Formulas and Calculations for Drilling, Production, and Workover: All the Formulas You Need to Solve Drilling and Production Problems

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Formulas and Calculations for Drilling, Production, and Workover: All the Formulas You Need to Solve Drilling and Producti ...
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Contents
Preface
Prologue
Chapter 1: Basic equations
1.1. Terminology
1.2. Mud weight MW (lb/ft3), mud weight MW (ppg), and specific gravity (SG)
1.3. Hydrostatic pressure (P) and (p)
1.4. Pressure gradient (psi/ft), G (ppg)
1.5. Mud pump output q (bbl/stk) and Q (gpm)
1.5.1. Triplex pump
1.5.2. Duplex pump
1.6. Hydraulic horsepower
1.7. Estimated weight of drill collars in AIR
1.8. Open hole and tubular capacity and displacement formulas
1.8.1. Capacity of open hole or tubulars
1.8.2. Displacement of tubulars
1.8.3. Annular capacity between casing or hole and drill pipe, tubing, or casing
1.8.4. Annular capacity between casing and multiple strings of tubing
1.9. Amount of cuttings drilled per foot of hole
1.10. Annular velocity (AV)
1.11. Pump output required in GPM for a desired annular velocity, ft/min
1.12. Bottoms-up formula
1.13. Pump pressure/pump stroke relationship (the Roughnecks formula)
1.14. Buoyancy factor (BF)
1.15. Formation temperature (Tf)
1.16. Temperature conversion formulas
Appendix: Supplementary material
Chapter 2: RIG calculations
2.1. Accumulator capacity
2.1.1. Usable volume per bottle
2.1.2. Surface application
2.1.3. Volume capacity of the accumulator bottle
2.1.4. Deepwater applications
2.1.5. Accumulator precharge pressure
2.2. Slug calculations
2.2.1. Barrels of slug required for a desired length of dry pipe
2.2.2. Weight of slug required for a desired length of dry pipe with a set volume of slug
2.2.3. Volume, height, and pressure gained because of placement of the slug in the drill pipe
2.2.4. The amount of dry pipe in feet after pumping the slug
2.3. Bulk density of cuttings using the mud balance
2.4. Drill string design
2.4.1. Estimated weight of the drill collars in air
2.4.2. Tensile strength of tubulars in lb (Ref.: API Spec 5D & 7)
2.4.3. Reduced tensile yield strength of tubulars in lb
2.4.4. Adjusted weight and length of the drill pipe and tool joints
2.4.5. Length of the BHA necessary for a desired weight on bit
2.4.6. Maximum length of the premium drill pipe that can be run into the hole with a specific BHA based on the margin of ...
2.4.7. Length of the premium drill pipe based on the overpull and slip crushing
2.4.7.1. Slip crushing
2.4.8. Design of a drill string for a specific set of well conditions
2.5. Depth of a washout in a drill pipe
2.6. Stuck pipe calculations
2.6.1. Calculate the number of days to quit fishing
2.6.2. Determine the length of the free pipe in feet and the free point constant
2.6.3. Stuck pipe overbalance guidelines
2.6.4. Force required to pull the differently stuck pipe free
2.7. Calculations required for placing spotting pills in an open hole annulus
2.7.1. Amount of spotting fluid pill in barrels required to cover the stuck point of the drill string or casing and the n ...
2.7.2. Determination of the length of an unweighted spotting fluid pill that will balance formation pressure in the annul ...
2.8. Line size for a low pressure system
Appendix: Supplementary material
References
Bibliography
Chapter 3: Pressure control
3.1. Normal kill sheet
3.2. Pressure chart: Prepare a chart with pressure and strokes
3.2.1. Use this technique for rigs that have digital pressure gauges
3.2.2. Use this technique for rigs that have analog pressure gauges
3.3. Kill sheet with a tapered string
3.4. Kill sheet for a highly deviated well
3.5. Maximum anticipated surface pressure
3.6. Trip margin (TM)
3.7. Sizing the diverter line
3.8. Fracture gradient (FG)
3.8.1. Fracture gradient determination-Surface application
3.8.2. Fracture gradient determination-Subsea application
3.9. Formation pressure tests
3.9.1. Precautions to be undertaken before testing
3.9.2. Testing to an equivalent mud weight (formation integrity test-FIT)
3.9.3. Testing to leak-off test pressure
3.9.4. Procedure to prepare the graph to record leak-off pressure data
3.9.5. Maximum allowable mud weight from leak-off test data
3.10. Kick tolerance (KT)
3.10.1. Kick tolerance intensity (KTI)
3.10.2. Kick tolerance volume (KTV)
3.10.3. Summary
3.11. Kick analysis
3.11.1. Formation pressure (FP) with the well shut-in on a kick
3.11.2. Bottom hole pressure (BHP) with the well shut-in on a kick
