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Eubank Field (Kansas) - A Formation Evaluation and Secondary Recovery Study

A comprehensive study on the primary recovery, waterflood feasibility, reservoir continuity, and interwell communication in the Eubank Field in Kansas. The study aims to estimate remaining oil-in-place, evaluate potential water injection well locations, and assess the feasibility of secondary recovery methods.

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Eubank Field (Kansas) - A Formation Evaluation and Secondary Recovery Study

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  1. Eubank Field (Kansas) - A Formation Evaluation and SecondaryRecovery Study Dominique Dexheimer Dr. Thomas A. Blasingame Associate Professor/Assistant Department Head Department of Petroleum Engineering Texas A&M University 12 August 1999

  2. Location of Eubank Field Eubank Field WYOMING IOWA NEBRASKA ILLINOIS UTAH COLORADO KANSAS MISSOURI OKLAHOMA ARKANSAS ARIZONA NEW MEXICO MISSISSIPPI TEXAS LOUISIANA

  3. Issues to be Addressed* • Primary recovery of old and new wells • Remaining oil-in-place/movable oil • Reservoir continuity/reservoir quality • Waterflood feasibility • Reservoir heterogeneity issues • Locations/patterns of water injection wells • Interwell communication via fractures * Terms of Reference—Anadarko Petroleum (April 1998)

  4. Key Findings • Oil-in-place (OIP) • Contacted: 13 million BBL • Movable: 5 million BBL • Remaining: 3 million BBL • Waterflood potential • 3 independent regions: North, South, West • The North region is best in terms of remaining reserves and reservoir quality • Locations/patterns of water injection wells

  5. North Region OIP Results Gregg 2 • OIP computed using production data • Radius of bubble proportional to the value of the variable shown • Wells with no "bubble" indicate that no production data are available • Contacted OIP distribution • North — 10 million BBL • South — 3 million BBL • West — 300,000 BBL West Region Permeability Barrier Moody A-1 Moody A-3 Permeability Barrier South Region

  6. North Region EUR/N Results West Region • EUR/N computed using production data • Note uniformity of EUR/N trends (average of 24 %) Permeability Barrier Permeability Barrier South Region

  7. Owens A-3 Doerksen A1-27 Waterflood Potential (kh, EUR/N) • Patterns developed using IQI, as well as natural flow barriers • IQI=(kh)x(EUR/N) • Predict recovery of 2 to 3 million BBL by waterflood • Almost certainly a low estimate • Repressuring will increase recovery Permeability Barrier (kh, EUR/N, location) Permeability Barrier Leslie 2-33 (kh, EUR/N, location) Leathers Land 1-10 (kh, EUR/N)

  8. Follow-Up (Anadarko) • Economics and Strategy • Must have Section 34 (T28S–R34W) • Water source/water quality • Assess risk involved in initiating and operating a waterflood project in this area • New data acquisition • Pressure transient tests • Geochemistry: source rock, migration • Additional work • Further geologic description of reservoirs • Reservoir simulation

  9. 5 Cores 130 ft cored — Owens A-3 Sidewall core data not used in correlations 53 Well logs 1 PVT sample (Owens A-2) 39 Pressure data 12 static bottomhole pressure tests 20 drill stem tests 5 pressure buildup tests 2 other wireline tests 25 Wellbore diagrams Drilling/Completion histories Stimulation treatments 43 Well production records 30 wells — oil allocated(2 wells had limited data) 10 wells — gas allocated 3 wells — unallocated Data Inventory — 55 Wells

  10. 1600 1400 1200 1000 800 600 400 Data Inventory Reservoir Pressure History MooA-1 Probable Data Trend for North Eubank Field and 95 % Confidence Interval South Eubank Field Ko1-28 Ko2-28 Su1-28 West Eubank Field Ko_A-4 Pressure, psia Clw1A9 GregF6 MooA-1 Greg_3 Clw1A9 Wr1-26 Su1-28 Legend u DrillStem Test n Static Bottomhole Pressure s Pressure Buildup Test RayC-2 OwnA-1 MooA-3 Clw3-9 Cl2-34 Do1-27 1960 1970 1980 1990 2000 Test date

