Regional Geologic Setting• Over 800 Devonian-age pinnacle reef structures.• F Pool is one of the several hydrocarbon-bearing structures.• Reef structures typically consist of dolomite surrounded and overlain by anhydrite (cap rock) of the Muskeg Formation. • A large variation in both porosity and permeability is observed in these dolomitized heterogeneous pinnacles, with a decrease to the tops of the reef.• The principal microfacies include wackestone, packstone, grainstone, �oatstone, and rudstone.• With varying degrees of alteration due to secondary leaching and dolomitization, porosity type varies from intercrystalline to microfracture (Burke, 2009).

AbstractSince October 2005, the Zama oil �eld in northwestern Alberta, Canada, has been the site of acid gas (approximately 70% carbon dioxide [CO2] and 30% hydrogen sul�de [H2S]) injection for the simultaneous purpose of enhanced oil recovery (EOR), H2S disposal, and CO2 storage. Injection began in December 2006 and continues through the present at a depth of 4900 feet into the Zama F Pool, which is one of over 800 pinnacle reef structures identi�ed in the Zama Subbasin. To date, over 90,000 tons of acid gas has been injected, with an incremental production of over 50,000 barrels of oil. The primary purpose of this work is to verify and validate stored volumes of CO2, with the ultimate goal of monetizing carbon credits.

Pinnacle reefs have very complex geologic and facies relationships, and as a result, a thorough understanding of the geology is necessary in order to properly monitor and predict �uid movement in the reservoir. Core-calibrated multimineral petrophysical analysis was performed on well logs, and borehole image logs were used to more accurately identify the di�erent facies and determine each facies’ properties along the wellbores. Seismic attribute data interpretations were used to identify the reef versus nonreef facies to aid in the distribution of the facies in the reservoir. These properties were then spatially distributed throughout the reservoir using a combination of multiple-point statistics and object modeling to produce equiprobable reef facies, structure, and volumetric realizations. These equiprobable static realizations were ranked to further use them in dynamic modeling. A few selected static and dynamic realizations were further conditioned to obtain a reasonable match between simulated results and historical data. A more realistic depiction of geological and reservoir features using the modeling approaches adopted in this study is expected to provide more reliable dynamic models for simulating long-term behavior and migration of the injected gas. Predictive simulation runs are in progress to predict original oil in place (OOIP), ultimate incremental oil recovery, and ultimate CO2 storage capacity. Long-term (>100 years) prediction simulations coupled with monitoring data will help in developing a cost-e�ective monitoring plan for ensuring safe and e�ective storage of injected acid gas in the depleted F Pool oil reservoir.

Zama Basin Patch(pinnacle) Reefs

Shekilie Basin

The PCOR Partnership, one of seven regional partnerships funded by the U.S. Department of Energy’s National Energy Technology Laboratory Regional Carbon Sequestration Partnership Program, is managed by the EERC at the University of North Dakota in Grand Forks, North Dakota.

Zama Subbasin

Uses acid gas (70% CO2 and 30% H2S), a by-product derived from the extraction process at a nearby gas-processing plant, for tertiary recovery.

• Cumulative acid gas injected through January 2011: ~90,000 tons

• Net CO2 stored: ~32,000 tons

• Cumulative oil produced: ~52,000 bbl

Simultaneous CO2

EOR and Storage

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Cumulative Oil and Injected CO2 Zama F Pool

Cumulative. Oil (STB)

Cumulative Acid Gas Injection (tons)

Cumulative CO2 Injection (tons)

CO2 Production (tons)

Net CO2 Stored

MUSKEG ANHYDRITEAQUITARD

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100/8-13-

WELL

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-1077 m SS

Spill point

Open Production Perforations

WATT MTN. SHALE

MUSKEG ANHYDRITEAQUITARD

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-1077 m SS

Spill point

Open Production Perforations

WATT MTN. SHALE

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-1106m SS

-1087 m SSGAS/OIL CONTACT(injected acid gas)

-1132 m SSORIGINAL O/W CONTACT

TD-1154 m SS (TVD)

TD-1084 m SS (TVD)

TD-1159 m SS (TVD)

TD-1178 m SS (TVD)

KEG RIVER POOL

1086.9 SS

-1113.6 m SS

-1070 m SS

-1085 m SS

-1093 m SS

103/01-13-116-6W6100/1-13-116-6W6102/8-13-116-6W6116-6W6

DISCOVERY

UNUSED IN EOR

? ? ? ? ? ?

