Using Quick Reservoir Simulation to Make Better Drilling, Completion, and Reservoir Management Decisions in Petroleum Re

1. Using Quick Reservoir Simulation to Make Better Drilling, Completion, and Reservoir Management Decisions in Petroleum Reservoirs Jim Buchwalter President, Gemini Solutions 281-238-5252

2. Outline Simulation review Cradle to grave applications for quick modeling Include steps showing quick model construction work flows in most simulators today

3. Simulation Overview Theory Accuracy Data required Comparison to other reservoir analysis approaches Simulation work flows and tools now versus 20 years ago

4. Theory Darcy�s Law for flow in a porous media Flow proportional to pressures drop and inversely proportional to distance for flow Law of conservation In � Out [=] Accumulation PV = NRT

5. Accuracy Simulation always gives the wrong answer At minimum the geology is always wrong in some respects Simulation gives a very accurate answer for the reservoir described The best answer possible for the data as we know it today

6. Minimum Data Required No magic data !! Structure maps Well properties � porosity/thickness / completion intervals Fluid stock tank gravities and gas-oil ratio�s Temperature & pressure Starting contacts Well production and pressure information

7. Comparison to Other Approaches Simulation integrates data from all geological and engineering sources Log analysis Petrophysical analysis Well test analysis Material balance PVT analysis Production and pressure Simulation infers unknown data and corrects inconsistent data For example, infers porosity to match well rates and pressures

8. Field Pilots versus Simulation Field pilot Disadvantages Cost of wells is enormous One shot proposition Do not know results for years Advantages It is real! Simulation Advantages Cost is very small to drill wells Can try many different development strategies and identify best strategy Results in seconds to minutes Disadvantages Results are approximate

9. Simulation Today and 20 Years Ago 20-30 years ago Simulation took months to years for one reservoir Key word driven interfaces Difficult work flows integrating maps and nodal analysis Expert users and long time frames Not applicable for most assets and real time reservoir management Applied to top 5% of all assets or less Assets with long lead times before development Larger assets and most assets had good permeability Good economics with or without simulation Today Models constructed in minutes to hours to days by everyday engineers Modern interfaces greatly facilitate work flows Mapping and nodal analysis seamlessly integrated Real time reservoir management possible Smaller offshore and tight reservoirs are the norm Require optimal development to be economic

10. Single Well/Pattern vs. Full Field Models Complex offshore fields Single well/pattern models answer near well bore questions Optimize completion interval and minimize water/gas coning Well skin Compression Full field models required to understand: Complex aquifer modeling Well to well interference Dip, rock property variation, and compartmentalization Tight assets and flat reservoirs Single well/pattern models answers most questions Accurate near well bore physics including coning + fractures Well to well interference included in pattern models

11. Cradle to Grave Reservoir Management With Quick Simulation

12. Simulation Applications in the Life Cycle Wildcat study before the first well is drilled Optimal step out well positioning for new discovery Optimal development strategy taking into account reservoir uncertainties Accurate reserves and proper infill well positions for maximizing value Identification of bypassed reserves in mature assets

13. 1 - Wildcat Before the First Well is DrilledSouth American Deep Onshore Oil Discovery

14. Wildcat Study Before Drilling the First Well Wildcat drilled Oil well was drilled to 18000 ft. in South America Well cost [=] $35 MM Tested 3400 BOPD , 24 hour test 21 API oil & 295 F Sand face estimated abandonment pressure [=] 1200 psi Assumed recovery factor [=] 15% from offset Offset analogy reservoir 10,000 ft. Same horizon PVT 23 API oil 5 CP viscosity 168 F Sand face abandonment pressure = 500 psi

15. Offset Reservoir Performance Versus Wildcat Using Simulator Offset � 320 spacing 3.8 MMBO in 28 years 15% recovery factor Wildcat � 320 acres 1.6 MMBO 4% recovery factor

