1. Selecting an Appropriate Technique Read: UDM Chapter 4 pages 4.1-4.54
Lesson 12
Selecting an Appropriate Technique
Read: UDM Chapter 4
pages

2. Selecting an Appropriate Technique
Potential Applications and Candidate Technique
Technical Feasibility
Economic Analysis
Harold Vance Department of Petroleum Engineering

3. Required data for UBO Candidate Identification:
Pore pressure/gradient plots
Actual reservoir pore pressure
ROP records
Production rate or reservoir characteristics to calculate/estimate production rate
Core analysis
Harold Vance Department of Petroleum Engineering

4. Required data for UBO Candidate Identification:
Formation fluid types
Formation integrity test data
Water/chemical sensitivity
Lost circulation information
Fracture pressure/gradient plot
Harold Vance Department of Petroleum Engineering

5. Required data for UBO Candidate Identification:
Sour/Corrosive gas data
Location topography/actual location
Well logs from area wells
Triaxial stress test data on any formation samples
Harold Vance Department of Petroleum Engineering

6. Poor candidates for UBD
High permeability coupled with high pore pressure
Unknown reservoir pressure
Discontinuous UBO likely (numerous trips, connections, surveys)
High production rates possible at low drawdown
Harold Vance Department of Petroleum Engineering

7. Poor candidates for UBD
Weak rock formations prone to wellbore collapse at high drawdown
Steeply dipping/fractured formation in tectonically active areas
Thick, unstable coal beds
Harold Vance Department of Petroleum Engineering

8. Poor candidates for UBD
Young, geo-pressure shale
H2S bearing formations
Multiple reservoirs open with different pressures
Isolated locations with poor supplies
Formation with a high likelihood of corrosion
Harold Vance Department of Petroleum Engineering

9. Good candidates for UBD
Pressure depleted formations
Areas prone to differential pressure sticking
Hard rock (dense, low permeability, low porosity)
“Crooked-hole” country and steeply dipping formations
Harold Vance Department of Petroleum Engineering

10. Good candidates for UBD
Lost-returns zones
Re-entries and workovers (especially pressure depleted zones)
Zones prone to formation damage
Areas with limited availability of water
Harold Vance Department of Petroleum Engineering

11. Good candidates for UBD
Fractured formations
Vugular formations
High permeability formations
Highly variable formations
Harold Vance Department of Petroleum Engineering

12. Good candidates for UBD
Once the optimum candidate has been identified, the appropriate technique must be selected, based on much of the same data required to pick the candidate.
Harold Vance Department of Petroleum Engineering

13. Candidate Decision Tree
Harold Vance Department of Petroleum Engineering

14. Candidate Decision Tree
Harold Vance Department of Petroleum Engineering

15. Candidate Decision Tree
Harold Vance Department of Petroleum Engineering

16. Candidate Decision Tree
Harold Vance Department of Petroleum Engineering

17. Harold Vance Department of Petroleum Engineering

18. Harold Vance Department of Petroleum Engineering

19. Harold Vance Department of Petroleum Engineering
These decision trees can be found on the IADC website (
Click on Committees
Click on Underbalanced Drilling committee
Click on decision tree.
Harold Vance Department of Petroleum Engineering

20. Potential Applications and Candidate Technique
Harold Vance Department of Petroleum Engineering

21. Low ROP through hard rock
Dry air
Mist, if there is a slight water inflow
Foam, if there is heavy water inflow, if the borehole wall is prone to erosion, or if there is a large hole diameter.
Nitrogen or natural gas, if the well is producing wet gas and it is a high angle or horizontal hole.
Harold Vance Department of Petroleum Engineering

22. Lost circulation through the overburden
Aerated mud, if the ROP is high (rock strength low or moderate) of if water-sensitive shales are present.
Foam is possible if wellbore instability is not a problem
Harold Vance Department of Petroleum Engineering

