Eubank Field Kansas A Formation Evaluation and Secondary

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

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

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

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

North Region OIP Results l OIP computed using production data n n l 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 n North South West — 10 million BBL — 300, 000 BBL Gregg 2 West Region Permeability Barrier Moody A-1 Moody A-3 Permeability Barrier South Region 5

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

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

Follow-Up (Anadarko) l Economics and Strategy Must have Section 34 (T 28 S–R 34 W) n Water source/water quality n Assess risk involved in initiating and operating a waterflood project in this area n l New data acquisition Pressure transient tests n Geochemistry: source rock, migration n l Additional work Further geologic description of reservoirs n Reservoir simulation n 8

Data Inventory — 55 Wells l 5 Cores n n l l l 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 n n 12 static bottomhole pressure tests 20 drill stem tests 5 pressure buildup tests 2 other wireline tests l 25 Wellbore diagrams n n l Drilling/Completion histories Stimulation treatments 43 Well production records n n n 30 wells — oil allocated (2 wells had limited data) 10 wells — gas allocated 3 wells — unallocated 9

Data Inventory Reservoir Pressure History 1600 Moo. A-1 1400 Probable Data Trend for North Eubank Field and 95 % Confidence Interval South Eubank Field Ko 1 -28 Ko 2 -28 West Eubank Field 1200 1000 Greg_3 800 Moo. A-3 u Drill Stem Test n Static Bottomhole Pressure s Pressure Buildup Test Su 1 -28 Ray. C-2 Own. A-1 Test date 2000 1990 Clw 3 -9 Cl 2 -34 Do 1 -27 1980 1970 0 400 Clw 1 A 9 Wr 1 -26 Legend 600 Ko_A-4 Clw 1 A 9 Greg. F 6 Moo. A-1 1960 Pressure, psia Su 1 -28 10

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

Data Inventory Production History — Oil and Gas South Eubank Field 1. 0 1800 Pres sure Data 1600 Tren d 1400 0. 6 Pressure, psia 1200 7 New Wells 1000 Outlying pressure data: Clawson Well 3 -34 0. 4 800 600 10 New Wells Legend 200 Time, Years 1998 0 1997 0. 0 400 Oil produced Gas Produced Reservoir Pressure 0. 2 1996 Np, MM BBL Gp, bscf 0. 8 12

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

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

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

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

Geologic Description Incised Chester Sand (from 3 D seismic structure map) l l 3 Producing intervals Average depth: 5, 500 ft 55 wells drilled 40 years of production n n l 700 ft 9 miles 100<h<300 ft Np, tot = 2. 4 million BBL Gp, tot = 5. 3 bscf Light oil, sweet gas, water 17

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

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

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

Well Log Analysis Frequency Porosity Distribution (from Well Logs) 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 0 Porosity Statistics mean = 0. 105 (fraction) std dev = 0. 022 0. 05 0. 06 0. 07 Average Porosity Distribution Function 0. 08 0. 09 0. 11 Per-Well Average Porosity, 0. 12 f 0. 13 0. 14 0. 15 0. 16 , fraction 21

Well Log Analysis Volume of Shale Distribution (from Well Logs) 16 Average Volume of Shale 14 Volume of Shale Distribution Function 12 Volume of Shale Statistics: mean Frequency 10 = 0. 082 (fraction) std dev = 0. 060 8 6 4 2 0 0 0. 04 0. 08 0. 12 0. 16 0. 24 Per-Well Average Volume of Shale, VSH , fraction 22

Well Log Analysis Net Pay Distribution (from Well Logs) 14 Per-well Net Pay Distribution Function 12 Net Pay Statistics: mean = 20. 00 ft std dev = 21. 83 ft 8 6 4 2 Per-Well Net Pay, 95 90 85 80 75 70 65 60 55 50 45 40 35 30 25 20 15 10 0 5 Frequency 10 h , ft 23

