enhanced gravity drainage in yates field dec04
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Paul Button and Chris Peterson KinderMorgan
10th ANNUAL CO2 FLOODING CONFRENCE
Midland, TX
December 2004www.spe-pb.org
Enhanced Gravity Drainage Through Immiscible CO2 Injection in
the Yates Field (Tx)
MILES
0 25 50
DELAWARE
BASIN
MIDLAND
BASINNEW MEXICO
TEXAS
N
CENTRAL
BASIN
PLATFORM
NORTHWEST SHELF
EA
STE
RN
SHE
LF
SHEFFIELD CHANNEL
Midland
YATES FIELD -HIGH POINT OF CBP
VAL VERDEBASIN
• ~ 90 miles South Midland/Odessa
• SE tip of Central Basin Platform
• Structural high point of the CBP
• 26,423 Acres
Yates Field Unit - Location Map
General Facts & History
• Field Discovery - October 28, 1926 (Ira Yates’ 67th birthday)
• Discovery Well: I. G. Yates A No. 1 (Unit Well No. 4901)
Structure on Top of the San Andres Formation
North
Vertical Exaggeration ~ 9x.
Type of Reservoir• Highly Fractured Carbonate
Middle shelf Shelf crestInnerslopeHFS 2
HFS 3HFS 4
Rampcrest
HFS 1
Ramp
Outer ramp
HFS 5
11 km
StratigraphyStratigraphy
Fusulinid packstone/grainstone
Indicator FaciesCGR
50 m
eter
s
1-D Interpretation
HF
S 5
HF
S 4
HF
S 3
HF
S 2
East-West Permeability Slice
High Permeability Zones
3-D View of San Andres Structure with Fracture
Connection Overlay
7Rv/Qn/Gbg 0.5
SA (above +1,050’) 2.8SA (+950’ to +1,050’) 1.4
Total (above +950’) 4.2
SA (below +950’) 0.3
TOTAL 5.0
Gross
BBO .
Yates Original Oil in Place (OOIP)
+950’
+1,050’
0
20,000
40,000
60,000
80,000
100,000
120,000
1925 1945 1965 1985 2005
Production History
Great Depression
WWII
Unitization
BOPD
General Facts & History• Field Discovery - October 28, 1926
• Highest Oil Rate = 205,000 BPD (Well No. 4930 in 1929)
• Total Wells in 1929 = 315
• Total Production Capacity of Wells Exceeded 2 MMBOPD!
• Unitized July 1, 1976
Gas Plant built in 1961 to recover natural gas liquids and prevent flaring
General Facts & History
East Side of Field
-In-field drilling continued into the mid 80’s
-East side had flowing wells
A distinct east/west line of demarcation was considered to exist in the field
West Side of Field
-Waterflood started in 1979
-Produced using pumping units
-Polymer injection from 1983 - 1989
General Facts & History
1985-1991
CO2 injected into the gas cap on east side of the field for pressure maintenance
General Facts & History
1993 – Nitrogen injection from ASU #1 (30 MMCFD) initiated for pressure maintenance
1996 – ASU #2 (60 MMCFD) increased nitrogen injection.
General Facts & History
WALRUS Process
1998 - WALRUS program initiated• Acronym for Wettability Alteration of Reservoirs Using Surfactant
• Surfactant was added with produced water and injected into the reservoir to enhance oil movement
General Facts & History
1998 – Water Export commenced for reservoir management
General Facts & History
1999 –2002
Steam injection pilot was run;
post-evaluation in progress.
General Facts & History
Historical Recovery Techniques• Primary Depletion/Natural Bottom Water Drive
(NBWD) (1926 – 1976)
• Gas Injection/Limited NBWD (1976 – 1985)
• West Side Water Flood/Polymer Augmented WF (1981-1988)
• East Side CO2 Injection (1985 - 1991)
• Double Displacement Process (Co-Production) (1993-2000)
• Gravity Drainage (2000 – Present)
Primary Depletion
Unit Formed
Tertiary CO2 PAW
Tertiary DDP
Tertiary Thermal
WALRUS
Gravity Drainage Process
Recovery Processes
Yates Field ReservoirSecondary Pressure
Maintenance
YFU Extraneous Gas Injection
0
30000
60000
90000
120000
Jul-7
6
Jul-7
7
Jul-7
8
Jul-7
9
Jul-8
0
Jul-8
1
Jul-8
2
Jul-8
3
Jul-8
4
Jul-8
5
Jul-8
6
Jul-8
7
Jul-8
8
Jul-8
9
Jul-9
0
Jul-9
1
Jul-9
2
Jul-9
3
Jul-9
4
Jul-9
5
Jul-9
6
Jul-9
7
Jul-9
8
Jul-9
9
Jul-0
0
Eff
ecti
ve F
ree
Gas
Ad
dit
ion
s (
MC
FP
D)
Flue gas CO2 C1 N2 Solution gas
Discovered in 1926550’ of Oil Column at Structure Top
Discovery: 1926
Produced By Individual OperatorsUnitized in 1976 to Prevent Aquifer Influx
1926 - 1976
1976 - 1992 Gas Re-injected, Water Re-injectedOil Column Thinned
1992 - 2000 Gas Cap InflationReservoir DewateringContact Lowering
2000 - 2005 Contact StabilizationGas Cap InjectionAquifer “Maintenance” By Offsite Disposal
Yates Reservoir History
Yates Field Unit Saturation Profile
+ 1200
+ 1050
+ 850
WOC
1926
Frac
Mat
rix
1976
Frac
GOC
Mat
rix
WOC
1990’s
Frac
GOC
Mat
rix
WOC
Present
Frac
GOC
Mat
rix
WOC
Reservoir Review
So, WhyGravity Drainage?
