Enhanced Gravity Drainage Through Immiscible CO 2 Injection

Enhanced Gravity Drainage Through Immiscible CO 2 Injection in the Yates Field (Tx) Paul Button and Chris Peterson Kinder. Morgan 10 th ANNUAL CO 2 FLOODING CONFRENCE Midland, TX December 2004 www. spe-pb. org

Yates Field Unit - Location Map N HW T R LF E H S EST NO MIDLAND BASIN LF BASIN SHE DELAWARE L CENTRA RM PLATFO SHEFFIELD CHANNEL 0 25 MILES 50 • ~ 90 miles South Midland/Odessa ERN Midland TEXAS T EAS BASIN NEW MEXICO VA LV BA ERD SIN E YATES FIELD HIGH POINT OF CBP • SE tip of Central Basin Platform • Structural high point of the CBP • 26, 423 Acres

General Facts & History • Field Discovery - October 28, 1926 (Ira Yates’ 67 th birthday) • Discovery Well: I. G. Yates A No. 1 (Unit Well No. 4901)

Structure on Top of the San Andres Formation Vertical Exaggeration ~ 9 x. North

Type of Reservoir • Highly Fractured Carbonate

Stratigraphy 1 -D Interpretation Indicator Facies 50 meters Fusulinid packstone/grainstone HFS 3 HFS 4 HFS 5 CGR HFS 2 11 km HFS 5 Middle shelf Ramp crest HFS 4 HFS 3 HFS 2 HFS 1 Outer ramp Shelf crest Inner slope

East-West Permeability Slice High Permeability Zones

3 -D View of San Andres Structure with Fracture Connection Overlay

Yates Original Oil in Place (OOIP) 7 Rv/Qn/Gbg Gross BBO. 0. 5 SA (above +1, 050’) SA (+950’ to +1, 050’) 2. 8 1. 4 +1, 050’ Total (above +950’) 4. 2 +950’ SA (below +950’) 0. 3 TOTAL 5. 0

Production History BOPD Great Depression Unitization WWII

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

General Facts & History Gas Plant built in 1961 to recover natural gas liquids and prevent flaring

General Facts & History West Side of Field -Waterflood started in 1979 -Produced using pumping units -Polymer injection from 1983 - 1989 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

General Facts & History 1985 -1991 CO 2 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 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 WALRUS Process

General Facts & History 1998 – Water Export commenced for reservoir management

General Facts & History 1999 – 2002 Steam injection pilot was run; post -evaluation in progress.

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 CO 2 Injection (1985 - 1991) • Double Displacement Process (Co-Production) (1993 -2000) • Gravity Drainage (2000 – Present)

Yates Field Reservoir Secondary Pressure Maintenance Recovery Processes Primary Depletion Tertiary CO 2 PAW Tertiary DDP Tertiary Thermal WALRUS Gravity Drainage Process Unit Formed

l-7 Ju 6 l-7 Ju 7 l-7 Ju 8 l-7 Ju 9 l-8 Ju 0 l-8 Ju 1 l-8 Ju 2 l-8 Ju 3 l-8 Ju 4 l-8 Ju 5 l-8 Ju 6 l-8 Ju 7 l-8 Ju 8 l-8 Ju 9 l-9 Ju 0 l-9 Ju 1 l-9 Ju 2 l-9 Ju 3 l-9 Ju 4 l-9 Ju 5 l-9 Ju 6 l-9 Ju 7 l-9 Ju 8 l-9 Ju 9 l-0 0 Ju Effective Free Gas Additions (MCFPD) YFU Extraneous Gas Injection 120000 90000 60000 30000 0 Flue gas CO 2 C 1 N 2 Solution gas

Yates Reservoir History Discovery: 1926 Discovered in 1926 550’ of Oil Column at Structure Top 1926 - 1976 Produced By Individual Operators Unitized in 1976 to Prevent Aquifer Influx 1976 - 1992 Gas Re-injected, Water Re-injected Oil Column Thinned 1992 - 2000 Gas Cap Inflation Reservoir Dewatering Contact Lowering 2000 - 2005 Contact Stabilization Gas Cap Injection Aquifer “Maintenance” By Offsite Disposal

Yates Field Unit Saturation Profile Frac GOC Frac WOC GOC Matrix Frac Matrix + 1200 WOC + 1050 GOC WOC + 850 1926 1976 1990’s Present

Reservoir Review So, Why Gravity Drainage?