23. Differential sticking through the overburden
Nitrified mud, if gas production is likely, especially if a closed system is to be used.
Aerated mud, if gas production is unlikely and an open surface system is to be used.
Foam is possible if the pore pressure is very low and if the formations are very hard
Harold Vance Department of Petroleum Engineering

24. Formation damage through a soft/medium-depleted reservoir
Nitrified brine or crude
string injection, if the pore pressure is very low
parasite injection, if the pore pressure is high enough and a deviated/horizontal hole needs conventional MWD and/or mud motor
Temporary casing injection, if the pore pressure is intermediate and a high gas rate in needed.
Harold Vance Department of Petroleum Engineering

25. Formation damage through a soft/medium-depleted reservoir
Nitrified brine or crude, con’t
String and temporary casing injection, if the pore pressure is very low and/or if very high gas rates
Foam, if the pore pressure is very low and an open surface system is acceptable
Harold Vance Department of Petroleum Engineering

26. Formation damage through a normally pressured reservoir
Flowdrill (use a closed surface system if sour gas is possible)
Harold Vance Department of Petroleum Engineering

27. Harold Vance Department of Petroleum Engineering
Lost circulation/formation damage through a normally pressured, fractured reservoir
Flowdrill (use an atmospheric system if no sour gas is possible)
Harold Vance Department of Petroleum Engineering

28. Formation damage through an overpressured reservoir.
Snub drill (use a closed surface system is sour gas is possible)
Harold Vance Department of Petroleum Engineering

29. Technical Feasibility
In evaluating the feasibility of a technique, a controlling factor is the range of anticipated borehole pressures which will be required for each zone to be drilled.
The upper limit is formation pore pressure
Lower limit will be determined by wellbore stability.
Harold Vance Department of Petroleum Engineering

30. Technical Feasibility
First step is to determine the anticipated pressures.
Step two is to determine which methods are functional within the anticipated pressure window.
Harold Vance Department of Petroleum Engineering

31. Technical Feasibility
Other considerations are:
Will there be sloughing shales?
Are aqueous fluids inappropriate?
Will water producing horizons be penetrated?
Will multiple, permeable zones, with dramatically different pore pressures, be encountered?
Harold Vance Department of Petroleum Engineering

32. Technical Feasibility
Other considerations con’t:
What is the potential for chemical formation damage, due to fluid/fluid or fluid/formation interaction and is this an overwhelming problem, regardless of what wellbore pressure is used?
Is there a potential for sour gas production?
Harold Vance Department of Petroleum Engineering

33. Technical Feasibility
Other considerations con’t:
Are there features of the well geometry which dictate specific underbalanced protocols?
What is the local availability of suitable equipment and consumables (including liquids and gases for the drilling fluids)?
Harold Vance Department of Petroleum Engineering

34. Borehole pressure limits
Pore pressure
the wellbore pressure must be maintained below the formation pressure in all open hole sections.
If there is no formation fluid inflow, borehole pressures with dry gas, mist, foam or pure liquid will be lower when not circulating.
With fluid influx, borehole pressure can increase or decrease when not circulating.
Harold Vance Department of Petroleum Engineering

35. Borehole pressure limits
Pore pressure
Best practice is to use the:
lower bounds for pore pressure prediction when choosing a technique
while surface equipment capacity and drilling specifics should be based on an upper bound.
Harold Vance Department of Petroleum Engineering

36. Borehole pressure limits
Wellbore stability provides the lower limit to the allowable borehole pressures.
Harold Vance Department of Petroleum Engineering

37. Borehole pressure limits
Hydrocarbon production rates can sometimes set the lower bound, depending upon the surface equipment available.
Formation damage may effect the tolerable drawdown due to fines mobilization in the producing formation.
Harold Vance Department of Petroleum Engineering

38. Borehole pressure limits
Backpressure from a choke can sometimes be used to protect the surface equipment from excess production rates or pressures.
This also increases the BHP.
This is limited by the pressure rating of the equipment and formation upstream of the choke.
Harold Vance Department of Petroleum Engineering