For
mat
ion
Por
osity
%
Total Formation HeterogeneityLow High
0
30
Gravity And Capillary
Replacement Processes
Dis
plac
emen
t P
roce
sses
Depletion Processes
Neutral Zone
Yates
Reservoir Recovery Process Screening
Matrix surroundedby fluid-filled fractures
Matrix exposed togas-filled fractures
Matrix exposed togas-filled fractures
Matrix exposed togas-filled fractures
Mobilization
GOC
WOC
1) Oil drains vertically through matrix until downward movement is limited by phase mobility.
Mobilization
GOC
WOC
1) Oil drains vertically through matrix until downward movement is limited by phase mobility.
2) When vertical mobility is limited, the oil migrates laterally into fractures and is Mobilized to be available for Capture.
~222 MMCFD
~151 MMCFD
+1015 Current WOC
+1040 Current GOC~24,500 BOPD
~392,000 BWPD
~25,000 BWPD Export
+1050 Original WOC
~417,000 BWPD
~109 MMCFD CO2
~113 MMCFD Prod
Produced Gas Composition
N2 CO2 H2S HC
~41% ~30% ~3% ~26%
Operations – Material Balance
~550 NGLPD
~14.8 MMCFD Fuel ~3.3 MMCFD Gas Sales
~17.6 MMCFD N2 Vent
Average Contacts – Connected Wells
1000
1020
1040
1060
1080
1100
1120
1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005
0
20
40
60
80
100
120
GOC WOC OCT Well Count
Resaturation
800
900
1000
1100
1200
1300
1400
1500
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
So (Oil Saturation)
Ele
vati
on
(F
T S
UB
SE
A)
Current Oil saturation Futrure Oil saturation GOC WOC
So to .89Sw to .11
GOC = 1045’
WOC = 1015’
1) Resaturation is controlled by maintaining the position of the contacts
2) Goal - prevent downward movement of the oil column
Oil
Gas
Water
At a lower elevation and thinner column, the fracture connectivity within the oil column is reduced.
Yates Horizontal Drilling Operations/Results
Production response from Production response from HDH wellsHDH wells
Horizontal Drain HoleHorizontal Drain HoleRe-establish fracture connectionsRe-establish fracture connections
10,000
12,000
14,000
16,000
18,000
20,000
22,000
24,000
26,000
2001 2002 2003 2004 2005
BO
PD
2005 (115wl)2004 (130 wl)2003 (75 wl)Base
Why CO2 at Yates ??
• After active fluid contact movement stopped need to develop method to enhance gravity drainage above Nitrogen injection
• Possible EOR Processes– Thermal - Expensive and doesn’t replace voidage
– Methane Injection – Expensive for voidage replacement
– NGL Injection – Expensive and technically challenging
– Immiscible CO2 – Reasonable cost and positive
compositional effects
Why Immiscible CO2 Will Work at Yates• Compositional effects of Nitrogen Injection
– Strips light end components– Increase oil viscosity– Negative impact on Kro
• Compositional effects of Immiscible CO2
– Decrease oil viscosity• Lab tests ~ -25 % from “Non-stripped“ sample• Lab tests ~ -50 % from “N2 stripped“ sample• Model ~ 30 % from N2 processed oil
– Positive impact on Kro• Lab tests ~ 5 % from “Non-stripped“ sample• Lab tests ~ 12 % from “N2 stripped“ sample• Model ~ 7-8 % from N2 processed oil
• CO2 injection results in improved oil mobility vs. Nitrogen injection
Oil Mobility = K * Kro
Yates Compositional Model History Match
300
400
500
600
700
800
900
Pre
ssu
re (
Psi)
1052 New Pressure @ +1050
Production History Match
-
20,000
40,000
60,000
80,000
100,000
120,000
140,000
J-26 J-31 J-36 J-41 J-46 J-51 J-56 J-61 J-66 J-71 J-76 J-81 J-86 J-91 J-96 J-01
Oil
an
d W
ater
(B
PD
)
-
50,000
100,000
150,000
200,000
250,000
Gas
(M
CF
)
Model Oil Model Water
Hist Oil Hist Water
Model Gas Hist Gas
-Reasonable pressure match- Discrepancy due to large difference in fluid contacts across the reservoir in late 80’s and 90’s
- Reasonable match on all fluids- Major oil difference due to documented leak oil- Water match on exported water
Yates Compositional Model History Match
800
900
1000
1100
1200
1300
1400
1500
0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0
So
Ele
va
tio
n (
Ft)
12/31/1984 1984 Log Study 8/31/2002 1984 Ave (block)
1000