  11. Legend Oil produced Gas Produced Reservoir Pressure 2 New Wells 8 New Wells 7 New Wells 2 New Wells 2 New Wells 2 New Wells Data Inventory Production History — Oil and GasNorth Eubank Field 5 2000 1800 4 1600 1400 3 Pressure Data Trend 1200 Np, MM BBL Gp, bscf Pressure, psia 1000 2 800 600 1 400 No production given prior to 1970 200 0 0 1960 1970 1990 1980 2000 Time, Years

  12. Legend Oil produced Gas Produced Reservoir Pressure 10 New Wells Data Inventory Production History — Oil and GasSouth Eubank Field 1.0 1800 Pressure Data Trend 1600 0.8 1400 1200 7 New Wells 0.6 Np, MM BBL Gp, bscf 1000 Pressure, psia Outlying pressure data: Clawson Well 3-34 800 0.4 600 400 0.2 200 0 0.0 1996 1997 1998 Time, Years

  13. Enabling Technologies/Data • Core Data (Owens A-3) • Core-Well Log data correlations • pc/kr correlations for effective permeability • Fluid Property Report (Owens A-2) • Well log analysis (53 Wells) • Field cross-section maps • Data used for well performance analysis • Decline type curve analysis (28 Wells) • Mapping/correlation of results

  14. Specific Objectives of this Work • Estimate rock and fluid properties • Estimate contacted and movable OIP • Estimate reservoir continuity • Horizontal flow capacity (koh) • Horizontal/Vertical flow barriers • Evaluate conditions for waterflooding • Reservoir pressure • Completion interval/contacted reserves • Identify potential water injection wells

  15. Results of this Work • Petrophysics • Distributions of rock properties • Core/Well log prediction of permeability • Well Performance Analysis • Distribution of computed variables • Bubble map of OIP and EUR/N • Correlation of volume and flow properties • Waterflood potential • Bubble map of "Injection Quality Index"

  16. Outline - Work Performed by Texas A&M • Geologic Description • Based on literature and Anadarko work • Well Log Analysis (53 wells) • Performed using Petra and SAS softwares • Oil Production Data Analysis (28 Wells) • WPA software • Integration of Results • Confirmed geologic flow model • Recommendations for waterflood • Conclusions

  17. 700 ft 9 miles Geologic Description Incised Chester Sand(from 3D seismic structure map) • 3 Producing intervals • Average depth: 5,500 ft • 55 wells drilled • 40 years of production • Np, tot = 2.4 million BBL • Gp, tot = 5.3 bscf • Light oil, sweet gas, water 100<h<300 ft

  18. Perforations Perforations Perforations Incised Chester Sand Geologic Description Schematic of Deposition in a Paleovalley Morrow Notch Sand 3 Shale 2 Sand 2 Shale 1 Sand 1 St. Louis

  19. SP SP SP SP ILD ILD ILD ILD Well Log Analysis Paleovalley Profile—Sample Cross-Section Owens A-3 Owens A-1 Owens A-2 Owens A-4 5300 Morrow Notch 5400 Basal Chester Sand 5500 St. Louis 5600

  20. Well Log Analysis Cluster Analysis (Owens A-3) ILD Log, Cluster Log, SPLog, no units Ohm-m mV 0 10 20 30 40 50 0 1 2 3 4 5 -200 -100 0 5300 Reservoir section is represented by "Cluster" 4 5400 5500 5600

  21. Well Log Analysis Porosity Distribution (from Well Logs) 15 14 Porosity Statistics Average Porosity 13 mean = 0.105 (fraction) Porosity Distribution Function 12 std dev = 0.022 11 10 9 8 Frequency 7 6 5 4 3 2 1 0 0.05 0.06 0.07 0.08 0.09 0.1 0.11 0.12 0.13 0.14 0.15 0.16 f Per-Well Average Porosity, , fraction

  22. Average Volume of Shale Volume of Shale Distribution Function Per-Well Average Volume of Shale, , fraction VSH Well Log Analysis Volume of Shale Distribution (from Well Logs) 16 14 12 Volume of Shale Statistics: mean = 0.082 (fraction) 10 std dev = 0.060 8 Frequency 6 4 2 0 0.04 0.12 0.16 0.08 0.24 0.2 0

  23. 14 Per-well Net Pay 12 Net Pay Distribution Function Net Pay Statistics: 10 mean = 20.00 ft std dev = 21.83 ft 8 Frequency 6 4 2 0 5 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90 95 10 Per-Well Net Pay, , ft h Well Log Analysis Net Pay Distribution (from Well Logs)