39. Borehole pressure limits
When using compressible fluids, it is usually more cost effective to switch to a higher density fluid than to choke back the well.
Harold Vance Department of Petroleum Engineering

40. Borehole pressure limits
Applying back pressure will:
increase the gas injection pressure.
Increase the gas injection rate required for acceptable hole cleaning.
These both will increase the cost of the gas supply.
Harold Vance Department of Petroleum Engineering

41. Borehole pressure limits
With a gasified liquid, BHP can usually be increased by reducing the gas injection rate.
When drilling with foam, back pressure may be necessary to maintain foam quality.
Holding back pressure is most beneficial when drilling with liquids.
Harold Vance Department of Petroleum Engineering

42. Borehole pressure limits
Once the maximum tolerable surface pressure is reached, production rate can only be further reduced by increasing downhole pressure by increasing the effective density of the drilling fluid.
Harold Vance Department of Petroleum Engineering

43. Implications of Drilling Technique Selection
Pore pressure gradients vary with depth
Formation strength varies with depth
In-situ stresses vary with depth
The tolerable stresses, are affected by by the inclination and orientation of deviated, extended reach and horizontal wells.
Harold Vance Department of Petroleum Engineering

44. Implications of Drilling Technique Selection
Production rates depend on the length of the reservoir that is open to the wellbore and on the underbalanced pressure
Harold Vance Department of Petroleum Engineering

45. Implications of Drilling Technique Selection
Once the borehole pressure limits, corresponding to wellbore instability and excessive production rate, have been determined , a first pass evaluation of the different drilling techniques can be performed.
Harold Vance Department of Petroleum Engineering

46. Harold Vance Department of Petroleum Engineering
Example 1
Shallow, normally pressured well.
No wellbore stability problems
Surface equipment can handle the anticipated AOF.
Minimal water inflow is expected.
Harold Vance Department of Petroleum Engineering

47. Harold Vance Department of Petroleum Engineering
Example 2
Depleted sandstone from 3000 to 4000 ft with a pore pressure gradient of 5 ppg. Pore pressure above the sand is 8 ppg.
Lost circulation and sticking is a problem with mud.
No instability problems anticipated if borehole pressure is > 2 ppg.
Production rate is low.
Harold Vance Department of Petroleum Engineering

48. Harold Vance Department of Petroleum Engineering
Example 3
Pore pressure = 8 ppg
Shale from ’ requires a minimum wellbore pressure of 7 ppg
Target zone is ’
Reservoir itself is competent unless borehole pressure < 5 ppg
Expect high flow rates w/ minimum drawdown = 500 psi
Pore pressure at 9000’ = 3744 psi, min BHP = 3244 psi or 6.93 ppg
Harold Vance Department of Petroleum Engineering

49. Harold Vance Department of Petroleum Engineering
Example 4
Maximum drawdown = 100 psi.
equivalent to 7.79 ppg.
Diesel or crude gives a pressure lower than this. Plain water is too dense.
Harold Vance Department of Petroleum Engineering

50. Harold Vance Department of Petroleum Engineering
Example 5
Reservoir is depleted to 6.5 ppg. Maximum drawdown is 500 psi. The tolerable range for ECD through the reservoir would be ppg. A gasified liquid would be required.
This would not supply sufficient support for the shale above.
Harold Vance Department of Petroleum Engineering

51. Evaluating Highly Productive Formations
Require detailed numerical analyses of circulating pressures.
Formation fluid influx interacts with drilling fluids which effect borehole pressure - effecting influx rate.
Harold Vance Department of Petroleum Engineering

52. Evaluating Highly Productive Formations
When circulation stops, the influx lifts mud from wellbore.
This changes the borehole pressure and the production rate.
Harold Vance Department of Petroleum Engineering

