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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Shaochang Wo
CO2-EOR Potential of Gravity-Stable CO2 Injection in the Frannie Tensleep Reservoir
Casper, Wyoming July 8-9, 2013
The 3rd Tensleep Workshop of EORI
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Outline
• An Overview of the Geological Setting and Production History of the Frannie Field
• OOIP Estimation Based on Stone’s Common-Pool Theory • Pressure Communication among All Tensleep Zones as
Indicated from DST Data and Pressure Buildup Tests • The Effect of Natural Fractures on Reservoir Conformance • Challenges to Achieving Optimum Performance of CO2
Floods in the Frannie Tensleep Reservoir and Its TZ/ROZs • Applicability of Gravity-Stable CO2 Injection at the Frannie
Field • Initial Estimations of Oil Recovery by Gravity-Stable CO2
Injection • Summary
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Wyoming Oil & Gas Fields
Powder River Basin
Greater Green River Basin
Bighorn Basin
Wind River Basin Overthrust
Belt
Hanna Basin
Laramie Basin
Jackson Hole
Denver Basin
Shirley Basin
Frannie-Sage Creek Area
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Aquifer Water Influx
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Frannie Tensleep: Top of A Sand Unit
Oil Pool after Tilting
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Southwest Northeast
13o
TZ/ROZ
Main Pay Zone
Illustration of Southwest-Northeast Cross Section at Frannie Field
~9,000 ft
~2,0
00 ft
45o A
~200 ft
B
C D
E
F
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
A
A
A
B
D
E
F
E
Well Logs and Identified Sand Units in Well #147
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000
1928 1938 1948 1958 1968 1978 1988 1998 2008 2018
Mon
thly
Oil
Prod
uctio
n Ra
te, B
O/m
onth
Frannie Field: Monthly Oil Production Rate
Discovery well Feb. 1928
Total 15 production wells drilled before 1940
122 wells drilled between 1940 ~ 1955
99% water cut In 2011
22 wells drilled between 1955 ~ 1989
Before 1948: produced only from A&B zones After 1948: produced from all zones
Water flooding started in Dec. 1970
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Monthly Productions at Frannie Field (after 1978)
Average Water Cut in 2011: 99%
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Depth of Tensleep Top 2548 ft Initial Reservoir Pressure NA, est. 1800 psi
Average Core Porosity 17%, Range 9-33% Oil Gravity 25-28.3o API
Average Core Permeability 75 md, Range 0.1-1000 md Bubble Point Pressure (BPP) 58-305 psi
Average Pay Thickness 100 ft Gas Oil Ratio at BPP 33.2-66 SCF/STB
Average Gross Pay 200 ft Est. OOIP in Main Pay Zone 215.7 MMBO
Oil Column 1300 ft Cum. Oil Production 119.1 MMBO
Oil/Water Contact NA, est. 450 ft above sea level Oil Recovery 55.22%
Reservoir Temperature 96o F Well Spacing 10 acre
Primary Drive Mechanism Water and solution gas CO2 MMP Est. 1750 psi
Oil and Reservoir Properties of the Frannie Tensleep
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
“… The hydrocarbons held within these Phosphoria and Tensleep stratigraphic traps were later released as a consequence of fracturing and faulting associated with Laramide folding, and moved into older Paleozoic reservoir rocks until fully adjusted to anticlinal structure in common pools. Vertical segregation of an original common pool into several separate pools was accomplished in some exceptional fields of the basin either by selective hydrodynamic tilting within the Tensleep zone, by leakage or redistribution of fluids through fault zones, … ”
“Theory of Paleozoic Oil and Gas Accumulation in the Big Horn Basin, Wyoming” by D. S. Stone, 1967, SPE 1883
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Frannie Tensleep: Top of A Sand Unit 1
2 3
4 5
6 7
8
9
A
A
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Edited from L.B. Curtis, 1954
1 2 3 4 5 6 7 8 9
Mean Oil-Water Contact in the Madison: 1107’ above Sea Level
Tensleep Oil Pool before Tilting
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Frannie Tensleep: Top of A Sand Unit
Oil Pool before Tilting
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Frannie Tensleep: Top of A Sand Unit
Oil Pool before Tilting
Oil Pool after Tilting
Peak Rate: 1292 BOPD Cum. Oil: 756 MBO
Well 128
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
AVG. WATER TOTAL POROSITY AVERAGE ORIGINAL OIL
SAND UNIT SATURATION (MATRIX+FRACTURE) AREA NET PAY IN PLACE
fraction fraction acres feet STB
A 0.157 0.176 1636 16 29,538,819 B 0.127 0.191 1636 45 93,366,919 C 0.130 0.185 1636 14 28,038,316 D 0.139 0.175 1636 10 18,748,827 E 0.162 0.168 1636 37 64,816,851 F 0.183 0.155 1636 7 11,030,233
Boi = 1.02