Well Log Analysis Core Porosity—Core Permeability Relationship (Owens A-3) Core Permeability, k, md 104 Data Trend and 95 % confidence interval 103 102 101 k = 0. 2777 exp(37. 75 ) R 2= 0. 82 100 10 -1 0. 00 0. 05 0. 10 0. 15 Core Porosity, , fraction 0. 20 0. 25 24

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

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

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

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

Well Performance Analysis "WPA" Plot (Used to Perform Type Curve Analysis) Moody A-3 1 Dimensionless Rate Functions (q. Dd, q. Ddid) 10 0 10 12 7 7 4 12 28 18 80 48 800 160 1 x 104 80 160 10 -1 4 48 28 18 12 7 q. Ddi 4 800 q. Ddid 10 q. Dd -2 10 -3 10 -2 10 -1 10 0 10 1 10 2 Dimensionless Material Balance Time, t. Dd, days 29

Well Performance Analysis Estimated Ultimate Recovery (EUR) Plot Moody A-3 0. 35 Estimated Primary Movable Oil: 520, 000 BBL q/Dp, BBL/D/psia 0. 30 0. 25 0. 20 0. 15 0. 10 0. 05 0. 00 0 100, 000 200, 000 300, 000 Np, BBL 400, 000 500, 000 600, 000 30

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

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

Well Performance Analysis "WPA" Plot (Used to Perform Type Curve Analysis) Owens A-2 1 Dimensionless Rate Functions (q. Dd, q. Ddid) 10 0 10 12 7 7 4 12 28 18 80 48 800 160 1 x 104 80 160 10 -1 4 48 28 18 12 7 q. Ddi 4 800 q. Ddid 10 q. Dd -2 10 -3 10 -2 10 -1 10 0 10 1 10 2 Dimensionless Total Material Balance Time, t. Dd, days 33

Well Performance Analysis Estimated Ultimate Recovery (EUR) Plot Owens A-2 0. 250 Estimated Primary Movable Oil : 51, 500 BBL q/Dp, BBL/D/psia 0. 200 0. 150 0. 100 0. 050 0. 000 0 10, 000 20, 000 30, 000 Np, BBL 40, 000 50, 000 60, 000 34

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

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 Frequency 5 4 3 2 1 0 0 25 50 75 100 125 150 175 200 225 Flow Capacity, koh, md-ft 250 275 300 325 350 375 400 36

Well Performance Analysis Fracture Half-Length Distribution (from Well Performance Analysis) 8 Fracture Half-Length Data Fracture Half-Length Distribution Function 7 Fracture Half-Length Statistics: Mean = 26 ft 5 4 3 2 200. 0 93. 8 64. 3 44. 0 30. 1 20. 6 14. 1 9. 7 6. 6 4. 5 3. 1 2. 1 1. 5 0 137. 0 1 1. 0 Frequency 6 Fracture Half Length, xf, ft 37

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

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

l Additional Input for koh from well log correlation: n n l Capillary pressure data Gas-Oil ratio (3 month avg. ) Comparison on available data (15 Wells) n n n Reasonable agreement Divergence due to different depths of investigation Data shift by a factor of 10 koh (Core-Well Logs Correlation), md-ft Integration of Results Comparison of Effective Permeabilities 103 LTHA-2 RAYC-2 OWNA-4 LS 2 -33 MURD-3 102 Data trend? GREGF 6 COLA-3 TILA-2 OWNA-1 TILA-1 KO_A-4 DO 1 -27 MURD-4 RAYC-4 101 100 101 102 103 koh (Production Data Analysis), md-ft 40

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

Integration of Results Reservoir Pressure History 1600 Moo. A-1 1400 Probable Data Trend for North Eubank Field and 95 % Confidence Interval South Eubank Field Ko 1 -28 Ko 2 -28 West Eubank Field 1200 1000 Greg_3 800 Moo. A-3 u Drill Stem Tests n Static Bottom Hole Pressure s Pressure Buildup Tests Su 1 -28 Ray. C-2 Own. A-1 Test date 2000 1990 Clw 3 -9 Cl 2 -34 Do 1 -27 1980 1970 0 400 Clw 1 A 9 Wr 1 -26 Legend 600 Ko_A-4 Clw 1 A 9 Greg. F 6 Moo. A-1 1960 Pressure, psia Su 1 -28 42