  24. k = 0.2777exp(37.75) 0.00 0.05 0.10 0.15 0.20 0.25 R2= 0.82 Well Log Analysis Core Porosity—Core Permeability Relationship(Owens A-3) 104 Data Trend and 95 % confidence interval 103 102 Core Permeability,k, md 101 100 10 -1 Core Porosity,  , fraction

  25. 5380 5400 5420 5440 5460 kobs kcal 5480 5500 5520 5540 10-1 100 101 102 103 Well Log Analysis Owens A-3 Core Permeability-Well Log Data Correlation • Tried several models • 3 to 5 well log variables • SP, GR • ILD • NPHI, DPHI, PHIDN True Vertical Depth, ft Legend • "Best" permeability model • Valid for 10<k<200 md • 4 variables (GR, ILD, NPHI, DPHI) • Stable predictor for 45 cases Permeability, md

  26. Well Performance Analysis • Data Required: • Time, pressure, rate (TPR) data • Initial reservoir pressure • Reservoir and fluid properties • How used: • Data edit plot (remove off-trend values) • Decline type curve match • EUR plot • Results: • Flow parameters (kh, s, xf) • Volumetric parameters (N, A)

  27. 103 Reservoir Pressure  1000 psia (1986) Gas 102 Flow Rates, BBL/D, Mscf/D Oil 101 Water 100 1985 1988 1991 1994 1997 Production Time, Years Well Performance Analysis Production Data Plot (Moody A-3)

  28. 100 qo/Dp, BBL/D/psia 10-1 10-2 102 103 104 105 Np/qo, Days Well Performance Analysis "Data Edit" Plot Moody A- 3 • Only oil cases are relevant for this field • "Data Edit" Plot used to Remove Off-Trend Data

  29. Well Performance Analysis "WPA" Plot (Used to Perform Type Curve Analysis)Moody A-3 1 10 12 7 4 7 4 12 28 18 80 48 800 160 0 1x104 10 qDdi 80 48 28 18 12 7 4 Dimensionless Rate Functions (qDd, qDdi, qDdid) 160 -1 10 800 qDdid qDd -2 10 -3 -2 -1 0 1 2 10 10 10 10 10 10 Dimensionless Material Balance Time, tDd, days

  30. 0.35 0.30 0.25 0.20 q/Dp, BBL/D/psia 0.15 0.10 0.05 0.00 0 100,000 200,000 300,000 400,000 500,000 600,000 Np, BBL Well Performance Analysis Estimated Ultimate Recovery (EUR) Plot Moody A-3 Estimated Primary Movable Oil: 520,000 BBL

  31. 103 Reservoir Pressure  770 psia (1995) Gas 102 Flow rates, BBL/D, Mscf/D Oil 101 100 1996 1997 1998 Production Time, Months Well Performance Analysis Production Data Plot Owens A-2

  32. 100 q/Dp, BBL/D/psia 10-1 10-2 101 102 103 104 Np/q, Days Well Performance Analysis "Data Edit" Plot Owens A-2 • A unique trend is identified on the plot • Approach tolerates incomplete data

  33. Well Performance Analysis "WPA" Plot (Used to Perform Type Curve Analysis)Owens A-2 1 10 12 7 4 7 4 12 28 18 80 48 800 160 0 1x104 10 qDdi 80 48 28 18 12 7 4 Dimensionless Rate Functions (qDd, qDdi, qDdid) 160 -1 10 800 qDdid qDd -2 10 -3 -2 -1 0 1 2 10 10 10 10 10 10 Dimensionless Total Material Balance Time, tDd, days

  34. 0.250 0.200 0.150 q/Dp, BBL/D/psia 0.100 0.050 0.000 0 10,000 20,000 30,000 40,000 50,000 60,000 Np, BBL Well Performance Analysis Estimated Ultimate Recovery (EUR) Plot Owens A-2 Estimated Primary Movable Oil : 51,500 BBL

  35. Well Performance Analysis Skin Factor Distribution(from Well Performance Analysis) 9 Skin Factor Statistics: Mean = -2.5 Std. Dev. = 1.4 Skin Factor Data Skin Factor Distribution Function 8 7 6 5 Frequency 4 3 2 1 0 -7 -6 -5 -4 -3 -2 -1 0 1 2 Skin Factor, s , Dimensionless