Estimated OOIP of the Frannie Tensleep Oil Pool before Tilting
Total Est. OOIP = 245.5 million STB
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Scenarios of OOIP Calculation Est. OOIP Cum. Oil Produced Oil Recovery MMBO MMBO %
OWC at +450' Elevation after Tilting* 215.7 119.1 55.22 OWC at the Sea Level after Tilting* 267.5 119.1 44.52 OWC at +1107' Elevation before Tilting 245.5 119.1 48.51
*data from a 1991 Conoco Report
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Available Data from the Frannie Field That Are Used for Assessing Reservoir Connectivity and Fracture Effects
• Well logs • Core description and measurements • DST data • WBH Pressure buildup tests • Tracer tests • Well perforation and workover history • Injection profile tests • Producers’ response to neighboring
injectors
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
-400
-200
0
200
400
600
800
1000
1200
1400
1600
1/1/1928 6/23/1933 12/14/1938 6/5/1944 11/26/1949 5/19/1955 11/8/1960 5/1/1966
Pres
sure
, psi
g
Frannie Tensleep: Pressure Buildup Tests & DST Data before 1970
Measured Pressure
Pressure corrected to +1200'
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E Frannie Tensleep Reservoir Pressure in June 1936 and June 1937 (data) Pressure Corrected to +1,200’ Datum
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E Frannie Tensleep Reservoir Pressure in October 1960 Pressure Corrected to +1,200’ Datum
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E Frannie Tensleep Reservoir Pressure in April 1967 Pressure Corrected to +1,200’ Datum
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Fracture Interpretation of the Southeast Tensleep Outcrop at Alcova Anticline, Wyoming
- Figures copied from Nathaniel Gilbertson & Neil F. Hurley (2005)
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Well #147 was drilled and cored in 1988
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E 0.00001
0.0001
0.001
0.01
0.1
1
10
100
1000
10000
0.000001 0.00001 0.0001 0.001 0.01 0.1 1
Frac
ture
Per
mea
bilit
y, D
arcy
Fracture Porosity, fraction
Fracture Permeability as a Function of Fracture Porosity and Width
Kf = ɸf 𝑒2/12
e = 10 micron
50 micron
100 micron
200 micron
1 mm
700 micron
500 micron
300 micron
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Frannie Tensleep Wells Have Been Sand Fractured (260 fracture treatments by 1990)
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Injection Profile of Well 120
A Sand
B Sand
25%
30%
45%
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Injection Profiles of Well 78 with Single or Dual Injection Configuration
B Sand
C Sand
D Sand
E Sand
Single Single Single Single Single Single Dual Dual Dual
Open hole Linered
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Challenges to Achieving Optimum Performance of CO2 Floods in the Frannie Tensleep Reservoir
• Lateral and Vertical Conformance Problems because of the Existence of Highly Conductive Natural Fractures and A 200-foot Thick Gross Pay Interval
• Lower Formation Fracture Pressure due to A Relatively Shallow Reservoir; the Depth of the Structure Top at the Frannie Tensleep is about 2548 ft
• Only Near-Miscible CO2 Flooding Will Likely Be Achieved at the Structure Top
• Strong Hydrodynamic Flow • Uncertainty of Current Remaining Oil Distribution in
the Reservoir
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E 0
10
20
30
40
50
60
70
80
90
100
0 500 1000 1500 2000 2500 3000 3500
Oil
Reco
very
, %
Pressure, psi
Oil Sample from Well #75; Oil Gravity=26.8 oAPI; Tested at 110 oF
Slim-tube Tests of CO2 Flood on Frannie Tensleep Oil
“Near-Miscibility” Pressure: ~1600 psi Range of Fracturing Pressure
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Critical Velocity for Gravity-Stable Gas Injection
Hill (1952)
Dumore (1964)
𝑉𝑐 =2.741𝐾𝐾𝐾𝐾𝐾 𝜌𝑜 − 𝜌𝑔
∅(𝜇𝑜 − 𝜇𝑔)
𝑉𝑐 =2.741𝐾𝐾𝐾𝐾𝐾
∅𝜕𝜌𝜕𝜇 𝑚𝑚𝑚
Vc = Critical velocity, ft/d K = Permeability, Darcy θ = Dip angle, degree φ = Porosity, fraction ρo = Oil density, gm/cc ρg = Gas density, gm/cc μo = Oil viscosity, cP μg = Gas viscosity, cP
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E 0.80
0.82
0.84
0.86
0.88
0.90
0.92
0.94
0.96
0.98
1.00
20
21
22
23
24
25
26
27
28
29
30
0 200 400 600 800 1000 1200 1400 1600 1800 2000
Oil
Dens
ity, g
m/c
c
Oil
Gra
vity
, API
Bottomhole Elevation above Sea Level, ft
Frannie Tensleep: Oil Gravity and Density
Oil Gravity
Oil Density
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E 0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
0 500 1,000 1,500 2,000 2,500 3,000 3,500
CO2 D
ensi
ty, g
m/c
c
Reservoir Pressure, psi
CO2 Density vs. Reservoir Pressure at 100 oF
Likely range of oil density at reservoir condition
