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Zama Acid Gas EOR COZama Acid Gas EOR CO Storage andStorage andZama Acid Gas EOR, COZama Acid Gas EOR, CO22 Storage, and Storage, and Monitoring ProjectMonitoring Project
CSLF Storage and Monitoring Projects Interactive WorkshopCSLF Storage and Monitoring Projects Interactive WorkshopSaudi ArabiaSaudi ArabiaMarch 1, 2011March 1, 2011
John A. HarjuJohn A. Harju
© 2010 University of North Dakota Energy & Environmental Research Center.
Acknowledgments
• Apache Canada, Ltd.
N t l R C d• Natural Resources Canada
• Alberta Energy Resources and Conservation Board
• RPS Energy
• Advanced Geotechnology, Inc.
• U.S. Department of Energy National Energy Technology Laboratory (NETL)y ( )
Where’s Zama?
Operated by Apache Canada, Ltd.
Zama Pinnacle
R fReef
Zama History
Discovery 1967y
Primary Well Development 60’s-70’s
W fl d I l i 80’Waterflood Implementation (selected pinnacle reefs)
80’s - present
Number of Pools Discovered to 846Date
Cumulative oil produced to August 2006
209 mmstb (17.4% OOIP)
Current Field Production 6,550 bopd @ 80.1% water cut
Source: Nimchuck, 2006
Zama History
• Technical evaluation based on $61 Million
186
Estimated Field Recoveries MMbbls
demonstration project in operation since 2004.
233.274
186 Primary Recovery
SecondaryRecovery 2004.
• Incremental pool recovery @ 15%
74 yBase Case ProvenCO2 RecoveryProbable CO2Recovery
• Zama Field OOIP is 1200 MMbbls
913.8RecoveryRemainingUnrecoverable
Source: Nimchuck, 2006
Zama Acid Gas Enhanced Oil Recovery (EOR) ProjectRecovery (EOR) Project
• Unique approach combining acid gas disposal and carbon dioxidegas disposal and carbon dioxide (CO2) EOR.
• Acid gas is obtained from EOR l d dditi l fi ldrecycle and additional field
production passed through the on-site gas plant.
• Eliminated CO2 venting to the atmosphere and surficial stockpiling of elemental sulfur.
• Six pinnacles currently accepting acid gas for EOR.
Potential for expansion into• Potential for expansion into hundreds of additional pinnacles.
Current Reservoir Pressures Vs. OriginalCandidate EOR Pools Near Zama Gas Plant (6 km radius)
25,000
30,000
Alstonw/40%
Alstonw/40%
HyCalRBA@40%H2S and Initial Oil BP
HyCalRBA@40%H2S and Depleted Oil
20,000
e, k
Pa
w/40% H2S
H2SInitial Oil BPDepleted Oil
Slim TubeTest Result
10,000
15,000
Pres
sure
-
5,000
Pure CO2 MMP Acid Gas (33% H2S) MMP Original Reservoir PressureLab Measured MMP (Pure CO2) Lab Measured MMP (20% H2S) Lab Measured MMP (40% H2S)Most Recent Pressure
Source: Lavoie, 2005
Rising Bubble Apparatus (RBA)Minimum Miscibility Pressure (Multicontact)
Rising Bubble Apparatus MMP for H2S and CO2 Injection GasRising Bubble Apparatus MMP for H2S and CO2 Injection GasZama Keg River F Pool - 1-13-116-6W6M
22
24
22
24Original BP 8.9 MPaDepleted BP 6.9 MPa
16
18
20
P (M
Pa)
16
18
20Depleted BP 4.9 MPa
10
12
14
MM
P
10
12
14
Original Reservoir pressure
80 5 10 15 20 25 30 35 40
Mol% H2S in CO2 Injection Gas
8pressure
Actual H2S conc.