53. Evaluating Highly Productive Formations
Choking back the well returns further complicates the calculation of borehole pressures and production rate.
If the fluid is incompressible, backpressure changes BHP by the amount of pressure applied.
If the fluid is compressible, backpressure changes density, velocity, and BHP
Harold Vance Department of Petroleum Engineering

54. Evaluating Highly Productive Formations
Uncertainty of input parameters in simulators leads to uncertainty in output.
In many cases these uncertainties can make simulations in technique selection unjustified.
Harold Vance Department of Petroleum Engineering

55. Harold Vance Department of Petroleum Engineering
Water production
Production of small quantities of water makes dry gas drilling difficult.
If offset wells have a history of water production, dry gas drilling below the water zone is probably impractical.
Harold Vance Department of Petroleum Engineering

56. Harold Vance Department of Petroleum Engineering
Water production
When misting, higher gas rates are required to prevent slug flow.
Slug flow can damage the borehole and surface equipment.
Higher injection rates and the increased density in the annulus may require boosters on the compressors.
Harold Vance Department of Petroleum Engineering

57. Harold Vance Department of Petroleum Engineering
Water production
Large water influxes may require foams.
High disposal costs can sometimes make mist drilling impractical.
Higher density foams can decrease water influx, however the increased volume of make-up water may make disposal still impractical.
Harold Vance Department of Petroleum Engineering

58. Harold Vance Department of Petroleum Engineering
Water production
If high water influx makes gas and foams impractical, aerated mud or low density liquids may be required.
Harold Vance Department of Petroleum Engineering

59. Multiple permeable zones
If all zones are to be drilled UB, the circulating pressure must satisfy the borehole pressure requirements for all open permeable zones, simultaneously.
Several factors can prevent this from happening.
Harold Vance Department of Petroleum Engineering

60. Factors preventing UB in all zones
The ECD of compressible fluids increases with increasing depth.
In vertical wells, it is possible for a permeable zone close to the bit to be overbalanced when a permeable zone higher up hole, with the same pore pressure gradient, is UB
Harold Vance Department of Petroleum Engineering

61. Factors preventing UB in all zones
This effect is more pronounced in high angle and horizontal wells.
AFP increases along the borehole even if HSP remains relatively constant along the borehole.
Harold Vance Department of Petroleum Engineering

62. Factors preventing UB in all zones
Changes in pore pressure gradient along the wellbore may be present.
This can be due to abnormally pressured formations, or partially depleted formations.
Harold Vance Department of Petroleum Engineering

63. Multiple permeable zones
The major concern with multiple permeable zones is the potential for underground blowouts.
Extreme care must be taken to prevent this from happening when pressure changes occur such as tripping, or connections.
Harold Vance Department of Petroleum Engineering

64. If cross flows cannot be tolerated:
Use a different drilling technique that allows all permeable zones to remain UB, if possible
Kill the well before suspending circulation.
Change the casing scheme so that the upper formations are isolated behind pipe before penetrating the producing zone.
Harold Vance Department of Petroleum Engineering

65. Harold Vance Department of Petroleum Engineering
Sour gas
There must be no possibility of releasing hydrogen sulfide into the atmosphere while the well is being drilled or completed.
If any is produced during drilling it must be disposed of in a suitable flare.
Harold Vance Department of Petroleum Engineering

66. Harold Vance Department of Petroleum Engineering
Sour gas
H2S can become entrained in any liquid in the wellbore, and must be completely removed from the fluid and flared before any of the liquids are returned to any open surface pits.
The separation process should be completed in a closed vessel.
Harold Vance Department of Petroleum Engineering

67. Harold Vance Department of Petroleum Engineering
Sour gas
Sour gas can become entrained in foams.
The foam must be completely broken prior to separation.
Unless effective defoaming can be guaranteed foams cannot be used in closed systems, and should not be used in the presence of Hydrogen Sulfide.
Harold Vance Department of Petroleum Engineering

68. Drilling/Reservoir fluid incompatibility
It can be difficult to prevent temporary overbalance.
Drilling fluids should be tested for compatibility with formation fluids.
Harold Vance Department of Petroleum Engineering

