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Economics of constructing deep HPHT gas wells with formate brines

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  • 90% recovery of recoverable condensate reserves in 4 years ! Think of leasing cesium formate brine as an investment in the future profitability of your gas condensate field development.
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Spe 130376 Slides

  1. 1. SPE 130376 A Review of the Impact of the Use of Formate Brines on the Economics of Deep Gas Field Development Projects <br />John Downs<br />Cabot Specialty Fluids<br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />
  2. 2. Deep gas wells are expensive ..... <br />12 times more expensive than conventional gas wells * <br />Last 10% of deep gas well accounts for 50% of total well cost *<br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />Gas well cost versus depth**<br />* US Department of Energy website - Onshore gas well costs in USA<br />** Snead (2005) - The Economics of Deep Drilling in Oklahoma <br />
  3. 3. Some basic principles for improving the economics of deep gas field developments ? <br />Working at depth is expensive, so.. : <br />Use technologies that will accelerate deep well construction *<br /> Get it right first time – avoid costly interventions <br /> Know what is down there - ensure accurate reservoir evaluation <br />Focus on recovering your substantial investment - extract <br />recoverable reserves as fast as the reservoir (engineers) will allow <br />* US DOE ”Deep Trek” R&D programme aimed at identifying some of these technologies <br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />
  4. 4. How can well construction fluids influence economics of deep gas field developments ? <br />WCF performance impacts on costsandrevenues<br /><ul><li> Time taken to drill and complete the required wells
  5. 5. Well design and placement
  6. 6. Well control and safety
  7. 7. Well integrity, lifetime and maintenance
  8. 8. Logging capability and interpretation
  9. 9. Waste management and liabilities
  10. 10. Rate of recovery of reserves </li></ul>2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />
  11. 11. Extreme conditions in deep wells expose the performance deficiencies of conventional WCF<br />High temperatures and hydrothermal chemistry <br /><ul><li>Barite sag, leading to well control problems
  12. 12. Need gels, causing high swab, surge and start-up pressures
  13. 13. Corrosive gas influx into halide brines will destroy ”corrosion resistant alloys” </li></ul>2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />Super 13Cr, 1 month<br />22Cr, 2 months<br />25Cr, 2 months <br />
  14. 14. Extreme conditions in deep wells expose the performance deficiencies of conventional WCF <br />High pressures and hard rocks<br />High solids loading have negative effects on ECD, ROP, bit life, swab and <br />surge, differential sticking, hole cleaning, tools, screens, seals, formation, etc ......! <br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />Best fluid for high ROP <br />and long bit-life is solids-free water … <br />From :SPE 112731 “Optimisation of Deep Drilling Performance with Improvements in Drill Bit and Drilling Fluid Design” <br />
  15. 15. Extreme conditions in deep gas wells expose the performance deficiencies of conventional WCF <br />Narrow drilling windows, aggravated by pressure depletion from<br /> production <br /><ul><li>Production while drilling lowers pore pressure and fracture gradient
  16. 16. Solids-weighted muds may not be able to stay within ECD limits
  17. 17. Well control problems if fracture pressure gradient exceeded
  18. 18. Increasingly the domain of MPD and ”designer fluids” providing Fracture Gradient </li></ul>Enhancement (FGE) or Stress Caging effects <br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />FGE -Increasing hoop stresses around the well bore by creating short stabilised fractures <br />
  19. 19. Conventional high-density completion fluids used in deep gas wells have a high cost of ownership <br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />
  20. 20. Software tool now available that calculates the full cost of owning and using high-density completion fluids <br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />Prices the full operational costs, waste costs and the cost of “incidents”<br />
  21. 21. Cost of fluid ownership <br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />BrineWise tool calculates all fluid ownership costs<br /><ul><li> Purchase /leasing fee
  22. 22. Transport onshore /offshore
  23. 23. Sub-optimal rig time
  24. 24. Well clean up time
  25. 25. Waste treatment and disposal
  26. 26. Stand-by time
  27. 27. Isolation and treatment of </li></ul> produced water <br /><ul><li> Production delays
  28. 28. Production handover delays
  29. 29. Liabilities and legal fees arising</li></ul> from splashes, spills, releases <br />Factors in damage caused to company reputation by incidents <br />
  30. 30. So.. do conventional WCF influence the economics of deep gas field developments ? <br /> Undoubtedly YES – conventional WCF have problems and influence economics by increasing overall development costs of deep gas fields <br /><ul><li> Lengthening the time taken to drill and complete