1050
1100
1150
1200
1250
1300
1350
1400
1450
1500
Jan-26 Jan-31 Jan-36 Jan-41 Jan-46 Jan-51 Jan-56 Jan-61 Jan-66 Jan-71 Jan-76 Jan-81 Jan-86 Jan-91 Jan-96 Jan-01
Ft
abo
ve S
ea le
vel
0
50
100
150
200
250
300
350
400
450
500
Ft
GOC OWC hist GOC Hist WOC
Series7 OCT Hist OCT
-Reasonable fluid contact match based on available data early time-Very good fluid contact match late time
-Reasonable oil saturation match based on 1984 log saturation study-Projection of current matrix oil saturation
Projected Oil Response from Yates Immiscible CO2 Injection Project
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
2002 2004 2006 2008 2010 2012 2014 2016 2018 2020
Year
Oil
Rat
e (B
OP
D)
High Trend (BOPD)
Medium Trend (BOPD)
Low Trend (BOPD)
Immiscible CO2 Injection Design
• Vertical Placement– Concentrate CO2 within 50’ of
current GOC
• Areal Placement– NW portion of Field (Area with
high N2 content)
• Planned CO2 Migration– Vertical
• Migration Upward to GLM
– Areal• Recycle through Gas Plant
and injected in SE Area
Vertical CO2 Placement
800
900
1000
1100
1200
1300
1400
1500
0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0
Matrix Oil Saturation
Ele
vati
on
(ft
ab
ove
sea
lev
el)
Current So Current GOC Top of CO2 Target Area Avg CLM Elevation
CO2 Target Area
CO2 Recycle Area
Implementation of Immiscible CO2 Injection
• CO2 injection started March 1st 2004• Used existing infrastructure to distribute CO2
to injection wells • Converted gassed-out horizontal producers to
CO2 injectors within 50’ of current gas-oil contact
• Initiated injection at 42.5 MMCFD of CO2
• N2 Rejection started March 2005
• Current CO2 injection rate 109 MMCFD
Cumulative CO2 Injected Since March, 2004
CO2 Inj. Well
Gas Inj. Well
Total CO2 Injected = 45.7 BCF
CO2 Area
Non-CO2 Area
CO2 Injection – Assessment
Non-CO2 Area
CO2 AreaIs Oilier
Different GOR Behavior
Different Vertical Declines
All Wells Non-CO2 Area
0
2000
4000
6000
8000
10000
12000
0 10000 20000 30000 40000 50000 60000
CUM GAS MCFPD
CU
M O
IL B
OP
D
Feb 05
Feb 04
Sep 04
Less Efficient
More Efficient
CO2 Injection – Assessment
All Wells CO2 Area
0
2000
4000
6000
8000
10000
12000
14000
16000
0 10000 20000 30000 40000 50000 60000 70000 80000
CUM GAS MCFPD
CU
M O
IL B
OP
D
Feb 05
Feb 04
Sep 04
Less Efficient
More Efficient
CO2 Injection – Assessment
Vertical Wells Non-CO2 Area
0
1000
2000
3000
4000
5000
6000
7000
0 5000 10000 15000 20000 25000 30000
CUM GAS MCFPD
CU
M O
IL B
OP
D
Feb 05
Feb 04
Sep 04
Less Efficient
More Efficient
CO2 Injection – Assessment
Vertical Wells CO2 Area
0
1000
2000
3000
4000
5000
6000
7000
0 5000 10000 15000 20000 25000 30000 35000
CUM GAS MCFPD
CU
M O
IL B
OP
D
Feb 05
Feb 04
Sep 04
Less Efficient
More Efficient
CO2 Injection – Assessment
All Wells
0
5000
10000
15000
20000
25000
30000
0 20000 40000 60000 80000 100000 120000 140000 160000
CUM GAS MCFPD
CU
M O
IL B
OP
D
Feb 05
Feb 04
Sep 04
Less Efficient
More Efficient Aug 05
CO2 Injection – Assessment
0
5,000
10,000
15,000
20,000
25,000
30,000
2002 2003 2004 2005
BO
PD
Base Pre 05 HDH 05 Phs 1 CO2
Current Production
Yates Field Response VS. Modeling Predictions
• Field response much earlier than model predicted
• Portion of early oil production response may be response to redistribution of gas injection
Projected Oil Response from Yates Immiscible CO2 Injection Project
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
2002 2004 2006 2008 2010 2012 2014 2016 2018 2020
Year
Oil
Rat
e (B
OP
D)
High Trend (BOPD)
Medium Trend (BOPD)
Low Trend (BOPD)
8801 OBS
88158816 Flush oil from thinning
Imitates CO2 response
Yates CO2 Expansion Options
• Modify Existing Facilities– Increase N2 Rejection (to 30+ MMCFD)
• CO2 Processing
– Expand Delivery Capacity• Pipeline Pump
– Mix CO2 with Recycle Gas
• New Facility Potential– New gas processing facility N2 Rejection– Additional Pipeline for CO2 Delivery– Simulation Driven
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