69. Harold Vance Department of Petroleum Engineering
Hole geometry
A compressible fluid will have a greater ECD in deep wells than in shallow wells.
Annular gas injection only reduces the density of the fluids above the injection point. In deep wells drillstring injection may be required.
Harold Vance Department of Petroleum Engineering

70. Harold Vance Department of Petroleum Engineering
Hole geometry
Increasing ECD with depth may make it impossible to maintain the proper foam quality in deep wells. Backpressure may be required, increasing the gas supply needed.
Increasing hole size makes hole cleaning more difficult.
Harold Vance Department of Petroleum Engineering

71. Harold Vance Department of Petroleum Engineering
Hole geometry
Large hole sizes may require larger diameter surface equipment. Larger surface diverter equipment may not have the pressure rating of smaller resulting in lower back pressure capabilities.
Harold Vance Department of Petroleum Engineering

72. Naturally fractured formations
In fractured formations, high viscosity drilling fluids, circulating at low rates may prevent hole enlargement and still maintain UB.
Stiff foams may be the preferred candidate.
Harold Vance Department of Petroleum Engineering

73. Harold Vance Department of Petroleum Engineering
Logistics
Water supplies may be limited in some areas, and a technique that limits water use may be chosen.
Availability and access to the gaseous phase can influence the choice of gas used.
Harold Vance Department of Petroleum Engineering

74. Harold Vance Department of Petroleum Engineering
Logistics
Offshore locations generally do not have the same space available as land locations.
Equipment used on surface locations may not be suitable for offshore locations.
Modular closed systems must be used offshore.
Harold Vance Department of Petroleum Engineering

75. Harold Vance Department of Petroleum Engineering
Logistics
The high production rates necessary for offshore wells to be economically viable may make them unlikely candidates for UBD.
Harold Vance Department of Petroleum Engineering

76. Harold Vance Department of Petroleum Engineering
Economic Analysis
Rules of thumb
UBO increases costs times the cost per day over conventional
but may be accomplished in 1/4 to 1/10 of the time.
Harold Vance Department of Petroleum Engineering

77. Harold Vance Department of Petroleum Engineering
Economic Analysis
Rules of thumb
In permeable rock ROP may be increased from 30% to 300% as well goes from overbalanced to balanced
Below balance ROP will increase another 10-20%
In impermeable rock, ROP will increase %
Harold Vance Department of Petroleum Engineering

78. Harold Vance Department of Petroleum Engineering

79. Harold Vance Department of Petroleum Engineering

80. Steps for Economic Analysis
1. Determine the expected penetration rate or drilling time of each candidate hole-interval, if the operation were to be carried out conventionally
2. Estimate the daily cost of conventional drilling operations for each prospective hole-interval based on empirical data.
Harold Vance Department of Petroleum Engineering

81. Steps for Economic Analysis
3. Multiply the conventional daily cost by an underbalanced factor ( , depending on difficulty of the operation) to get the expected daily cost of UBO
4. Apply the expected underbalanced operating cost by the anticipated underbalanced drilling ROP to get the total cost for each interval.
Harold Vance Department of Petroleum Engineering

82. Factors that Effect the Economics of Underbalanced Drilling
Penetration rate
Bit selection
Bit weight and rotary speed
Mud weight
Harold Vance Department of Petroleum Engineering

83. Completions and Stimulation
UBO does not save completion time
but, if you are going to drill UB to prevent formation damage, you better complete UB
Mitigation of formation damage in wells that will need to be hydraulically fractured (except naturally fractured) may be a poor and unnecessary economic decision.
Harold Vance Department of Petroleum Engineering

84. Harold Vance Department of Petroleum Engineering
Formation Evaluation
Real time formation evaluation possible
UB coring possible
Harold Vance Department of Petroleum Engineering

85. Environmental Savings
Closed systems make smaller reserve pits and locations possible, but there is additional costs of rental of the systems.
Harold Vance Department of Petroleum Engineering