  36. Well Performance Analysis Flow Capacity (koh) Distribution(from Well Performance Analysis) 7 koh Data koh Distribution Function 6 koh distribution Statistics: Mean = 50 md-ft 5 4 Frequency 3 2 1 0 400 0 25 50 75 100 125 150 175 200 225 250 275 300 325 350 375 Flow Capacity, koh, md-ft

  37. 8 Fracture Half-Length Data Fracture Half-Length Statistics: Mean = 26 ft FractureHalf-Length Distribution Function 7 6 5 Frequency 4 3 2 1 0 2.1 6.6 44.0 93.8 137.0 200.0 1.0 9.7 64.3 1.5 3.1 4.5 14.1 20.6 30.1 Fracture Half Length, xf, ft Well Performance Analysis Fracture Half-Length Distribution (from Well Performance Analysis)

  38. Integration of Results: Outline • Petrophysical Data • Geologic structure and continuity • Prediction of effective permeability • Well Performance Analysis • Pressure history (used to initialize analysis) • Correlation of koh and N (consistency) • Correlation of EUR and N (primary recovery) • Evaluation for Waterflood • Injection criteria (reservoir properties) • Locations of candidate wells for injection

  39. Integration of Results North Region Geologic Structure/Continuity West Region • 3 independent regions • North, main region • South and dry Southeast tributary • West, minor region • Origin of permeability barriers • Depositional sequences • Block faulting • Morphology of channel • Fluid migration Permeability Barrier Permeability Barrier South Region

  40. Integration of Results Comparison of Effective Permeabilities • Additional Input for koh from well log correlation: • Capillary pressure data • Gas-Oil ratio (3 month avg.) • Comparison on available data (15 Wells) • Reasonable agreement • Divergence due to different depths of investigation • Data shift by a factor of 10 103 LTHA-3 MURD-3 LTHA-2 RAYC-2 OWNA-4 LS2-33 GREGF6 COLA-3 Data trend? TILA-2 102 OWNA-1 TILA-1 DO1-27 KO_A-4 koh (Core-Well Logs Correlation), md-ft MURD-4 RAYC-4 101 100 100 101 102 103 koh (Production Data Analysis), md-ft

  41. North Region Integration of Results Gregg 2 • Contacted OIP distribution • North — 10 million BBL • South — 3 million BBL • West — 300,000 BBL • Remaining movable oil • North — 2 million BBL • South — 625,000 BBL • West — 50,000 BBL • 3 major wells (Np) • Moody A-1 — 235,000 BBL • Moody A-3 — 370,000 BBL • Gregg 2 — 235,000 BBL West Region Permeability Barrier Moody A-1 Moody A-3 Permeability Barrier South Region

  42. 1600 MooA-1 Probable Data Trend for North Eubank Field and 95 % Confidence Interval South Eubank Field 1400 Ko1-28 Ko2-28 Su1-28 1200 West Eubank Field Ko_A-4 Pressure, psia Clw1A9 GregF6 1000 MooA-1 Greg_3 Clw1A9 Wr1-26 800 Su1-28 Legend u DrillStem Tests n Static Bottom Hole Pressure s Pressure Buildup Tests RayC-2 OwnA-1 MooA-3 Clw3-9 Cl2-34 Do1-27 600 1960 1970 1980 1990 2000 400 Test date Integration of Results Reservoir Pressure History

  43. Integration of Results Flow Capacity (kh) versus Contacted Oil-in-Place, N • The range of kh-values is uniform, but the spread of N-values has a disconti-nuity caused by differen-tial depletion • Differential depletion is accentuated by pressure declining well below the bubblepoint pressure • The difference between estimated volumes of contacted oil (new and old wells) suggests significant waterflood potential 103 Legend u North Eubank Field ¬ kh = 6 ´10-4N s West Eubank Field DO1-27 n South Eubank Field OWNA-3 1990 OWNA-2 TILA-1 1995 1995 TILA-2 LTHA-3 "New Wells" LTHA-2 1995 RAYC-5 MOOA-1 KO_A-4 1995 MOOA-3 1996 OWNA-4 102 1996 OWNA-1 RAYC-2 1996 1961 1996 1985 1996 1995 1996 RAYC-4 LS2-33 COLA-3 GREGF6 GREG_2 1996 SU2-28 1996 RAYC-3 LS1-33 1996 1996 "Old Wells" 1959 1997 1996 1996 Flow Capacity, koh, md-ft MURD-3 RMRC-2 WR1-26 1997 1964 Incomplete Data 1991 ¬ kh =5 ´10-5N RMRC-1 101 1964 MU1-34 MURD-4 Note Format: Well Code s Completion Date 1985 1997 100 104 105 106 107 Contacted Oil-in-Place, N, STB

