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 Researchjharju@undeerc.orgj a ju@u dee c o g

Ed Steadman PCOR Partnership Program ManagerSenior Research Advisoresteadman@undeerc.org