1. 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

2. 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

3. General Facts & History
Field Discovery - October 28, (Ira Yates’ 67th birthday)
Discovery Well: I. G. Yates A No (Unit Well No. 4901)
Drilled to ~1000 ft.

4. 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.

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

6. 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

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

8. 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

9. Yates Original Oil in Place (OOIP)
Gross
BBO .
7Rv/Qn/Gbg
SA (above +1,050’)
SA (+950’ to +1,050’)
Total (above +950’)
SA (below +950’)
TOTAL
+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 B bbl produced 28%... So there is much left

10. 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

11. General Facts & History
Field Discovery - October 28, 1926
Highest Oil Rate = 205,000 BPD (Well No 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.

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

13. General Facts & History
West Side of Field
Waterflood started in 1979
Produced using pumping units
Polymer injection from
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

14. General Facts & History
CO2 injected into the gas cap on east side of the field for pressure maintenance
Tax advantage… wind fall profits

15. General Facts & History
1993 – Nitrogen injection from ASU #1 (30 MMCFD) initiated for pressure maintenance
1996 – ASU #2 (60 MMCFD) increased nitrogen injection.

16. General Facts & History
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
yr treatment… continue evalutation

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

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

19. 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 ( )
East Side CO2 Injection ( )
Double Displacement Process (Co-Production) ( )
Gravity Drainage (2000 – Present)

20. 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

21. YFU Extraneous Gas Injection
120000
90000
Effective Free Gas Additions (MCFPD)
60000
N2 185 BCF
Flue Gas 36 BCf
CO2 96 BCF
C 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

22. 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
Gas Re-injected, Water Re-injected
Oil Column Thinned
Gas Cap Inflation
Reservoir Dewatering
Contact Lowering
Contact Stabilization
Gas Cap Injection
Aquifer “Maintenance” By Offsite Disposal

23. 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

24. Reservoir Review
So, Why
Gravity Drainage?

25. Reservoir Recovery Process Screening30
Gravity And Capillary
Replacement Processes
Yates
Formation Porosity %
Displacement Processes
Neutral
Zone
Depletion Processes
Low
High
Total Formation Heterogeneity

26. by fluid-filled fractures
Matrix surrounded
by fluid-filled fractures

27. Matrix exposed to
gas-filled fractures

28. Matrix exposed to
gas-filled fractures

29. Matrix exposed to
gas-filled fractures

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

31. 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.

32. 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

33. Average Contacts – Connected Wells

34. 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’

35. 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

36. 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

37. 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

38. 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

39. 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

40. Projected Oil Response from Yates Immiscible CO2 Injection Project

41. 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

42. 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

43. Cumulative CO2 Injected Since March, 2004
Total CO2 Injected = 45.7 BCF
CO2 Inj. Well
Gas Inj. Well
CO2 Area
Non-CO2 Area

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

45. CO2 Injection – Assessment

46. CO2 Injection – Assessment

47. CO2 Injection – Assessment

48. CO2 Injection – Assessment

49. CO2 Injection – Assessment

50. Current Production

51. 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

52. Projected Oil Response from Yates Immiscible CO2 Injection Project

53. 8801 OBS
8816
Flush oil from thinning
Imitates CO2 response
8815

54. 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