  44. Integration of Results Contacted Oil-in-Place (N) versus Estimated Ultimate Recovery (EUR) • Excellent agreement in the computed N and EUR-values • Primary recovery of 24 percent (average for the entire field) • Note that the "old" wells clearly have higher N and EUR—which also vali-dates the "differential depletion" concept 107 Legend u North Eubank Field s West Eubank Field n South Eubank Field MOOA-1 "Old Wells" 1961 MOOA-3 GREG_2 1985 N = 4.2 EUR 1959 106 DO1-27 RMRC-2 OWNA-3 TILA-2 TILA-1 Contacted Oil-in-Place, N, STB 1990 KO_A-4 LTHA-3 1964 1995 LTHA-2 1995 1995 OWNA-4 1996 "New Wells" 1996 1996 OWNA-2 OWNA-1 1996 RAYC-5 1995 1995 COLA-3 105 RAYC-3 MURD-3 RAYC-2 LS2-33 1996 SU2-28 MU1-34 1996 1997 1996 1996 1996 1997 1985 WR1-26 RAYC-4 Note Format: Well Code s Completion Date GREGF6 LS1-33 1991 1996 1996 1996 MURD-4 Incomplete Data 1997 RMRC-1 104 1964 103 104 105 106 Estimated Ultimate Recovery, EUR, STB

  45. Integration of Results Injection Well Criteria • Potential injectors must simultaneously maximize • Access to flow capacity, koh • Primary recovery, EUR/N • Candidates appear on the top right corner of the plot • Criteria to be combined with well locations taken from field maps 0.45 North Region 0.40 COLA-3 0.35 OWNA-1 TILA-2 MOOA-3 0.30 DO1-27 OWNA-2 RAYC-2 TILA-1 OWNA-3 WR1-26 RMRC-2 0.25 RAYC-5 RAYC-4 EUR/N, fraction RAYC-3 OWNA-4 0.20 GREG_2 0.15 RMRC-1 0.10 MOOA-1 0.05 0.00 100 101 102 103 Flow capacity, koh, md-ft

  46. Integration of Results Injection Well Criteria • South and west regions have fewer injection wells based on reservoir quality and movable oil • Alternative injection well locations (green oval) are taken from field maps and the IQI criteria 0.35 South and West Regions 0.30 MURD-3 MU1-34 0.25 LS1-33 LTHA-2 KO_A-4 MURD-4 GREGF6 LS2-33 0.20 EUR/N, fraction SU2-28 0.15 0.10 LTHA-3 0.05 0.00 100 101 102 103 Flow capacity, koh, md-ft

  47. Owens A-3 Doerksen A1-27 Integration of Results (kh, EUR/N) • Patterns developed using IQI, as well as natural flow barriers • Predict recovery of 2 to 3 million BBL by waterflood—from Anadarko study (esti-mate of total recovery) • Flow barriers are well-defined by pressure data • Repressuring should increase recovery Permeability Barrier (kh, EUR/N, location) Permeability Barrier Leslie 2-33 (kh, EUR/N, location) Leathers Land 1-10 (kh, EUR/N)

  48. Integration of Results: Closure • Injection Quality Index, khEUR/N • Limited to available well performance data • Criteria focuses on flow capacity (koh), as well as regions that were well swept (high EUR/N) • Criteria provides optimal sweep of oil to production wells • Well completions • Efficiency of hydraulic fracture is an issue • Interwell communication (fractures, high k zones)

  49. Conclusions • Well log analysis provides comprehensive description of the reservoir • Porosity, shale content, net pay • Approach of core-log permeability correlation • Type curve analysis is a robust tool • Volumetric estimates • Flow parameters • Waterflood potential based on IQI criteria • Injectors location/pattern • Sweep efficiency

  50. Conclusions • Three independent regions (contacted OIP) • North — 75 % of the field reserves (10 MM BBL) • South — 23 % of the field reserves (3 MM BBL) • West — 2 % of the field reserves (300,000 BBL) • Target OIP is 5 million BBL • Primary — 3 MM BBL (24 percent) • Secondary — 2 MM BBL (16 percent)

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