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

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

2. Selecting an Appropriate Technique Potential applications and candidate technique. Technical feasibility. Economic analysis.

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.

4. Formation fluid types. Formation integrity test data. Water/chemical sensitivity. Lost circulation information. Fracture pressure/gradient plot. Required Data For UBO Candidate Identification

5. Sour/Corrosive gas data. Location topography/actual location. Well logs from area wells. Triaxial stress test data on any formation samples. Required Data For UBO Candidate Identification

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.

7. Weak rock formations prone to wellbore collapse at high drawdown. Steeply dipping/fractured formation in tectonically active areas. Thick, unstable coal beds. Poor Candidates For UBD

8. 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. Poor Candidates For UBD

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.

10. Lost-returns zones. Re-entries and workovers (especially pressure depleted zones). Zones prone to formation damage. Areas with limited availability of water. Poor Candidates For UBD

11. Good Candidates For UBD Fractured formations. Vugular formations. High permeability formations. Highly variable formations.

12. 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. Good Candidates For UBD

13. Candidate Decision Tree-Sheet 1

14. Candidate Decision Tree-Sheet 2

16. Potential Applications and Candidate Technique

17. 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. N2 or natural gas, if the well is producing wet gas and it is a high angle or horizontal hole.

18. 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.

19. 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.

20. 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.

21. 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. Formation Damage Through A Soft/Medium-Depleted Reservoir

22. Formation Damage Through A Normally Pressured Reservoir Flowdrill (use a closed surface system if sour gas is possible).

23. Lost Circulation/Formation Damage Through A Normally Pressured, Fractured Reservoir Flowdrill (use an atmospheric system if no sour gas is possible).

24. Formation Damage Through An Overpressured Reservoir. Snub drill (use a closed surface system is sour gas is possible).

25. Technical Feasibility In evaluating the feasibility of candidate drilling techniques, a controlling factor is the range of anticipated borehole pressures which will be required for each zone to be drilled. The upper limit for UB conditions is formation pore pressure. Lower limit will generally be regulated by the lowest pressure at which wellbore stability is ensured.

26. First step is to determine the anticipated pressures. Step two is to determine which methods are functional within the anticipated pressure window.

27. 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?

28. 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? Technical Feasibility

29. 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)? Technical Feasibility

30. 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.

31. 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. Borehole Pressure Limits

32. Wellbore stability provides the lower limit to the allowable borehole pressures. Will be discussed later. Borehole Pressure Limits

33. 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. Borehole Pressure Limits

34. Backpressure from a choke can sometimes be used to protect the surface equipment from excess production rates or pressures. This also increases the BHP. The allowable backpressure is limited by the pressure rating of the equipment and formation upstream of the choke. Borehole Pressure Limits

35. When using compressible fluids, it is usually more cost effective to switch to a higher density fluid than to choke back the well. Borehole Pressure Limits

36. 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. Borehole Pressure Limits

37. 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. Borehole Pressure Limits

38. 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. Borehole Pressure Limits

39. 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.

40. Production rates depend on the length of the reservoir that is open to the wellbore and on the underbalanced pressure. Implications of Drilling Technique Selection

41. 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. Implications of Drilling Technique Selection

42. Example 1

43. Example 2

44. Example 3

45. Example 4

46. Example 5

47. 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.

48. When circulation stops, the influx lifts mud from wellbore. This changes the borehole pressure and the production rate. Evaluating Highly Productive Formations

49. 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. Evaluating Highly Productive Formations

50. Uncertainty of input parameters in simulators leads to uncertainty in output. In many cases these uncertainties can make simulations in technique selection unjustified. Evaluating Highly Productive Formations

51. 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.

52. 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. Water Production

53. 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. Water Production

54. If high water influx makes gas and foams impractical, aerated mud or low density liquids may be required. Water Production

55. 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.

56. 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.

57. This effect is more pronounced in high angle and horizontal wells. AFP increases along the borehole even if formation pore pressure remains relatively constant along the borehole. Factors Preventing UB In All Zones

58. Changes in pore pressure gradient along the wellbore may be present. This can be due to abnormally pressured formations, or partially depleted formations. Factors Preventing UB In All Zones

59. 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.

60. 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 cased of before penetrating the lower zone in the hole.

61. 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.

62. 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. Sour Gas

63. 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. Sour Gas

64. Drilling/Reservoir Fluid Incompatibility It can be difficult to prevent temporary overbalance. Drilling fluids should be tested for compatibility with formation fluids.

65. 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. Drillpipe gas injection may be necessary if long vertical sections are to be drilled with gasified liquid.

66. 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. Hole Geometry

67. 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. Hole Geometry

68. 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.

69. 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.

70. 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. Logistics

71. The high production rates necessary for offshore wells to be economically viable may make them unlikely candidates for UBD. Logistics

72. Economic Analysis Rules of thumb. UBO increases costs 1.25 - 2.0 times the cost per day over conventional. but may be accomplished in 1/4 to 1/10 of the time.

73. 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 100-200%. Economic Analysis

76. 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.

77. 3.Multiply the conventional daily cost by an underbalanced factor (1.3-2.0, 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. Steps for Economic Analysis

78. Factors that Effect the Economics of UBD Penetration rate. Bit selection. Bit weight and rotary speed. Mud weight.

79. 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.

80. Formation Evaluation Real time formation evaluation possible. UB coring possible.

81. Environmental Savings Closed systems make smaller reserve pits and locations possible, but there is additional costs of rental of the systems.

82. Fluid Type The bottom line controlling factor may be the specific fluid system adopted. Each fluid type has technical and economic advantages and limitations.

90. Cost Comparisons - Case 1Nitrogen vs. Pipeline Gas

91. Cost Comparisons - Case 1

94. 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.

95. Perform basic cost/ft drilling evaluations. Economic Analysis

96. Assess Drilling Costs

97. Assess Drilling Costs

99. Accelerated Production Earlier production can improve the NPV

100. 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).

101. Well Inflow Quality Indicator, WIQI, is the ratio of the PI for an impaired to that for an undamaged well. Improved Production/Reserves

102. Improved Production/Reserves

103. Improved Production/Reserves

104. Improved Production/Reserves

105. 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

106. Case 1 All five wells drilled in the first year with a conventional mud system.

109. Case 2 Same as Case 1 with the exception that there is higher production to reduced formation damage from UBD.

112. 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.

115. Summary of all Cases(Present Worth of Cash)

116. Summary of Examples