Integration of Results l l The range of kh-values is uniform, but the spread of N-values has a discontinuity caused by differential 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 s West Eubank Field n South Eubank Field DO 1 -27 OWNA-2 Flow Capacity, koh, md-ft l Flow Capacity (kh) versus Contacted Oil-in-Place, N OWNA-3 1990 TILA-1 1995 TILA-2 LTHA-3 LTHA-2 1995 RAYC-5 KO_A-4 19961995 OWNA-4 1996 2 OWNA-1 RAYC-2 1996 10 1996 1995 RAYC-4 LS 2 -33 COLA-3 GREGF 6 1996 SU 2 -28 1996 RAYC-3 LS 1 -33 1996 1997 1996 MURD-3 RMRC-2 WR 1 -26 1997 1964 Incomplete Data 1991 RMRC-1 101 1964 MU 1 -34 MURD-4 1985 1997 "New Wells" ¬ kh = 6 10 -4 N MOOA-1 MOOA-3 1961 1985 GREG_2 1959 "Old Wells" ¬ kh =5 10 -5 N Note Format: Well Code s Completion Date 100 104 105 106 107 Contacted Oil-in-Place, N, STB 43

Integration of Results l l Excellent agreement in the computed N and EURvalues Primary recovery of 24 percent (average for the entire field) Note that the "old" wells clearly have higher N and EUR—which also validates the "differential depletion" concept 107 Contacted Oil-in-Place, N, STB l Contacted Oil-in-Place (N) versus Estimated Ultimate Recovery (EUR) Legend u North Eubank Field s West Eubank Field n South Eubank Field 106 "Old Wells" MOOA-1 N = 4. 2 EUR 1961 MOOA-3 GREG_2 1985 1959 DO 1 -27 RMRC-2 OWNA-3 TILA-2 TILA-1 LTHA-3 1990 KO_A-4 1964 1995 LTHA-2 1995 1996 OWNA-4 1996 OWNA-2 OWNA-1 1996 RAYC-51995 COLA-3 RAYC-3 MURD-3 RAYC-2 LS 2 -33 1996 SU 2 -28 MU 1 -34 1996 1997 1996 19971985 WR 1 -26 RAYC-4 GREGF 6 LS 1 -33 1991 1996 MURD-4 "New Wells" 105 Note Format: Well Code s Completion Date Incomplete Data 1997 RMRC-1 104 1964 103 104 105 106 Estimated Ultimate Recovery, EUR, STB 44

Integration of Results Potential injectors must simultaneously maximize n n l l 0. 45 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. 40 North Region COLA-3 0. 35 EUR/N, fraction l Injection Well Criteria OWNA-1 TILA-2 MOOA-3 DO 1 -27 OWNA-2 RAYC-2 TILA-1 OWNA-3 0. 30 WR 1 -26 RMRC-2 0. 25 RAYC-4 RAYC-5 RAYC-3 OWNA-4 GREG_2 0. 20 0. 15 0. 10 RMRC-1 MOOA-1 0. 05 0. 00 101 102 103 Flow capacity, koh, md-ft 45

Integration of Results l 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 EUR/N, fraction l Injection Well Criteria 0. 25 MU 1 -34 MURD-4 0. 20 LS 1 -33 LTHA-2 KO_A-4 GREGF 6 LS 2 -33 SU 2 -28 0. 15 0. 10 LTHA-3 0. 05 0. 00 101 102 103 Flow capacity, koh, md-ft 46

