Design and History Matching of Waterflood/Miscible CO 2 Flood Model of a Mature Field: The Wellman Unit, West Texas

1. Design and History Matching of Waterflood/Miscible CO2 Flood Model of a Mature Field: The Wellman Unit, West Texas by Jose Rojas Master of Science Candidate Chair of Advisory Committee: Dr. David Schechter Committee Members: Dr. Duane McVay and Dr. Luc Ikelle

2. Content • Research Objectives • Review of Geology • Historical Reservoir Performance • OOIP and Water Influx (Material Balance) • Simulation Model • Model Calibration – History Matching • Results: Primary Depletion • Waterflooding • CO2 Injection • Conclusions and Recommendations

3. Objectives Revise and integrate data from the reservoir description to develop a full field, three-dimensional black oil simulation model to reproduce via history matching, the historical performance of the reservoir under primary, secondary and tertiary stages of depletion Secondly, develop a calibrated model that can be used to evaluate, design and plan future reservoir management decisions.

4. Wellman Field Horseshoe Atoll Midland Review Of Geology Location • Terry county, TX, along the • Horseshoe Atoll reef complex that • developed in North Midland during • Pennsylvanian and early Permian • time

5. Pennsylvanian Cisco Reef Permian Wolfcamp Reef Review Of Geology Field is considered geologically unique, because it comprises two types of reef construction • Built in shallow muddy(turbid) water • Encroaching shales at the flank • Smaller cone-shape structure • Oil bearing • Built in deep clear water • Large mound shape structure • Strong depositional dip • Water bearing

6. Spraberry Sand Top of Wolfcamp • Structural Northeast – southwest cross section reveals the cone shaped • structure Review Of Geology Reef on Reef Depositional Model • Wolfcamp deposited on top of the prominent Cisco Reef • Curved layers at the bottom, more horizontal in upper structure

7. Structural Setting • Oval shaped covering a • productive area of 2100 acres • Two local highs (dual, cone-shaped • anticlinal structure) Lithology • Carbonate reservoir (skeletal • marine organisms) • Secondary Porosity to diagenesis • - Intercrystalline • - Vugular • - Natural Fractures Review Of Geology Isopach Structure Map

8. 1) 1950-53 oil rate peaked 6 MSTBD 4 2) 1954 allowable restrictions oil rate reduced to 3, then 1.7 MSTBD 1 3 3) 1966 oil rate peaked 8 MSTBD 5 4) 1976-79 produced below Pb until reached minimum 1,050 psig 2 5) 1976-79 GOR did not increase secondary gas cap formed. H2O cut: from 10 to 25% Pb at 1,248 PSI Historical Reservoir Performance Primary Depletion (1950 – 1979) Cum. Oil: 41.8 MMSTB RF: 34.6%

9. Waterflooding (1979 – 1983) 1979 - four flank H2O injectors re-pressurize (MMP), re-dissolve part of the gas, displace oil upward H2O H2O H2O Inj Inj Inj CO2 CO2 Inj Inj • Pressure increased from 1,050 to • 1,600 psig prior CO2 (1983) • Oil rate increased to 9 MSTBD OWOC OWOC OWOC • Water cut from 25 to 40% • GOR aprox. constant • Water cut controlled by plug • downs. Cum. Oil: 23.9 MMSTB Sec. RF: 19.5% Waterflooding Historical Reservoir Performance

10. 1983-89 - Three crestal injectors to displace oil downward and reduce Sor • 1984-89, CO2 Inj. From 5 to 15 • MMCFD. • 1985, break water cut from 40 to • 85%. (ESP’s, leaks, corrosion) • GOR peaked to 3000 SCF/STB • (mostly CO2) • Pressure from 1600 to 2,300 • peaked at 2,500 psig in 1994. Primary Depletion CO2 Injection Cum. Oil: 6.3 MMSTB Ter. RF: 5.4% Waterflooding Historical Reservoir Performance CO2 Injection (1983 – 1995)

11. Chronological Stages of Depletion

12. Havlena and Odeh • Validate existence and influence of external energy (aquifer) • Use performance data and fluid properties prior waterflooding • Lack of linearity • Not Volumetric • Most likely producing • under influence of an • aquifer OOIP and Water Influx Material Balance

13. OOIP and Water Influx Material Balance Hurst and Van Everdigen • Estimate and validate previous OOIP assessments • Estimate water influx rate prior waterflooding Results Final Aquifer Properties • OOIP (N) aprox 125 MMSTB • We10: approximately 8.0 MMRB

14. Simulation Model Full field, 3-D black oil simulation “Imex” – CMG Grid System • Use of flexible grids: corner point, • non - orthogonal geometry. • 27 x 27 gridblocks I,J direction • K, direction subdivided in 23 layers • based on porosity correlations • (geological description) • Total 16,767 gridblocks