PROD #2 CO2 INJ PROD #1

S

-1087 m SS

Spill point

ZAMA MEMBER

ZAMA MEMBER

77m

108m

142m

Open Injection Perforations

Dolomite Stringer

MDT Intervals

LOWER KEG RIVERAQUIFER

SULPHUR POINT

FT. VERMILLION EVAPORITE (WATT MTN. AQUITARD)

SLAVE PT. AQUIFER

Abdn. Comp.

F Pool -966 m SS

KEG RIVER F POOL

-1089 m SS

-1106m SS

-1087 m SSGAS/OIL CONTACT(injected acid gas)

-1132 m SSORIGINAL O/W CONTACT

TD-1154 m SS (TVD)

TD-1084 m SS (TVD)

TD-1159 m SS (TVD)

TD-1178 m SS (TVD)

KEG RIVER POOL

1086.9 SS

-1113.6 m SS

-1070 m SS

-1085 m SS

-1093 m SS

103/01-13-116-6W6100/1-13-116-6W6102/8-13-116-6W6116-6W6

DISCOVERY

UNUSED IN EOR

? ? ? ? ? ?

PROD #2 CO2 INJ PROD #1

S

-1087 m SS

Spill point

ZAMA MEMBER

ZAMA MEMBER

77m

108m

142m

Open Injection Perforations

Dolomite Stringer

MDT Intervals

LOWER KEG RIVERAQUIFER

SULPHUR POINT

FT. VERMILLION EVAPORITE (WATT MTN. AQUITARD)

SLAVE PT. AQUIFER

Abdn. Comp.

F Pool -966 m SS

PVT (pressure, volume, and temperature) Modeling

• 11-component Peng–Robinson (P–R) equation of state (EOS) PVT model for compositional simulations.• A good agreement between simulated and experimental minimum miscibilty pressures (MMPs) (simulated MMPs were 4.1% higher and 5.5% lower than the measured values for pure CO2 and acid gas [80% CO2 + 20% H2S] mixture) with initial recombined live oil.

Input

GR

NPH

I

RHO

B

PEF

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RT RXO

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PHIE

Faci

es

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S wS oirr

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S o

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Final ROV Init. ROV Exp. ROV

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osity

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Rasterization.

DolomiteBackgroundCalciteOthersQuartzHiBSEHalitePore

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mea

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acie

sP

erm

eab

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ies

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ht

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es

Step 1. Micro-CT scan (nm-to-µm scale)

Step 2. QEMSCAN (µm-to-mm scale)

Step 3. Formation MicroimagingLog Processing and Petrophysics

(cm-to-m scale)

Step 4. Form Reservoir Model (10s of m-to-km scale)

Anhydrite Wackestone/Packstone Grainstone/Floatstone/Rudstone

Porosity Matrix

UPSCA

LE

Low-Permeability Rock Type Facies

General Modeling Work�ow

Seasoned geologists’ interpretation of what the internal microfacies heterogeneity might look like.

Fitting rasterized image to actual reef structure and imported into Petrel.

