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Lesson 12. Selecting an Appropriate Technique Read: UDM Chapter 4 pages 4.1-4.54. Selecting an Appropriate Technique. Potential Applications and Candidate Technique Technical Feasibility Economic Analysis. Required data for UBO Candidate Identification:.

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Lesson 12


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    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 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. These decision trees can be found on the IADC website (www.iadc.org). 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. 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. 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. 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. Example 3 Pore pressure = 8 ppg Shale from 6-8000’ requires a minimum wellbore pressure of 7 ppg Target zone is 8-9000’ 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. 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. Example 5 Reservoir is depleted to 6.5 ppg. Maximum drawdown is 500 psi. The tolerable range for ECD through the reservoir would be 5.4-6.5 ppg. A gasified liquid would be required. This would not supply sufficient support for the shale above. Harold Vance Department of Petroleum Engineering