15. Simulation Model 3D – Structure Development

16. Individual Static Bottom Hole Pressure Simulation Model Input Data Production data • Over 45 years of monthly cumulative oil, gas and water production from 47 • wells was converted into daily rate schedules for simulation • Model initially constrained by oil rates and water/CO2 injection rates Pressure data • Pressure measurements reveal good communication within the reservoir • Use of BHP corrected and averaged to a common mid-perforation • Static BHP seemed to be representative of the average reservoir pressure

17. Gross Thickness Porosity Net to Gross Ratio Simulation Model Input Data Isopach Maps • Use of isopach maps resulted from geological and petrophysical study in 1994 • Geological and stratigraphic correlation (Core vs Log data) • Quantify major rock properties • Lateral and areal continuity • 60 geological contoured maps from gross thickness, porosity and NTGR were • digitized • Interpolation between contour allows model to be populated

18. Simulation Model Input Data Permeability • Use previous estimates from correlations between open-hole logs and core • measurements K = 10^(0.167 * Core porosity – 0.537) Water Saturation

19. Initial Oil-Water and Gas Relative Permeability Simulation Model Input Data Fluid Properties • Use PVT properties contained in previous lab and reservoir studies • Bubble point: 1248 – 1300 psig • Rs, 400-500 SCF/STB • Oil Gravity, 43 API • OFVF, 1.30 RB/STB • Oil Viscosity, 0.4 cp • Black oil fluid type Relative Permeability • Special core analysis for core well No. 7-6 included measurements on only • two samples with a low non-representative permeability • Use functions derived from Honarpour’s correlation (past studies)

20. Data normalized by • Leverett J-function • Shape suggests lack of • capillary transition zone • Good vertical communication • capillary effect “not significant” Simulation Model Input Data Capillary Pressure Data • Only 4 samples, K > 1 md • (Special core analysis)

21. Tuning uncertain properties influencing the solution Via Sensitivity analysis simulation runs Model Calibration – History Matching • Objective: Validate the model adjusting the reservoir description until • dynamic model match the historical production and pressures • Weight and rank properties by level of uncertainty (quality, • source, amount, availability of data) Historical Responses to be Matched • Fieldwide average reservoir pressure • Fieldwide production rates • Fieldwide GOR and Water cut • Arrival times • Individual responses (lesser degree)

22. Results: Primary Depletion First simulation runs • No aquifer modeled • Poor pressure response • Need of external energy “recognized”

23. Fetkovich, “Analytical Aquifer” • First years not matched • Radius ratio, K and Ф Results: Primary Depletion Preliminary runs Aquifer Calibration • Carter and Tracy “Analytic” • MB case too strong (top) • Aquifer size (Ф,h), trans. (K,h) • Reference datum adjusted • Influx 20% greater, best case

24. Need for improvement was recognized ! • Secondary gas cap formed Results: Primary Depletion Preliminary runs • Water arrival time and cumulative • did not match • Highest corresponds to MB • Poorest corresponds “no aquifer” • Poorest corresponds “no aquifer” • Best pressure match “sharp gas • increase”

25. Most Uncertain Parameters influencing Production of Fluids • Vertical Transmissibility • Aquifer/reservoir • vertical arrays • Aquifer Properties • , h,k • Relative Permeability • Functions • end points, shape, crit. sat Model Calibration • Re-interpretation • Completion intervals • Plug-downs • GOR, water cut • cutoff Local Absolute (K) Lesser degree Uniform Mod. Fluid PVT “K.H” Term Prod / Inj Index Results: Primary Depletion

26. Results: Primary Depletion Diagnosis

27. Results: Primary Depletion Final Results

28. Results: Primary Depletion Final Results

29. Results: Waterflooding Injector Location • 4 producers converted • to water injectors (1979) • Located at the flank • forming a perimeter belt • Injection below and above • OWOC @ - 6,680 ft • Model primarily constrained • by historical injection rate • schedule

30. Adjustment Most Uncertain Parameters influencing Production of Fluids • Vertical Transmissibility • Aquifer/reservoir • vertical arrays • Aquifer Properties • , h,k • Relative Permeability • Functions • end points, shape, crit. sat Model Calibration • Re-interpretation • Completion intervals • Plug-downs • GOR, water cut • cutoff Local Absolute (K) Lesser degree • In spite of injecting the • correct volume of water • reservoir pressure continued • declining • Green, one of the best cases • from primary depletion match • Adjustment “KH” term of the • injectivity index to match constraint • Blue, same with water injectors • Injection rate and volumes matched Uniform Mod. Fluid PVT “K.H” Term Prod / Inj Index • Pressure continued declining • Water and gas exceeded • historical data (H2O: 47%) Results: Waterflooding Initial runs Fluid production needs to be controlled !