Reservoir Recovery Process Screening Formation Porosity % Displacement Processes 30 Gr a Re vity pla An cem d C en apill t. P a roc ry ess es Yates Neutral Zone Depletion Processes 0 Low Total Formation Heterogeneity High

Matrix surrounded by fluid-filled fractures

Matrix exposed to gas-filled fractures

Matrix exposed to gas-filled fractures

Matrix exposed to gas-filled fractures

Mobilization 1) Oil drains vertically through matrix until downward movement is limited by phase mobility. GOC WOC

Mobilization 1) Oil drains vertically through matrix until downward movement is limited by phase mobility. GOC WOC 2) When vertical mobility is limited, the oil migrates laterally into fractures and is Mobilized to be available for Capture.

Operations – Material Balance ~109 MMCFD CO 2 ~222 MMCFD ~113 MMCFD Prod ~17. 6 MMCFD N 2 Vent ~14. 8 MMCFD Fuel ~3. 3 MMCFD Gas Sales ~550 NGLPD ~417, 000 BWPD ~151 MMCFD ~24, 500 BOPD +1050 Original WOC +1015 Current WOC Produced Gas Composition N 2 CO 2 H 2 S HC ~41% ~30% ~3% ~26% +1040 Current GOC ~392, 000 BWPD ~25, 000 BWPD Export

Average Contacts – Connected Wells

Resaturation 1) Resaturation is controlled by maintaining the position of the contacts 2) Goal - prevent downward movement of the oil column So Sw to. 89 to. 11 GOC = 1045’ WOC = 1015’

Yates Horizontal Drilling Operations/Results Horizontal Drain Hole Re-establish fracture connections Gas Oil Water At a lower elevation and thinner column, the fracture connectivity within the oil column is reduced. Production response from HDH wells

Why CO 2 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 CO 2 – Reasonable cost and positive compositional effects

Why Immiscible CO 2 Will Work at Yates • Compositional effects of Nitrogen Injection – Strips light end components – Increase oil viscosity – Negative impact on Kro • Compositional effects of Immiscible CO 2 – Decrease oil viscosity • Lab tests ~ -25 % from “Non-stripped“ sample • Lab tests ~ -50 % from “N 2 stripped“ sample • Model ~ 30 % from N 2 processed oil – Positive impact on Kro • Lab tests ~ 5 % from “Non-stripped“ sample • Lab tests ~ 12 % from “N 2 stripped“ sample • Model ~ 7 -8 % from N 2 processed oil • CO 2 injection results in improved oil mobility vs. Nitrogen injection Oil Mobility = K * Kro m

Yates Compositional Model History Match - Reasonable match on all fluids - Major oil difference due to documented leak oil - Water match on exported water -Reasonable pressure match - Discrepancy due to large difference in fluid contacts across the reservoir in late 80’s and 90’s

Yates Compositional Model History Match -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 CO 2 Injection Project

Immiscible CO 2 Injection Design • Vertical Placement – Concentrate CO 2 within 50’ of current GOC • Areal Placement – NW portion of Field (Area with high N 2 content) • Planned CO 2 Migration CO 2 Target Area – Vertical • Migration Upward to GLM – Areal • Recycle through Gas Plant and injected in SE Area CO 2 Recycle Area

Implementation of Immiscible CO 2 Injection • CO 2 injection started March 1 st 2004 • Used existing infrastructure to distribute CO 2 to injection wells • Converted gassed-out horizontal producers to CO 2 injectors within 50’ of current gas-oil contact • Initiated injection at 42. 5 MMCFD of CO 2 • N 2 Rejection started March 2005 • Current CO 2 injection rate 109 MMCFD

Cumulative CO 2 Injected Since March, 2004 Total CO 2 Injected = 45. 7 BCF CO 2 Inj. Well Gas Inj. Well CO 2 Area Non-CO 2 Area

CO 2 Injection – Assessment Different GOR Behavior CO 2 Area Is Oilier Different Vertical Declines Non-CO 2 Area

CO 2 Injection – Assessment

CO 2 Injection – Assessment

CO 2 Injection – Assessment

CO 2 Injection – Assessment

CO 2 Injection – Assessment

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 CO 2 Injection Project

8801 OBS 8816 Flush oil from thinning Imitates CO 2 response 8815

Yates CO 2 Expansion Options • Modify Existing Facilities – Increase N 2 Rejection (to 30+ MMCFD) • CO 2 Processing – Expand Delivery Capacity • Pipeline Pump – Mix CO 2 with Recycle Gas • New Facility Potential – New gas processing facility N 2 Rejection – Additional Pipeline for CO 2 Delivery – Simulation Driven