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Pressure Range for Miscible Gravity-Stable CO2 Injection
𝑷𝑴𝑴𝑷 < 𝑷𝑹𝑹𝑹 < 𝑷𝑴𝑴𝑴
PMMP: minimum miscibility pressure of CO2 PRES: average reservoir pressure during CO2 injection PMAX: a reservoir pressure at which CO2 becomes heavier than miscible oil
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Simulation Analog of Gravity-Stable CO2 Injection
• Scaling parameters used in the 2D line-drive simulation models — Reservoir dip angle — Ratio of reservoir length to gross pay interval — Permeability aspect ratio (vertical/lateral) — Oil-water mobility ratio — Oil-CO2 mobility ratio — Buoyancy number — Injection and production pressures — Remaining oil saturation after water flood — Residual oil saturations to water and CO2
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Estimated Oil Recovery by Gravity-Stable CO2 Injection
Scenarios of OOIP Calculation OWC at +450' Elevation after Tilting
OWC at +1107' Elevation before Tilting
Estimated OOIP 215.7 MMBO 245.5 MMBO Estimated Remaining-Oil-In-Place 96.6 MMBO 126.4 MMBO Oil Recovery after Water Flood 55.22% 48.51% Average Saturation of Remaining Oil 36% 41% Recoverable Oil By Gravity-Stable CO2 Flood 31.6 MMBO 49 MMBO Net CO2Usage for Incremental Oil Recovery 9.9 Mscf/BO 7.3 Mscf/BO
Additional Oil Recovery by Gravity-Stable CO2 Flood 14.6% of OOIP 20% of OOIP
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
9 Tensleep reservoirs in the Bighorn basin that have large TZ/ROZs have been identified as good candidates for miscible gravity-stable CO2 flood
Field Name Reservoir Name Basin Cum. Oil MMBO
Res. Depth ft Oil API
Initial Pressure psi
Res. Temp F Oil SG
Oil Density @Res. gm/cc
CO2 Density @Res. gm/cc
ρo - ρco2 gm/cc
BYRON EMBAR-TENSLEEP BIGHORN 122 5425 25.2 2085 130 0.903 0.890 0.641 0.249 ELK BASIN EMBAR-TENSLEEP BIGHORN 353 4490 30 2234 120 0.876 0.866 0.721 0.145 ELK BASIN SOUTH EMBAR-TENSLEEP BIGHORN 21 6846 28 2493 146? 0.887 0.871 0.625 0.246
FRANNIE PHOSPHORIA-TENSLEEP BIGHORN 135 2574 28.3 1350 96 0.885 0.879 0.609 0.270
GEBO EMBAR-TENSLEEP BIGHORN 17 4735 24.9 2223 145 0.905 0.889 0.561 0.328 MURPHY DOME TENSLEEP BIGHORN 39 4752 34 2150 117 0.855 0.846 0.705 0.141 GRASS CREEK EMBAR-TENSLEEP BIGHORN 47 4168 24.2 1300 110 0.909 0.901 0.368 0.533 SAGE CREEK TENSLEEP BIGHORN 5 3421 23.5 1400 96 0.913 0.907 0.641 0.266 BIG POLECAT TENSLEEP BIGHORN 7 5452 26.4 2050 118 0.896 0.886 0.689 0.197
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Summary
• Based on Stone’s common-pool theory and an OWC at +1107’ elevation before tilting, the OOIP in the Frannie Tensleep is estimated to be 245.5 million barrels of oil.
• Due to restricted injection pressure of CO2, only “near-miscible” condition could be achieved at the structure top of the Frannie Tensleep.
• DST data and pressure buildup tests indicate a pressure communication among all Tensleep zones, assumably by vertical fractures.
• Because the Frannie Tensleep reservoir is relative shallow and CO2 is less dense than oil under the reservoir condition, gravity-stable CO2 flooding appears to be a superior method to CO2-WAG flooding.
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Summary (cont’d)
• A preliminary study of simulation analog estimates that between 31.6 and 49 million barrels of oil could be recovered by gravity-stable CO2 flood depending on the remaining oil-in-place.
• Direct evidence shows that, at different locations of the structure, natural fractures are developed in a variety of orientations, laterally and vertically.
• Most of Tensleep wells at Frannie have been hydraulically fractured and, to some extent, are connected to natural fracture networks. However, well-to-well fracture conduits can change with time depending on at-the-time wellbore configurations and injection/production intervals.
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Ongoing and Future Work
• Developing a dual porosity/permeability simulation model of the entire Tensleep structure at the Frannie field
• Simulating the effect of hydrodynamic flow and natural fractures on the titling of the Tensleep oil pool and its production/injection performance
• Evaluating various injector-producer configurations, e.g. CO2-WAG vs. gravity-stable CO2 injection, to identify the optimal option(s) for CO2 EOR in the main pay zone as well as in its TZ/ROZ
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Acknowledgements
• We thank Merit Energy Company for supporting this study and providing the entire Frannie data set.
• The software donation of Petrel and Eclipse made by Schlumberger to EORI, which is being used in this study, is much acknowledged.
E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Thank You!