  31. 31. Creating well control and safety risks
  32. 32. Degrading well integrity/durability
  33. 33. Raising waste management costs and liabilities – i.e. high cost of</li></ul> ownership <br />...And if they are damaging to the formation they may <br />reduce the rate of revenue generation <br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />
  34. 34. How do you make a WCF that performs better under extreme conditions in deep gas wells ? <br />Remove the source of the problems <br /><ul><li>Remove the solid-weighting agents
  35. 35. Remove any halide salts (chlorides and bromides)
  36. 36. Preferably remove any hydrocarbons too (well control risk and logging issues) </li></ul>Formate brines developed by Shell Research, 1985-95 <br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />Density to SG 2.3 /19.2 ppg/143 pcf<br /> No solids <br /> No halides <br /> No hydrocarbons<br /> Anti-oxidant<br />Drilling, completion, workover and suspension fluids for deep gas wells <br />
  37. 37. 2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />1995 – Formate brines used for first time by Mobil to drill and work over deep gas wells, onshore, northern Germany <br />Walsrode field – onshore, high-angle slim hole wells Z1, Z5, Z6 and Z7 <br />TVD : 4,450-5,547 metres <br />Reservoir: Sandstone 0.1-125 mD<br />BHST : 315oF (157o C)<br />Section length: 345-650 metres <br />
  38. 38. Outcome of Mobil’s first drilling trials with formate brines in onshore deep gas wells - 1995/96<br />Absence of weighting solids has a clear impact on efficiency and<br /> economics 1,2<br />“Use of formate drilling fluid ….eliminated most of the previous hole problems<br /> ...resulted in a dramatic increase in drilling performance and hydraulics…<br />and significantly reduced well costs” <br />Low-solids drilling fluid concept appears to be validated <br />1)Sundermann, R. and Bungert, D.: “Potassium-Formate-Based Fluid Solves High Temperature Drill-In <br />Problem,” Journal of Petroleum Technology (November 1996) 1042<br />2) Bungert, D., Maikranz, S., Sundermann, R., Downs, J., Benton, W. and Dick, M.A.: “The Evolution and <br />Application of Formate Brines in High-Temperature/High-Pressure Operations”, IADC/SPE 59191, IADC/SPE <br />Drilling Conference, New Orleans, 23-25 February 2000.<br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />
  39. 39. Formate brines used by Mobil in 15 deep gas well constructions in northern Germany 1995-1999 (SPE 59191) <br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />
  40. 40. Huldra field, HP/HT gas condensate<br /><ul><li>BHST: 297oF
  41. 41. TVD : 3,900 metres/12,795 ft </li></ul>- Fluid density: 15.75 ppg/118 pcf <br />- 6 wells – 600 ft reservoir sections 5-7/8” at 45-55o<br />- 1–2,000 mD sandstone<br /><ul><li>Open hole, wire wrapped screens</li></ul>Justification for using formate<br />- Improve well control ! <br />- Lower ECD<br />- Run completion in same fluid <br />- Low risk of screen plugging <br />- Shale stabilisation <br />- Lubricating<br />- Safe for crews <br />- Environmentally benign<br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />2001 - Formate brines used for first time by Statoil to drill and complete 6 deep HPHT gas wells, offshore, Norway <br />Operator had experienced kicks when using barite-weighted fluids <br />
  42. 42. Outcome of Statoil’s first drilling trials with formate brines in offshore deep gas wells - 2001/02<br />Efficiencies and economies provided by drilling at depth with low-<br /> solids brine 1<br />“Stable hole, low ECD, good hole cleaning and stable fluid has led to rig time savings due to:<br /><ul><li>Fast tripping speed
  43. 43. Fast casing running speeds
  44. 44. Less mud conditioning and wiper trips than with conventional drilling fluids” </li></ul>Low-solids fluid enables faster well constructions at depth <br />1) Saasen, A., Jordal, O.H., Burkhead, D., Berg, P.C., Løklingholm, G., Pedersen, E.S., Turner, J. and Harris, M.J.:<br /> “Drilling HT/HP Wells Using a Cesium Formate Based Drilling Fluid,” IADC/SPE 74541, IADC/SPE Drilling <br />Conference, Dallas, 26-28 February 2002.<br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />
  45. 45. Deep and/or HPHT gas fields developed using formate brines as WCF 1995-2009<br />Author has good information on 35 fields <br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />
  46. 46. Formate brine used in > 140* deep and/or HPHT gas wells , 1995- present <br />Drilling, completion, workover, suspension and packer fluids <br />At densities up to SG 2.25 (18.7 ppg or 140.2 pcf) <br />At BHST up to 235oC (450oF) <br /> For periods of > 10 years dowhole (packer fluid applications) <br />In sandstone and carbonate reservoirs, 0.01 mD up to 4 Darcy <br />Wide variety of completions – barefoot open hole, cased and <br />perforated, with sand screens and gravel packs<br />* Actual field/well numbers will be greater – but some are not documented <br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />
  47. 47. Deep gas fields where formate brines have been used as WCF – segmented by operator <br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />
  48. 48. Formate brines used in the world’s largest HPHT gas field development – Elgin/Franklin <br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />Also the deepest HPHT gas field in North Sea <br />Cesium formate brine used by TOTAL in 34 well construction operations in 8 deep gas fields in period 1999-2009 <br />B <br />
  49. 49. Gaining an economic perspective – Scope of review <br />Collect and analyse user observations on operational well <br /> construction efficiencies <br />2) Look for examples of long-term production rates, for evidence<br /> of production efficiencies <br />Only examined Cs formate brine applications (more extreme conditions)<br />128 user observations extracted from 5 published field case histories<br />8-year production figures found for two HPHT gas fields drilled and <br />completed entirely with potassium/cesium formate brines <br />Observations on well construction efficiencies tend to be qualitative<br />rather than quantitative <br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />
  50. 50. Economic benefits from use of formate brines in deep gas field developments – Results of review <br />Operational efficiencies provide well construction cost reductions <br />Better drilling environment gives rig-time savings <br /> - Stable hole: see LWD vs. WL calipers in shale <br /> - Elimination of well control and stuck pipe incidents<br /> - Good hydraulics, low ECD<br /> - Good ROP in hard abrasive rocks <br />“ a remarkable record of zero well control incidents in all 15 <br />HPHT drilling operations and 20 HPHT completion operations” <br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />
  51. 51. Economic benefits from use of formate brines in deep gas field developments – Results of review <br />Operational efficiencies provide well construction cost reductions <br />2. Allowing faster and easier movements of tubulars and fluids <br /> - Pipe and casing running speeds are faster <br /> - Mud conditioning and flow-check times shorter <br /> - Displacements simplified, and sometimes eliminated <br /> (i.e. formate drilling fluid = formate completion fluid)<br />Quote by operator : “ Improved well economics by increasing trip speed” <br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />
  52. 52. Economic benefits from use of formate brines in deep gas field developments – Results of review <br />Operational efficiencies provide well construction cost reductions <br />3. Faster completions <br />HPHT gas well completion times<br />from the Rushmore database <br /><ul><li>Wells drilled with OBM vs</li></ul>cesium formate brine <br />Quote by operator : “ fastest HPHT completion operation ever performed in North Sea (12.7 days)” <br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />
  53. 53. Efficient delivery of gas reserves (revenues) <br />Tune and Huldra fields – drilled and completed with formate brines<br />90% recovery of reserves (16-18 billion m3) produced in 7 to 8 years<br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />Source : Norwegian Petroleum Directorate- Fact Pages - November 2009 <br />
  54. 54. Efficient delivery of condensate reserves (revenues) <br />Tune and Huldra fields – drilled and completed with formate brines<br />90% recovery of reserves (3-5 million m3) produced in 4 to 6 years<br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />Source : Norwegian Petroleum Directorate- Fact Pages - November 2009 <br />
  55. 55. Conclusion <br />Results of thisreview suggests that the use of formate brines in <br />deep gas field developments has reduced well construction times <br />and costs by : <br /><ul><li>Providing a better drilling environment
  56. 56. Allowing faster/easier movements of WCFand hardware
  57. 57. Allowing faster completions </li></ul>The non-damaging nature of formate brines may have contributed to<br /> the efficient production of recoverable hydrocarbon reserves from<br /> two HPHT gas/condensate fields examined in this study. <br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />
  58. 58. Footnote 1 <br />Results of independent Eco-efficiency study by BASF show that<br />cesium formate brine is the most sustainable high-density completion<br /> fluid <br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />Leasing of cesium formate brine encourages a sustainable approach <br />
  59. 59. Footnote 2 <br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />Good reservoir definition in cesium formate brine<br />“Using photoelectric factor and bulk density data, combined with resistivity measurements from both the LWD drill pass and the ream pass, produces a very reliable and consistent net reservoir definition.”<br />
  60. 60. Footnote 3 <br />2010 SPE Deep Gas Conference, Bahrain, 24-26 January<br />Good reservoir definition in cesium formate brine<br />“Applying a conductive drilling fluid in all production wells drilled in a field also provides the possibility of running high quality resistivity image logs (FMI). Extensive use of such logs provides the geo-modelers with detailed information regarding structural dip, depositional environment, sedimentary features, facies, and geological correlations.”<br />

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