3.11.3. Shut-in drill pipe pressure (SIDPP)
3.11.4. Shut-in casing pressure (SICP)
3.11.5. Length of influx in ft
3.11.6. Estimated type of influx
3.12. Gas cut mud weight measurement calculations
3.12.1. Determine the original mud weight of a gas cut mud at the flowline
3.12.2. Determine the reduction in the mud weight at the flowline when a gas formation is drilled with no kick
3.13. Gas migration in a shut-in well
3.13.1. Gas migration
3.14. Hydrostatic pressure decrease at TD caused by formation fluid influx due to a kick
3.14.1. Hydrostatic pressure decrease
3.14.2. Maximum surface pressure from a gas kick in a water-base mud
3.14.3. Maximum pit gain from gas kick in a water-base mud
3.15. Maximum pressures when circulating out a kick (Moore equations)
3.15.1. Maximum pressure calculations
3.15.2. Summary of maximum pressures when circulating out a kick (Moore equations)
3.16. Gas flow into the wellbore
3.16.1. Gas flow into the wellbore
3.16.2. Gas flow through a choke
3.17. Pressure analysis
3.17.1. Gas expansion equation
3.17.2. Hydrostatic pressure exerted by each barrel of mud in the casing
3.17.3. Surface pressure during drill stem test (DST)
3.18. Stripping/snubbing calculations
3.18.1. Breakover point between stripping and snubbing
3.18.2. Minimum surface pressure before stripping is possible
3.18.3. Height gain from stripping into influx
3.18.4. Casing pressure increase from stripping into influx
3.18.5. Volume of mud that must be bled to maintain constant bottom hole pressure with a gas bubble rising
3.18.6. Maximum allowable surface pressure (MASP) governed by the formation
3.18.7. Maximum allowable surface pressure (MASP) governed by casing burst pressure
3.19. Subsea considerations
3.19.1. Casing pressure decrease when bringing well on choke
3.19.2. Pressure chart for bringing well on choke
3.19.3. Maximum allowable mud weight for subsea stack as derived from leak-off test data
3.19.4. Casing burst pressure-Subsea stack
3.19.5. Calculate choke line pressure loss in psi
3.19.6. Velocity through the choke line in ft/min
3.19.7. Adjusting choke line pressure loss for a higher mud weight in ppg
3.19.8. Minimum conductor casing setting depth in ft
3.19.9. Maximum mud weight with returns back to rig floor in ppg
3.19.10. Reduction in bottom hole pressure if riser is disconnected in psi
3.19.11. Bottom hole pressure when circulating out a kick in psi
3.20. Workover operations
3.20.1. Bullheading
3.20.2. Lubricate and bleed
3.21. Controlling gas migration
3.21.1. Drill pipe pressure method
3.21.2. Volumetric method to control gas migration
3.22. Gas lubrication
3.22.1. Gas lubrication-Volume method
3.22.2. Gas lubrication-Pressure method
3.23. Annular stripping procedures
3.23.1. Strip and bleed procedure
3.23.2. Combined stripping/volumetric procedure
3.23.3. Worksheet
3.24. Barite plug
Appendix: Supplementary material
Bibliography
Chapter 4: Drilling fluids
4.1. Mud density increase and volume change
4.1.1. Field procedure for determining the specific gravity of barite
4.1.2. Increase mud density-No base liquid added and no volume limit
4.1.3. Increase mud weight-No base liquid added but limit final volume
4.1.4. Increase the mud weight-With base liquid added and no volume limit
4.1.5. Increase mud weight-With base liquid added but limit final volume
4.1.6. Increase mud weight-With base liquid added but limit final volume and limited weight material inventory
4.1.7. Increase mud weight to a maximum mud weight with base liquid added but with limited weight material inventory
4.2. Mud weight reduction with base liquid dilution
4.2.1. Mud weight reduction with base liquid
4.3. Mixing fluids of different densities
4.3.1. Mixing fluids of different densities formula
4.4. Oil-based mud calculations
4.4.1. Calculate the starting volume of liquid (base oil plus water) required to prepare a desired final volume of nonaqu ...
4.4.2. Oil/water ratio from retort data
4.4.3. Change the OWR
4.5. Solids analysis
4.6. Solids fractions (barite treated muds)
4.6.1. Calculate the maximum recommended solids fraction in % based on the mud weight
4.6.2. Calculate the maximum recommended LGS fraction in % based on the mud weight
4.7. Dilution of mud system
4.7.1. Calculate the volume of dilution in bbl required to reduce the solids content in the mud system
4.7.2. Displacement-Barrels of water/slurry required
4.8. Evaluation of hydrocyclones
4.8.1. Calculate the mass of solids (for an unweighted mud) and the volume of water discarded by one cone of a hydrocyclo ...