31. Voidage Replacement Ratio Results: Waterflooding Diagnosis Model Pressure Map

32. Numerical aquifer Results: Waterflooding Model Calibration for Final Pressure Match

33. Results: Waterflooding Model fluid match

34. 208 ft 210 ft (a) 1950 (b) 1979 (c) 1983 Results: Waterflooding WOC Movement

35. Results: CO2 Injection Miscible Displacement Highlights • Modification of the black oil sim. • Pseudo-miscible option with • no chase gas • Based on the “Todd and Long- • staff” theory • Modifies physical properties • and flow characteristics of • the miscible fluids • Requires definition of new param. • CO2 PVT prop., MMP, ωo(P)

36. Results: CO2 Injection Initial runs What is happening ? • Abnormal increase in reservoir pressure • VRR greater than 1, correlates with sharp pressure increase • VRR decreased (1992) correlating with decrease in pressure

37. Results: CO2 Injection Initial runs Solvent Rate Water Rate • Model is not able to reproduce rapid water rate increase (1986) • In 1986, insufficient water and solvent production results in • a dramatic increase in reservoir pressure

38. Kv areal distribution 2nd Relative permeability region Results: CO2 Injection Most Uncertain Parameters influencing Production of Fluids • Relative Permeability • Functions • end points, shape, crit. Sat • New set for middle reef • Account for ESP’s • Vertical Transmissibility • Aquifer/reservoir • vertical arrays • local refinements • Kv / Kh > 1 • Aquifer Properties • , h,k Model Calibration • Re-interpretation • Completion intervals • Plug-downs • Include wells high • on the struct. Local Absolute (K) Lesser degree Negative Skin Stimulations - Acidizing Uniform Mod. Fluid PVT “K.H” Term Prod / Inj Index

39. Identification of abnormal • individual performance • Fluid saturation distribution • Adjustment completion intervals Results: CO2 Injection Diagnosis / adjustments

40. Unsuccessful match after • extensive model calibration • Matching fluid production • more accurately is required! Results: CO2 Injection Sensitivity runs • Good pressure match “primary”. Lost • during waterflooding, poor at CO2 Inj. • Excess of H20 (waterflooding) • Overall insufficient water and solvent • production (tertiary), causing over- • pressurization.

41. Results: CO2 Injection Final match • Daily oil rate primary constraint • expanded to daily total liquid rate • (oil + water) • Match is preserved (primary, H2O Inj.) • Water and H2O breakthrough matched • Oil match sacrificed to match pressure

42. Results: CO2 Injection Final match

43. Chronological Stages of Depletion

45. Conclusions • Original fluids in place (according to simulation): • Oil: 127.1 MMSTB • Water: 139.0 MMSTB • Gas: 54.3 BSCF • Model OOIP, proved to be in close agreement not only with past estimations • but also with the analytical solution of the material balance technique • previously presented. 2. Cumulative water influx (8 MSTB) was estimated from application of the material balance theory and correlates quite well with water influx obtained in the “best case” being 8.5 MMSTB (first 10 years). • The natural aquifer greatly influenced production of fluids and consequentially, the predicted average reservoir pressure. 4. The initial set of aquifer parameters was derived analytically by the Hurst and Van Everdigen theory and finally tuned by sensitivity analysis

46. Conclusions Cont…. 5. The Carter and Tracy (analytic) method resulted as the best alternative to model the Cisco aquifer over the Fetkovich (analytic) and the numerical aquifer method. • The Cisco aquifer provided energy and supplied water that encroached • uniformly advancing the WOC 208 ft (prior to waterflooding) and an additional 210 feet (prior to CO2 injection) being in excellent agreement with field observations. • The use of a flexible grid system, honored the characteristic structure • of the cone-shaped double anticline. The distorted grid blocks • allowed a good representation of Wellman Unit geological features. • Historical water production and breakthrough times were identified as • one of the most difficult parameters to match and one that greatly influenced the behavior of the predicted reservoir pressure response.

47. Conclusions Cont…. • A complete pressure match was achieved through primary depletion, • waterflooding and CO2 injection, however the match on liquid production • was compromised in order to tune the final pressure match. • The results of this work provide the foundation for future research into • this hydraulically complicated reservoir

48. Recommendations for Future Work…. • More research is recommended on the geology of the field with the aim • of simplifying the total number of gridblocks, specifically the number of • layers (23) by the use of some of the upscaling methods in the literature. • Consider the use of pseudo-functions during simplification of the • existing model to increase the accuracy when modeling the production of • fluids. • Place additional effort to update the current model by incorporating • production and injection data from 1995 to the present time, thereby it • can be used to assist future reservoir management decisions.

49. Thanks! Everyone... Muchas Gracias a Todos......