Mul

tiple

-Poi

nt S

tatis

tics

and

Obj

ect M

odel

ing

Out

put

Training Image Work�ow Three Examples of Facies Realizations

Fluid Inversion Petrophysics

Multiple-Point Statistics and Training Image Production in Schlumberger Petrel®

Uncertainty Analysis for Ultimate Recovery

Initial Conditions(dynamic simulation model in CMG-GEM®)

PVT Modeling in Winprop®

Using Multiple-Point Statistics for Conditioning a Zama Pinnacle Reef Facies Model to Production History

Damion J. Knudsen, Dayanand Saini, Charles D. Gorecki, Steven A. Smith, Wesley D. Peck, James A. Sorensen,

Edward N. Steadman, and John A. Harju Energy & Environmental Research Center, Grand Forks, North Dakota, USA

High-Permeability Rock Type Facies

(response is UR, alpha = 0.05)

Reservoir Volume

Porosity

Recovery Factor

Net/Gross

Boi

Soirr

Swirr 95th Percentile

Fact

ors

0 10 20 30 40

Results

(P90)(P50)

(P10)

(P90)(P50)(P10)

(P90) (P50) (P10)

Tight Facies

Permeable Facies

Well Control

Soft ProbabilitiesUsed as Input for

Multiple-Point Statistics

Oil–Water Contact (OWC)

Original Seismic Surface

• OOIP ≈ 3.9 million stock tank barrels (MMSTB [material balance-based calculation]).• Initial reservoir pressure = 2095 psi. • Reservoir temperature = 160°F.• Saturation pressure = 1275 psi.• Initial gas/oil ratio = 284 scf/stb.• API gravity = 35.2°.• 1.1 MMSTB (28% of OOIP) of oil was produced during a 20-year period (1967–1987) of primary depletion aided by bottom aquifer in�ux through a single well.• Pressure and production behavior indicates the presence of weak bottom aquifer support.

Porosity and permeability realizations populated into the model using the sequential Gaussian simulation algorithm.

History Matching

The P10 OOIP (4.45 MMSTB) realization was selected for performing history matching. Both sets of relative permeability (oil–water and gas–oil) curves for tight reservoir (Rock Type 1) and good reservoir rocks (Rock Type 2) were modi�ed to achieve a satisfactory history match. In addition to the modeled reef structure below the OWC, a small numerical aquifer with no leakage option was also added at the bottom of the structure for improving simulated pressure response.

Cum

ulat

ive

Oil

SC, b

bl

Cum

ulat

ive

Gas

SC,

ft3

Wel

l Bot

tom

hole

Pre

ssur

e, p

siG

as R

ate

SC, f

t3 /da

y

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er R

ate

SC, b

bl/d

ay

Time, date

Time, date Time, date

Time, date

Summary

Bibliography

Results

Next Steps

Gravity Equilibrated Oil Saturation Above the OWC Accomplished by Using a Hetrogeneous Swirr Realization as Input

in the Simulation

Gas per Unit Area (total) at the Start of Acid Gas Injection

Oil Saturations at the End of History Match Period

OWC

• Further history matching with other static realizations and predictive dynamic simulations are in progress to evaluate the potential for maximizing incremental oil recovery through optimum well locations and injection–production strategies to study the long-term behavior of acid gas plumes and to predict ultimate CO2 storage capacity.

• The work�ow adopted in the project will be used to evaluate more pinnacle reefs in the Zama Subbasin.

• Multiple-point statistics algorithm and object modeling work�ow were successfully used for characterizing and modeling complex oil-producing carbonate pinnacle reef structure.

• A good agreement between the historical data (production, gas injection, and pressure) and simulated results was obtained with minimal reconditioning of both static and dynamic models.

Asghari, K., 2005, Zama Keg River F Pool �eld-scale CO2-�ood simulation study: Report for Apache Canada Ltd., March.

Buchkuehle, M., Haug, K., Michael, K., and Berhane, M., 2007, Regional-scale geology and hydrogeology of acid-gas enhanced oil recovery in the Zama oil �eld in northwestern Alberta, Canada: Alberta Energy and Utilities Board, Alberta Geological Survey, June.

Burke, L., 2009, PCOR project Apache Zama F Pool acid gas EOR and CO2 storage: Report by RPS Energy Canada for the Energy & Environmental Research Center, September.

Initial Oil Saturation Initial Gas Saturation

Gas Saturations at the End of History Match Period

EERCEnergy & Environmental Research Center®

Putting Research into Practice

AAPG Annual Convention & Exhibition, April 2012

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© 2012 University of North Dakota Energy & Environmental Research Center