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

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

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

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

Follow-Up (Anadarko) l Economics and Strategy Must have Section 34 (T 28 S–R 34 W) n Water source/water quality n Risk assessment must be performed n l New data acquisition Pressure transient tests n Geochemistry: source rock, migration n l Additional work Further geologic description of reservoirs n Reservoir simulation n 51

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Geologic Description Stratigraphic Timetable — Southwest Kansas Age Depth (Ma) (ft) 245 2400 System Wolfcampian Pennsylvanian Missourian Desmoinesian Atokan Morrowan 5300 5500 Chesterian ssippian Meramecian 360 Wabaunsee Shawnee Lansing Group Marmaton Group l Atokan Group Morrow Group l Chester Group Missi- 335 (Hugoton Field Reservoir) Show 2700 Virgilian 310 Stratigraphic Unit Chase Group Permian 290 Series (Eubank Field Reservoir) Sainte Genevieve Saint Louis l l 5700 53

Well Log Analysis Water Saturation Distribution (from Well Logs) 12 10 Frequency Average Water Saturation Statistics: Mean = 0. 367 (fraction) Std dev = 0. 116 Water Saturation Distribution Function 8 6 4 2 0 0. 05 0. 10 0. 15 0. 20 0. 25 0. 30 0. 35 0. 40 0. 45 0. 50 0. 55 0. 60 0. 65 0. 70 0. 75 Per-Well Average Water Saturation, S w , fraction 54

Well Log Analysis Net Pay Distribution (from Well Logs) 6 Per-well Net Pay Distribution Function 5 Net Pay Statistics: mean = 20. 00 ft Frequency 4 std dev = 21. 83 ft 3 2 1 0 6 7 9 11 14 17 20 25 30 Per-Well Net Pay, 37 45 55 67 82 100 h , ft 55

Well Log Analysis Volume of Shale Distribution (from Well Logs) 9 8 Average Volume of Shale Statistics: Volume of Shale Distribution Function mean std dev = 0. 060 7 Frequency = 0. 082 (fraction) 6 5 4 3 2 1 0 0. 014 0. 020 0. 029 0. 042 0. 060 0. 085 0. 122 0. 175 0. 250 Per-Well Average Volume of Shale, VSH , fraction 56

Well Performance Analysis Flow Capacity (koh) Distribution (from Well Performance Analysis) 8 koh Data koh Distribution Function 7 Frequency 6 5 koh distribution Statistics: Mean = 50 md-ft 4 3 2 1 0 1 2 4 7 14 28 54 Flow Capacity, koh, md-ft 106 206 400 800 57

Geologic Description Owens Well A-3 5380 Core Permeability-Well Log Data Correlation l Best three models 3 to 5 well log variables n n n l Various bounds tested n n n l SP, GR ILD NPHI, DPHI, PHIDN No bounds kobs > 0. 5 md 10 md < kobs < 200 md Accuracy varies little in the reservoir rock, a lot more in the shaly zones 5420 True Vertical Depth, ft l 5400 5440 Legend 5460 kobs 5480 kcal_1 kcal_2 5500 kcal_3 5520 5540 10 -1 100 101 102 Permeability, md 103 58

l Reasonable agreement of koh and GOR values n n l High GOR corresponds to low permeability to oil Trend for main area Deviant data trends n n Owens and Ray Wells may have a secondary gas cap South Eubank Field has much more scatter koh from Production Data Analysis, md-ft Integration of Results Flow Capacity versus Initial GOR 103 DO 1 -27 OWNA-3 Probable data trends for Owens and Ray Wells TILA-1 TILA-2 LTHA-3 MOOA-1 KO_A-4 MOOA-3 OWNA-4 OWNA-1 RAYC-2 102 RAYC-4 LS 2 -33 COLA-3 GREGF 6 LS 1 -33 MURD-3 101 MU 1 -34 South Region WR 1 -26 MURD-4 Probable data trends for Eubank Field, main area 100 102 103 104 Initial Gas-Oil Ratio, scf/STB 105 (3 month average) 59