of
Run Run
The length ofheavyweight must be increased so that heavyweight drillpipe is at point A at the beginning of the run, as well as the end. At the end of this run, compressive forces at point A may have increased to the critical buckling force, and drillpipe will buckle. Therefore, heavyweight drillpipe should be used here.
Figure 15 Buckling Region
If the well design calls for running the drillpipe at the surface close to the design limits for tension and/or torsion, further calculations should be done to determine the reduction in tensile strength due to torque and vice versa. API Recommended Practice 7G gives the equations for this in Appendix A, Section A.8.3.
The next phase of the design should look at the planned casing depths. Both casing and drillpipe should be modeled at each depth (including TD) to determine if the well plan is achievable. The same design criteria listed above should be applied to insure that adequate tensile and torsional margins are built into the design.
References: 1Chen, Yu-Che, Lin, Yu-Hsu, and Cheatham, John B.: "Tubing and Casing Buckling in Horizontal Wells," JPT (Feb. 1990) 140.
2Johancsik, C.A., Friesen, D.B., and Dawson, R.: "Torque and Drag in Directional Wells-Prediction and Measurement," JPT (June 1984) 987-92.
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