16. Why? Recovery in wildcat was sensitive to abandonment pressure Abandonment pressure must be below the bubble point pressure [=] 1079 psi 1200 psi recovers 1.6 MMBO 800 psi recovers 6.3 MMBO 500 psi recovers 6.4 MMBO

17. Result of Study Bottom hole pump was not possible due to high reservoir temperature Reservoir abandoned due to high well cost and low per well recovery

18. Lessons Learned Do not wait to study reservoirs Pre-drill studies add value A pre drill study would show the reservoir was likely uneconomic Simple single well models can answer many questions Use simulation to guide data gathering to better understand uncertainties and their impact on economics Economic development required: Sizable accumulation and either: Higher bubble point pressure/ gas-oil ratio than anticipated Pump and lower abandonment pressure

19. 2- Optimal Step Out Well PositionInternational offshore oil discovery with aquifer and gas cap

20. Reservoir Problem Two discovery wells drilled Lowest proved oil-water contacts identified Where should the next wells be drilled? Spill point contacts shown below Highest known water limit

21. Simulation Work Flow Build a full field model Determine optimal well positions, drilling trajectory, and recovery factors for different possible oil-water contacts Properly placed horizontal wells in oil column recover 15-20% OIP Vertical wells recover 2% OIP Identify optimal step out wildcat well positions to prove the prospect economic

22. Lessons Learned Simulation maximizes data gathering value and minimize costs Reduce exploration costs by drilling wildcat step out wells at optimal well positions Simulation allows development of smaller prospects that could not otherwise be developed Here the recovery factor is very sensitive to well position and completion Horizontal well technology required

23. 3- Optimal Development Strategy Taking into Account Reservoir UncertaintiesBlack Widow Oil Field, GOM SPE 53980 - Time Critical Decision Making Using PC-Based Reservoir Simulation

24. Problem Black Widow Mariner discovery well drilled in 2000 29 feet of pay discovered Half the net pay count anticipated Mariner cannot decide if prospect is economic with lower pay count and uncertainties including: Aquifer strength Permeability Rock compressibility Fault seal Rig to be placed on stand by and prospect abandoned by noon the next day A simulation study within 4 hours required to determine if the prospect is economic Rig + other costs - $200K per day

25. Work Flow Full field model built in 2-3 hours 2 sensitivities completed 8 what if cases constructed at Mariner the next morning All but one were economic Decision to develop Black Widow made

26. Result � 11 MMBO Oil produced to date

27. Lessons Learned The less you understand a reservoir the more value simulation can add Understand reservoir uncertainties and impact on economics By the time you understand a reservoir you have spent most of the monies and simulation is of far less value Or lost an opportunity

28. 3- Optimal Development Strategy Taking into Account Reservoir UncertaintiesLarge offshore gas reservoir with aquifer influx

29. Problem Large offshore gas reservoir Influence of rock property heterogeneity on optimal well positions and reservoir recovery factors required Influence of reservoir heterogeneity on premature water influx

30. Work Completed Complex geostatistic grids created for all rock properties Large simulation model constructed to accommodate the complex geostatistic grids Months required to generate geostatistic maps and build a larger complex model

31. Results of Modeling Reservoir heterogeneity had small influence on water movement Rock compressibility and its impact on aquifer influx was far more important the reservoir heterogeneity Man months of work could have been avoided building complex geology and a large full field model Alternative equivalent model constructed in days Homogeneous rock properties Reservoir heterogeneity represented by increasing residual gas saturation to water Variable rock compressibility

32. Lessons Learned Bigger is not always better Start simple and then add complexities once the variables that impact the reservoir development understood Reservoir heterogeneity had a small impact on reservoir development and NPV Rock compressibility has a large influence on optimal well positions, reservoir recovery factor, and economics A coarse full field model constructed in hours was adequate

33. 4- Accurate Reserves and Optimal Infill Well Positions for Producing AssetsInclude a typical quick simulation work flow

34. Problem Description Optimal well positioning and staged fracture spacing required for a large tight gas well development