Slide courtesy of B. Jackson
Zama Acid Gas Project - Risks / ChallengesChallenges
• Vertical Sweep efficiency controlp y• Excessive acid gas breakthrough• Protection of wells and pipelines against corrosion
D t i i ti f ti th lif• Determining optimum perforation zones over the life of each pinnacle
• Optimum gas injection rates• Safety in handling high H2S concentrations• Possible need to drill additional wells
Plugging and freezing up of wells due to hydrates• Plugging and freezing up of wells due to hydrates, wax, and asphaltene precipitation (wax stabilized hydrates)
Slide courtesy of B. Jackson
Zama Pinnacle (F-Pool)
• Carbonate reservoir 5300 feet deep
Shekilie BasinShekilie Basin
• 5300 feet deep• About 40 acres at the base
(.16 km2)• 400 feet tall (120 m)• 10% average porosity • 100–1000 mD permeability Zama BasinZama Basin100 1000 mD permeability• 2100 psi initial reservoir
pressure
Patch (Pinnacle)Reefs
Patch (Pinnacle)Reefs
Current F-Pool Configuration
• Top-down injection scheme through one
KEG RIVER F POOL103/01-13-116-6W6100/1-13-116-6W6102/8-13-116-6W6
100/8-13-116-6W6DISCOVERY
WELLUNUSED IN EOR
PROD #2 CO2 INJ PROD #1
N S
Open Production Perforations
Open Injection Perforations
FT. VERMILLION EVAPORITE (WATT MTN. AQUITARD)
SLAVE PT. AQUIFER
KEG RIVER F POOL103/01-13-116-6W6100/1-13-116-6W6102/8-13-116-6W6
100/8-13-116-6W6DISCOVERY
WELLUNUSED IN EOR
PROD #2 CO2 INJ PROD #1
N S
Open Production Perforations
Open Injection Perforations
FT. VERMILLION EVAPORITE (WATT MTN. AQUITARD)
SLAVE PT. AQUIFER
scheme through one wellbore.
• Injected gas stream is approximately 70% CO
-1089 m SS-1087 m SSGAS/OIL CONTACT
TD
MUSKEG ANHYDRITEAQUITARD
1086 9 SS
-1070 m SS
-1085 m SS-1087 m SS
-1077 m SS
AMA MEMBER
Dolomite Stringer
MDT Intervals
SULPHUR POINT WATT MTN. SHALE (WATT MTN. AQUITARD)
F Pool -966 m SS
-1089 m SS-1087 m SSGAS/OIL CONTACT
TD
MUSKEG ANHYDRITEAQUITARD
1086 9 SS
-1070 m SS
-1085 m SS-1087 m SS
-1077 m SS
AMA MEMBER
Dolomite Stringer
MDT Intervals
SULPHUR POINT WATT MTN. SHALE (WATT MTN. AQUITARD)
F Pool -966 m SSapproximately 70% CO2and 30% H2S.
• Two production wells. -1106m SS
(injected acid gas)
-1132 m SS
TD-1084 m SS (TVD)
KEG RIVER POOL
-1086.9 SS
-1113.6 m SS
-1093 m SSZAMA
ZAMA MEMBER
77
108m
142mAbdn. Comp.
-1106m SS(injected acid gas)
-1132 m SS
TD-1084 m SS (TVD)
KEG RIVER POOL
-1086.9 SS
-1113.6 m SS
-1093 m SSZAMA
ZAMA MEMBER
77
108m
142mAbdn. Comp.
• Observation well completed in the Sulphur Point Reservoir. Former
ORIGINAL O/W CONTACT
TD-1154 m SS (TVD)
TD-1159 m SS (TVD)
TD-1178 m SS (TVD)
? ? ? ? ? ? ?
Spill point
Spill point
77m
LOWER KEG RIVERAQUIFER
ORIGINAL O/W CONTACT
TD-1154 m SS (TVD)
TD-1159 m SS (TVD)
TD-1178 m SS (TVD)
? ? ? ? ? ? ?
Spill point
Spill point
77m
LOWER KEG RIVERAQUIFER
producer completed in top of pinnacle, currently plugged to 104 m above top of pinnacle.
F-Pool Pinnacle Production History
160 30,000
Pool Pressure and Production History
• Began production in January
120
14025,000 D
atum Pr
• Began production in January 1967
• Cumulative oil production prior to 2006 = 1,104,887 bbl
80
100
ate
(m3/
d)
15,000
20,000
ressure (kPaa) & G
40
60
Ra
10,000
GO
R (m
3/m3) x 10
0
20
0
5,000
0
Jan-67 Jun-72 Dec-77 Jun-83 Nov-88 May-94 Nov-99 May-05
Daily Fluid PROD m3/d DAILY OIL PROD m3/dDAILY WTR INJECTION m3/d /10 GOR m3/m3 x 10Pressure Survey Survey Date
Oil 175,663 m3Gas 15,144 e3m3Wtr 59,898 m3Wtr Inj 366,424 m3
Acid Gas Injection
• Began Injection g jDecember 15, 2006.
• Average injection rate around 1 MMCF/Daround 1 MMCF/D.
• Second production well completed June p2008.
• Cumulative injection over 60 000 tonsover 60,000 tons.
• Cumulative incremental production
It is anticipated that as much as 588,000 additional barrels (approximately 15% of the estimated original oil in place) can be
produced from the Zama pinnacle reef structure using this techniquep
is over 50,000 barrels.structure using this technique.
Philosophy of Monitoring• Maximize the use of existing data sets in an
effort to characterize the baseline conditions of th itthe site.
• Minimize the use of invasive or disruptive technologies to acquire new data.