4.8.2. Calculate the mass rate of solids in gal/h
4.8.3. Calculate the volume of liquid ejected by one cone of a hydrocyclone in gal/h
4.8.4. Calculate the theoretical cut point of hydrocyclone
4.9. Evaluation of centrifuge
4.9.1. Calculate the centrifugal force of a centrifuge bowl
4.9.2. Evaluate the centrifuge underflow
4.10. Mud volume required to drill 1000ft of hole
4.11. Determine the downhole density of the base oil or brine in the mud at depth of interest in ppg
Appendix: Supplementary material
Bibliography
Chapter 5: Cementing calculations
5.1. Cement additive calculations
5.2. Water requirements
5.3. Field cement additive calculations
5.4. Weighted cement calculations
5.5. Calculate the number of sacks required for cement job
5.6. Calculations for the number of feet to be cemented
5.7. Setting a balanced cement plug
5.8. Differential hydrostatic pressure between cement in the annulus and mud inside the casing
5.9. Hydraulicing casing
5.10. Pump strokes to bump the plug
Appendix: Supplementary material
Bibliography
Chapter 6: Well hydraulics
6.1. System pressure losses
6.1.1. Determine the pressure loss in the surface system in psi
6.1.2. Determine the pressure loss in the drill string (drill pipe-DP, heavy weight drill pipe-HWDP, or drill collars-DC) ...
6.1.3. Determine the pressure loss at the bit in psi
6.1.4. Determine the pressure loss in the annulus in psi
6.1.5. Critical velocity and pump rate
6.2. Equivalent circulating ``density´´ ECD (ppg)
6.3. Surge and swab pressure loss
6.3.1. Determine the pressure surge for the plugged pipe case
6.3.2. Determine the pressure surge for the open pipe case
6.4. Equivalent spherical diameter for drilled cuttings size used in slip velocity equations
6.5. Slip velocity of cuttings in the annulus
6.6. Carrying capacity index
6.7. Pressure required to break circulation
6.8. Initial gel strength guidelines for top hole drilling in high angle wells (after Zamora)
6.9. Bit nozzle selection-Optimized hydraulics
6.10. Hydraulic analysis
6.11. Minimum flowrate for PDC bits
6.12. Critical RPM: RPM to avoid due to excessive vibration (accurate to approximately 15%)
Appendix: Supplementary material
Bibliography
Chapter 7: Drilling and completion calculations
7.1. Control drilling-Maximum drilling rate (MDR) when drilling large diameter holes (14in. and larger) in ft/h
7.2. Mud effects on rate of penetration
7.3. Cuttings concentration % by volume
7.4. ``d´´ Exponent and corrected ``d´´ exponent
7.5. Cost per foot
7.6. Rig loads
7.7. Ton-mile (TM) calculations
7.7.1. Round trip ton-miles (RTTM)
7.7.2. Drilling or ``connection´´ ton-miles
7.7.3. Ton-miles during coring operations
7.7.4. Ton-miles setting casing
7.7.5. Ton-miles while making short trips
7.7.6. Cutoff practices for rotary drilling line
7.7.7. Calculate the length of drill line cutoff
7.8. Hydrostatic pressure decrease when pulling pipe out of the hole
7.8.1. When pulling DRY pipe
7.8.2. When pulling WET pipe
7.9. Loss of overbalance due to falling mud level
7.9.1. Feet of pipe pulled DRY to lose overbalance
7.9.2. Feet of pipe pulled WET to lose overbalance
7.10. Lost circulation
7.10.1. Loss of overbalance
7.10.2. Determine the equivalent mud weight in ppg that will balance the formation losing mud volume
7.10.3. Determine the depth of the fluid level with loss of circulation in natural fractured formations
7.10.4. Determine the amount of mud loss that can occur before the well begins to flow from a gas-bearing formation
7.11. Core analysis technique
7.11.1. Extraction and saturation determinations (dean stark analysis)
7.12. Temperature correction for brines
7.12.1. Determine the clear brine fluid weight to be mixed at the surface to balance the required bottomhole pressure at ...
7.13. Tubing stretch
7.14. Directional drilling calculations
7.14.1. Directional survey calculations
7.14.2. Deviation/departure calculation
7.14.3. Dogleg severity calculation
7.14.4. Available weight on bit in directional wells
7.14.5. Determining true vertical depth
7.15. Hole washout
Appendix: Supplementary material
Bibliography
Chapter 8: Air and gas calculations
8.1. Static gas column
8.2. Direct circulation: Flow up the annulus (from annulus bottomhole to exit)
8.3. Direct circulation: Flow down the inside of the drill pipe (from the bottom of the inside of the drill string to the ...
8.4. Reverse circulation: Flow up the inside of tubing string
8.5. Reverse circulation: Flow down the annulus
8.6. Reverse circulation: Adjusting for reservoir pressure
Appendix: Supplementary material
Bibliography
Appendix A
A.1. Tank capacity determinations
A.1.1. Rectangular tanks with flat bottom
A.1.2. Rectangular tanks with sloping sides
A.1.3. Horizontal cylindrical (lay down) tank
A.1.4. Tapered vertical cylindrical tanks
A.1.5. Vertical cylindrical tank
A.2. Pipe capacities, displacements, and weight calculations
Appendix: Supplementary material
Appendix B: Conversion factors
Appendix C: Average annual atmospheric conditions
Index
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