35. Starting Data 11000 feet reservoir 110 feet pay Perm [=] 7.4E-4 Md 6% porosity 275F 0.6 gravity gas 30% water saturation Horizontal well development with staged fractures 350 ft half length .010 ft 10 Darcy permeability 10 stages Production & tubing head pressures to match

36. Model Construction Steps

37. Step 1 � enter rock properties

38. Step 2 � grid construction Horizontal well setup 4000 feet 10 stages 640/320/160 down spacing with time 300 ft half length

39. Step 3 - PVT & Kr Correlations

40. Step 4 � Well completion times, target rates, minimum well head pressure, completion intervals

41. Step 5 � Enter historical pressures and rates to match

42. Step 6 � Run model Model tubing pressures do not match historical tubing pressures

43. Step 7 � Set up assisted history match parameters and match rates and pressures Match tubing pressures Vary rock porosity to get correct pore volume Vary fracture half length Vary rock permeability Vary all parameters simultaneously

44. Step 8 � run assisted history match 32 runs & 10 minutes Match Historical points are squares Starting model in green Matched model in blue Comparable match takes days and required hundreds of runs without this tool

45. Step 9 � Run additional forecasts and optimize well/field development strategy Sensitivity to fracture and well spacing Run economics on all cases and determine optimal development strategy to maximize NPV

46. Lessons Learned Simulation is the best technology for optimal well spacing and completion technique SPE 75708 - Paul McKinney, Jay Rushing @ Anadarko Carthage Field, Panola County, Texas Single well infill well optimization is fast One hour or less per well Simulation adds most value to marginal assets Tight assets uneconomic if not developed optimally 3 fold increase in NPV for Carthage Field

47. 4- Accurate Reserves and Optimal Infill Well Positions for Producing AssetsLarge offshore international reservoir

48. Background Large detailed model constructed over 2+ years for an international offshore prospect by a major by a team of several engineers and geologists After 30 months of production the model shows serious production shortcomings A quick model was constructed in one week that showed in place hydrocarbons and reserves were about 40% higher

49. Match + Reservoir Ternary View

50. Why? 12 months into the original study the geology was revised Because it took the team several months to incorporate the previous geology there was not enough time to incorporate the new geology and finish the study in time Study was completed with the wrong geology

51. Lesson Learned All models are wrong � a more complex wrong model is not the goal of simulation The goal is to have the best model that can be adjusted continually to incorporate new data and improve the reservoir description

52. 5- Identification of Reserves in a Mature AssetGOM reservoir overlying a salt dome

53. Background Presented by Steve Tobias several years ago at this forum Large mature oil asset acquired by company B from company A Technical staff from company A released All information except log data, production records, and raw seismic data were lost in the process 3 platforms, 50+ wells Current production rate approaching field economic limit

54. Goals Create maps from 3D seismic Build models for 50+ reservoirs in 5 major horizons and history match all recorded production and pressures Adjust geology as needed to match production in the simulator Identify workover and infill drilling potential � if any

55. Study Accomplishments5 MMBO + 23 Bcf in new reserves identified

56. Lessons learned Integrating 3D seismic technology with reservoir simulation in complex mature assets almost always finds reserves 1+1 [=] 4 Neither discipline by itself can identify these reserves

57. Conclusions Simulation is the best tool available for optimally developing reservoirs Reservoirs are as complex as people are different The tools available in most simulators allow models to be be built and history matched in minutes to hours to days Technology is accessible to the everyday engineer Single well models that take less than one hour are adequate for optimizing many fields Simple full field models can be built in hours to days and provide a 75-90% answer

58. Conclusions Simulation adds value to every step of the reservoir life cycle Add no more complexity that the starting data justifies Nothing had added more value to simulation results over the last 20 years than geostatistics Nothing is more abused in simulation than geostatistics All simulators for new assets are wrong A simple model that can be modified continually as new data becomes available to improve the model description is paramount

59. Using Quick Reservoir Simulation to Make Better Drilling, Completion, and Reservoir Management Decisions in Petroleum Reservoirs Jim Buchwalter President, Gemini Solutions 281-238-5252