• Monitoring, verification, and accounting (MVA) data acquisitions will be coordinated with routinely scheduled operation activities.
• Ensure that the monitoring operations are as transparent as possible to the day-to-day field operations.
The Zama MVA program was developed using current Alberta regulatory framework
for acid gas injection. Characterization activities were added to fully describe theactivities were added to fully describe the system and provide confidence in the safe
and secure storage of injected fluids.
MVA Operations
Monitor the CO2–H2S plume through:• Perfluorocarbon tracer injection and fluid sampling in the overlyingPerfluorocarbon tracer injection and fluid sampling in the overlying
Sulphur Point Formation• Reservoir pressure monitoring• Wellhead and formation fluid sampling (oil, water, gas)
Monitor for cap rock failure through:• Pressure measurements of injection well, reservoir, and overlying
formations• Fluid sampling of overlying formations
Determine injection well conditionsDetermine injection well conditions through:• Wellhead pressure gauges• Well integrity tests• Well integrity tests• Wellbore annulus pressure
measurements
Geology and Hydrogeology Results
• Conducted to better understand the storage characteristics of gregional aquifer systems and the fate of acid gas.
• Results indicate there is minimalResults indicate there is minimal potential for acid gas migration to shallower strata and potable groundwater.g
Mechanical Integrity
• Program elements include:– Evaluation of possible cap rock leakage mechanisms.
– Triaxial and unconfined compressive strength.
U i i l l– Uniaxial pore volume compressibility.
– Schmidt rebound hammer.
– Minimum horizontal in situ stress orientations.
– Vertical stress magnitude.
– Geomechanical simulation of acid gas injection.
Mechanical Integrity (continued)
• Modular Dynamics Test – July 2008
– Performed to obtain horizontal stresses in reservoir cap rock
– Tested three intervals:• Two anhydrite• One dolomite stringer (encased
in anhydrite)in anhydrite)
• Unable to fracture anhydrite!• Fracture attained in dolomite
at over 5000 psi. – Allowable injection pressure is
approximately 2100 psi.
Geochemistry
• Petrophysical evaluation– Injection zone, cap rock, andInjection zone, cap rock, and
overlying porous intervals.• Laboratory work
– EERC acid gas soak test toEERC acid gas soak test to determine rates of mineral reactions in carbonates and evaporites.
• Modeling– To evaluate reactions in
carbonates with respect to:• Acid gas.• Formation fluids.• Formation minerals.
Wellbore Cement Acid Gas Interactions
• The EERC has developed novel U 18(innovative) approaches to prepare
and maintain H2S CO2 mixtures under relevant sequestration
diti
Up to 18 samples
per reactor
bconditions.• Cement samples were exposed for
a period of 28 days at a t t f 50°C d
can be run in
individual glass
i ltemperature of 50°C and a pressure of 15 MPa using pure CO2and H2S CO2 ( 21 mol% H2S in the vapor phase) to simulate acid gas
vials.
vapor phase) to simulate acid gas.
Wellbore Cement Acid Gas Interactions (continued)(continued)
• The CO2-only exposed cement underwent carbonation and Pure COunderwent carbonation and decalcification in the outer rim area, while the interior regions of the cement remained intact and unaltered.
Pure CO2forms a carbonate "sheath."
• The H2S CO2 exposed cement exhibited carbonated zones similar to the CO2-only samples. However, the H2S CO2 exposed cement h d id f i ifi tshowed evidence of significant
impact to the interior region of the samples.
• Working closely with NETL labs to interpret results H S COinterpret results.
• Will provide valuable information toward understanding the risk management issues related to potential wellbore leakage
H2S CO2 forms ettringite and iron sulfides.potential wellbore leakage.
Well‐bore cement: 2200 psi, 50 C, 28 days
Current ActivitiesNew laboratory work to determine:
• Capillary threshold pressure of capCapillary threshold pressure of cap rock.
• Threshold intrusion pressures for acid gas-rich brine.
• Mechanical changes before and after acid gas exposure.
This work will allow the field s o a o t e e doperator to determine maximum operating pressures in this regime. Work has been funded by Natural Resources Canada and ApacheResources Canada and Apache Canada, Ltd.
Additional funding was received from the U.S. Department of Energy to conduct additional laboratory- and field-based activities at Zama.
Contact Information
Energy & Environmental Research CenterUniversity of North DakotaUniversity of North Dakota15 North 23rd Street, Stop 9018Grand Forks, North Dakota 58202-9018
World Wide Web: www.undeerc.orgTelephone No. (701) 777-5000Fax No. (701) 777-5181
John HarjuAssociate Director for [email protected] a ju@u dee c o g
Ed Steadman PCOR Partnership Program ManagerSenior Research [email protected]