86. Harold Vance Department of Petroleum Engineering
Fluid Type
The bottom line controlling factor may be the specific fluid system adopted. Each fluid type has technical and economic advantages and limitations.
Harold Vance Department of Petroleum Engineering

87. Harold Vance Department of Petroleum Engineering

88. Harold Vance Department of Petroleum Engineering

89. Harold Vance Department of Petroleum Engineering

90. Harold Vance Department of Petroleum Engineering

91. Harold Vance Department of Petroleum Engineering

92. Harold Vance Department of Petroleum Engineering

93. Cost Comparisons - Case 1 Nitrogen vs. Pipeline Gas
Harold Vance Department of Petroleum Engineering

94. Cost Comparisons - Case 1
Harold Vance Department of Petroleum Engineering

95. Cost Comparisons - Case 2
Harold Vance Department of Petroleum Engineering

96. Harold Vance Department of Petroleum Engineering
Economic Analysis
On the basis of available technology, select the potential drilling systems to be evaluated.
Tabulate the tangible and intangible costs for each system
Rely on previous history and recognize the inevitability of statistical variation
Harold Vance Department of Petroleum Engineering

97. Harold Vance Department of Petroleum Engineering
Economic Analysis
Perform basic cost/ft drilling evaluations.
Harold Vance Department of Petroleum Engineering

98. Harold Vance Department of Petroleum Engineering
Assess Drilling Costs
Harold Vance Department of Petroleum Engineering

99. Harold Vance Department of Petroleum Engineering

100. Harold Vance Department of Petroleum Engineering

101. Accelerated Production
Earlier production can improve the NPV
Harold Vance Department of Petroleum Engineering

102. Improved Production/Reserves
The absolute and relative increase in production should be calculated, or estimated.
Productivity Index, PI should be calculated based on whether the well is vertical, horizontal, oil, gas, radial, transient flow, or pseudo-steady state flow (see page 4.48)
Harold Vance Department of Petroleum Engineering

103. Improved Production/Reserves
Well Inflow Quality Indicator, WIQI, is the ratio of the PI for an impaired to that for an undamaged well.
Harold Vance Department of Petroleum Engineering

104. Improved Production/Reserves
Harold Vance Department of Petroleum Engineering

105. Improved Production/Reserves
Harold Vance Department of Petroleum Engineering

106. Improved Production/Reserves
Harold Vance Department of Petroleum Engineering

107. Harold Vance Department of Petroleum Engineering
Example
Oil well
Revenue Interest = R = 0.375
Working Interest = WI = 0.5
Gross Income (per net bbl)
Crude Price = $20.00/bbl
Less
Transportation = $1.00/bbl
Production taxes = $6.00/bbl
Leaves
Gross Income (per net bbl) = $13.00/bbl
Estimated Op. Expense = $5000/well month
Number of wells = 5
Harold Vance Department of Petroleum Engineering

108. Harold Vance Department of Petroleum Engineering
Case 1
All five wells drilled in the first year with a conventional mud system.
Harold Vance Department of Petroleum Engineering

109. Harold Vance Department of Petroleum Engineering

110. Harold Vance Department of Petroleum Engineering
Case 2
Same as Case 1 with the exception that there is higher production to reduced formation damage from UBD.
Harold Vance Department of Petroleum Engineering

111. Harold Vance Department of Petroleum Engineering

112. Harold Vance Department of Petroleum Engineering
Case 3
Same as case 2 with the exception that development costs for the five wells are $150,000 less, due to improved drilling while underbalanced.
Harold Vance Department of Petroleum Engineering

113. Harold Vance Department of Petroleum Engineering

114. Harold Vance Department of Petroleum Engineering
Summary of Examples
Harold Vance Department of Petroleum Engineering

115. Harold Vance Department of Petroleum Engineering
Summary of Examples
Harold Vance Department of Petroleum Engineering