A Denver-based independent energy company plans to develop oil reserves in Wyoming’s Powder River Basin through the application of modern reservoir management practices and secondary and tertiary recovery techniques to enhance production on mature, historically productive fields with proven in-place reserves.

Specifically, Rancher Energy Corp. plans to develop its existing properties through waterflood and CO2 injection, which should allow the company to recover substantial oil reserves that are not accessible through primary production techniques. The operating company owns three oil fields in Wyoming’s Powder River Basin — the Big Muddy, South Glenrock B and Cole Creek South fields.

Rancher Energy is pursuing its secondary and tertiary enhanced oil recovery (EOR) strategy because the management believes this offers significant upside potential while not exposing the company to risks typically associated with drilling newfield wildcat wells in frontier basins.

Rancher Energy engaged a Denver-based reservoir consulting firm, NITEC LLC, to complete a simulation and extensive technical review concerning the operator’s three fields via CO2 flooding. NITEC concluded that the fields represent a compelling development opportunity and are particularly well suited to a full-field continuous CO2 flood injection program to enhance oil recovery to the maximum extent possible.

NITEC estimates that these fields collectively contain at least 424.1 million bbl of original oil in place (OOIP) supported by more than 90 years of hydrocarbon development and production data.

Total production to date as a percentage of OOIP for the Cole Creek South and South Glenrock B fields equals about 34%, and for the Big Muddy field, only 12%.

Rancher Energy expects an incremental recovery factor of 19 to 20% of the OOIP, with potential additional recoverable oil of approximately 90 million bbl for all three fields. The operating company paid approximately US $74 million to acquire its three fields. (Note that a candidate field for tertiary oil recovery using CO2 injection must yield a minimum of 5 million bbl of recoverable oil due to the cost of CO2 surface, injection and other facilities).

CO2 injection has been used successfully for 35 years throughout the Permian Basin of West Texas and eastern New Mexico and is now being pursued in Kansas, Mississippi, Wyoming, Oklahoma, Colorado, Utah, Montana, Alaska and Pennsylvania.

Today there are more than 80 CO2 EOR projects in existence in the United States, and more than 240,000 b/d of oil are being produced by CO2 injection. Because the sources and methods of transportation of CO2 are limited, only 240,000 b/d of oil, or 3% of the current US domestic oil production, is derived from tertiary recovery projects.

As the price of crude oil has risen, CO2 injection projects have become economically feasible, and the US Department of Energy has estimated that full use of “next-generation” EOR techniques in the United States could generate an additional 240 billion bbl of recoverable oil resources.

CO2 is a super-critical fluid that has the density of a liquid and the viscosity of a gas. Super-critical CO2 is easy to meter and pump. In most cases, CO2 is pumped at pressures of about 1,500 to 2,000 psi.

When CO2 is injected into an oil reservoir at sufficient pressure, the CO2 will become miscible with the oil. The pressure at which miscibility is first achieved is called the minimum miscibility pressure (MMP). At or above its MMP, CO2 becomes an ideal solvent for oil, and because of this it displaces oil from the reservoir much more efficiently than water. It picks up lighter hydrocarbon components, swells the total volume of oil, reduces its viscosity and physically washes the oil from the reservoir.

Low-gravity oil tends to have high MMPs. High-viscosity oils have very unfavorable mobility ratios.

The depth must be great enough for the reservoir rock to have a high enough fracture pressure to contain the CO2 above the MMP. The higher the temperature, the higher the MMP. (If the depth is great enough, a high temperature may not preclude miscible flooding). The residual oil must be great enough so that there is a target for CO2 EOR.

The feasibility of a CO2 injection strongly depends on reservoir temperature, pressure and crude oil composition. The oil requirements along with the Rancher Energy figures are listed in the table.

Rancher Energy’s CO2 strategy first entails the reactivation of the waterflood program in the Big Muddy field followed by CO2 injection.

This is because current reservoir pressure in the Big Muddy field is not sufficient for effective CO2 flooding at this time. The injection of this water not only should enable the secondary recovery of oil, but it also should raise the field’s reservoir pressure to a level sufficient for CO2 injection operations.

The Big Muddy waterflood project plan anticipates sourcing external funds in a staged manner, drawing approximately US $50 million of marginal finance over two years, together with internally generated funds, to conduct up to 100 sq miles (259 sq km) of 3-D seismic, drill and equip approximately 70 wells, and complete waterflood surface facilities. CO2 deliveries are anticipated to start early in 2010.

By this time the reservoir pressure in the Big Muddy field should be above the minimum miscibility pressure and a sufficient number of wells should be drilled to commence the CO2 flood. The CO2 plan anticipates sourcing external funds in a staged manner, drawing approximately $200 million ($150 million net of the waterflood plan) of marginal finance over five years, together with internally generated funds, to construct a CO2 pipeline to the field, drill and equip 70 to 80 additional wells, and construct surface and compression facilities to inject and recycle CO2.

The injection patterns for the waterflood envision five-spot patterns. The CO2 injection patterns envision inverted nine-spot patterns and necessarily are different from the water injection patterns in order to maximize the reservoir sweep and provide a flexible starting pattern that can be quickly changed to react to new reservoir information that comes to light during the injection of CO2.

For its injection program Rancher Energy will require a volume of approximately 90 MMcf/d of CO2.

It is expected that the Big Muddy field will require approximately 40 MMcf/d, the South Glenrock B and Cole Creek South fields together approximately 40 MMcf/d, leaving 10 MMcf/d available for future expansion plans.

Wyoming, specifically the Powder River Basin, greatly benefits from ExxonMobil’s LaBarge gas field and Shute Creek gas treatment plant in southwestern Wyoming, which generate an immense supply of CO2 that is transported through pipelines to various CO2 injection points. The region has been slow to implement CO2 injection strategies but has experienced rapid growth in the past decade.