Completed slim-tube tests for MMP measurement. Completed swelling tests. Completed phase behavior model. Completed preliminary geological model. At 110 °F, MMP determined from slim-tube test is

1,350 psig. At 110 °F, near-miscible pressure range defined from

this study is between 1,150 and 1,350 psig. At pressure near miscible, extraction or vaporization is

a primary mechanism for mass transfer. Oil viscosity reduction factor of five is achieved in the

near miscible region with injection of CO2.

Near Miscible CO2 Application to Improve Oil Recovery for Small Producers

RPSEA Small Producer Program

Core flooding test with CO2 displacement to determine incremental oil recovery from

residual oil after waterflooding (Sorw) with Berea core.

repeat same tests with Arbuckle cores. Construction of reservoir model to history match

the field operation and predict the recovery from the field by CO2 injection at near miscible conditions.

In Progress

Description Arbuckle Arbuckle Berea SS Berea SS Berea SS Berea SS

Core sample C1 C1 A1 Epoxy A1 Epoxy A1 Epoxy A1 Epoxy

Temperature (°F) 86 86 86 110 110 110

Pressure (psia) 14.7 14.7 14.7 1380 1320 1200Length (cm) 4.82 4.82 5.86 5.86 5.86 5.86

Diameter (cm) 2.48 2.48 2.52 2.52 2.52 2.52PV (cc) 3.26 3.26 5.80 5.80 5.80 5.80Porosity 0.15 0.15 0.2 0.2 0.2 0.2

Permeability (md) 58 58 332 239 212 252Swc 0.38 0.37 0.33 0.38 0.32 0.34Ko 56 58 228 119.1 112.2 134.6

Kro@Swc 0.97 1.00 0.69 0.50 0.53 0.53Sor 0.37 0.4 0.26 0.62 0.50 0.47Kw 11.8 10.9 23.5 16.1 15.3 16.7

Krw@Sor 0.20 0.19 0.07 0.07 0.07 0.07

Brine solution: 0.5 wt% Calcium chloride and 0.5 wt% Magnesium chlorideCrude oil: Ogallah oilArbuckle core: Hadley L#4 well, depth 3605 ft, Bemis-shutts, Ellis County, Kansas

Characterization of core sample

CO2 Displacement @ 1320 psia, 110°F

Recovery of Remaining oil with CO2 Injection @ 110 °F

Structure top and flow unit were constructed from log stratification study

Porosity was estimated from log analysis and an in-house developed correlation between micro log and density neutron log.

Permeability was derived from a correlation based on published petrophysical properties by Franseen, E. K. and Byrnes, A.P. (1999 AAPG, A18).

Geological model

Arbuckle

Reagan

Granite

Oil Field: Ogallah Unit, Trego County, Kansas Formation depth: 3950-4060 ft Formation temperature: 110 °F Reservoir pressure: ~1150 psia Total number of wells: 133 Active producers: 18 Average thickness: 22 ft Average porosity: 0.10 Average permeability: 12 md Original oil in place: 9.1 MMSTB Original water in place: 16.1 MMSTB Mobile oil: 3.2 MMSTB

Reservoir model

Paper to be Presented

• "Laboratory Investigations of CO2 Near Miscible Application in Arbuckle Reservoir" paper SPE-129710 to be presented at 2010 SPE Improved Oil Recovery Symposium, Tulsa, April 24-28.

• "Swelling/Extraction Test of a small sample size for Phase Behavior Study" paper SPE-129728 to be presented at 2010 SPE Improved Oil Recovery Symposium, Tulsa, April 24-28.