Paul Button and Chris Peterson KinderMorgan Enhanced Gravity Drainage Through Immiscible CO2 Injection in the Yates Field (Tx) Paul Button and Chris Peterson KinderMorgan 10th ANNUAL CO2 FLOODING CONFRENCE Midland, TX December 2004 www.spe-pb.org

Yates Field Unit - Location Map MILES 25 50 DELAWARE BASIN MIDLAND NEW MEXICO TEXAS N CENTRAL PLATFORM NORTHWEST SHELF EASTERN SHELF SHEFFIELD CHANNEL Midland YATES FIELD - HIGH POINT OF CBP VAL VERDE ~ 90 miles South Midland/Odessa SE tip of Central Basin Platform Structural high point of the CBP 26,423 Acres Typical locator 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) Drilled to ~1000 ft.

Structure on Top of the San Andres Formation Vertical Exaggeration ~ 9x. North What they found, discovery well near the peak of structure ~750’ of structure to bottom oil saturation, ~600 to orig fracture OWC.

Type of Reservoir Highly Fractured Carbonate San Andres Formation, 95% dolomite, limestone, vuggy, cavy, Fractured

Stratigraphy 1-D Interpretation Indicator Facies CGR 50 meters 1-D Interpretation HFS 5 HFS 4 HFS 3 HFS 2 Fusulinid packstone/grainstone Indicator Facies This is the best I can do for geologists… Flatten the structure to a geologic marker (7 Rivers M ?), depositional environment could have looked something like this. Middle shelf Shelf crest Inner slope HFS 2 HFS 3 HFS 4 Ramp crest HFS 1 Outer ramp HFS 5 11 km

East-West Permeability Slice High Permeability Zones Slice through near center of the field Shows character of uplift and direction of the sediment beds…

3-D View of San Andres Structure with Fracture Connection Overlay What the uplift did was fracture the heck out of the rock Red areas show interpretation of where high concentrations of fractures should be. Generally verified by production

Yates Original Oil in Place (OOIP) Gross BBO . 7Rv/Qn/Gbg 0.5 SA (above +1,050’) 2.8 SA (+950’ to +1,050’) 1.4 Total (above +950’) 4.2 SA (below +950’) 0.3 TOTAL 5.0 +1,050’ +950’ In operating Yates we use depths relative to sea level because of surface topography Smaller number is deeper since closer to sea level 1050 is around the elevation of Gas Oil contact 950 is estimated elevation of original Oil Water Contact 1050 is original free water in matrix 1015 current WOC 1.4 B bbl produced 28%... So there is much left

Production History Great Depression Unitization WWII BOPD Flat prod rates caused by allowable restrictions thru mid 80’s Finally water encroachment, pressure maintenance, depletion caused decline Bump late 90’s from aggressively expanding the gas cap, moving the oil column down Late time flattening from HDH and oil column optimization

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 Quick run through field trivia and major recovery processes tried.

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 CO2 injected into the gas cap on east side of the field for pressure maintenance Tax advantage… wind fall profits

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 98-99 smaller, huff-puff treatments, 6 mo continuous 2000 1 yr treatment… continue evalutation

General Facts & History 1998 – Water Export commenced for reservoir management North of field inj wells, McCamey, McElroy

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 CO2 Injection (1985 - 1991) Double Displacement Process (Co-Production) (1993-2000) Gravity Drainage (2000 – Present)

Yates Field Reservoir Recovery Processes Tertiary DDP Secondary Pressure Maintenance Tertiary CO2 PAW Tertiary Thermal WALRUS Primary Depletion Gravity Drainage Process Unit Formed Production curve with recovery processes showing effects

YFU Extraneous Gas Injection 120000 90000 Effective Free Gas Additions (MCFPD) 60000 N2 185 BCF Flue Gas 36 BCf CO2 96 BCF C1 3.6 BCF ~ 300 BSCF of Gas Cap ~ 1.2 Brb of Gas Cap 30000 Jul-76 Jul-77 Jul-78 Jul-79 Jul-80 Jul-81 Jul-82 Jul-83 Jul-84 Jul-85 Jul-86 Jul-87 Jul-88 Jul-89 Jul-90 Jul-91 Jul-92 Jul-93 Jul-94 Jul-95 Jul-96 Jul-97 Jul-98 Jul-99 Jul-00 Flue gas CO2 C1 N2 Solution gas

Yates Reservoir History Discovered in 1926 550’ of Oil Column at Structure Top Discovery: 1926 Produced By Individual Operators Unitized in 1976 to Prevent Aquifer Influx 1926 - 1976 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 Frac Frac GOC + 1200 Frac Matrix Matrix Matrix Matrix GOC WOC WOC + 1050 GOC WOC Matrix and Frac cartoon Primary depletion until 1976 bottom water drive, gas evolved below bubble point and migrated Extraneous gas injection expanding the gas cap, mining of water pushing contacts back down Expose high oil saturation rock to gravity drainage WOC + 850 1926 1976 1990’s Present

Reservoir Review So, Why Gravity Drainage?

Reservoir Recovery Process Screening 30 Gravity And Capillary Replacement Processes Yates Formation Porosity % Displacement Processes Neutral Zone Depletion Processes Low High Total Formation Heterogeneity

by fluid-filled fractures 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 CO2 ~222 MMCFD ~113 MMCFD Prod ~17.6 MMCFD N2 Vent ~14.8 MMCFD Fuel ~3.3 MMCFD Gas Sales ~417,000 BWPD ~550 NGLPD ~151 MMCFD ~24,500 BOPD +1050 Original WOC +1040 Current GOC +1015 Current WOC ~392,000 BWPD Produced Gas Composition N2 CO2 H2S HC ~41% ~30% ~3% ~26% ~25,000 BWPD Export

Average Contacts – Connected Wells

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

Yates Horizontal Drilling Operations/Results Horizontal Drain Hole Re-establish fracture connections Production response from HDH wells Oil Gas Water At a lower elevation and thinner column, the fracture connectivity within the oil column is reduced. HDH recompletions support production and flatten decline, but decline resumes when drilling stops

Why CO2 at Yates ?? Possible EOR Processes 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 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 CO2 Injection Project

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 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 Total CO2 Injected = 45.7 BCF CO2 Inj. Well Gas Inj. Well CO2 Area Non-CO2 Area

CO2 Injection – Assessment Different GOR Behavior CO2 Area Is Oilier Different Vertical Declines Non-CO2 Area

CO2 Injection – Assessment

CO2 Injection – Assessment

CO2 Injection – Assessment

CO2 Injection – Assessment

CO2 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 CO2 Injection Project

8801 OBS 8816 Flush oil from thinning Imitates CO2 response 8815

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