CO2 Flooding the Elm Coulee Field

Abstract

The Elm Coulee Field has extremely low permeability for an oil reservoir (0.01 - 0.04 md), which has caused an unconventional approach to its development by drilling long horizontal wells and massively fracturing them. The primary recovery factor, however, remains very low, around 5–10%. Significant reserves are available for post-primary production, yet the low permeability value restricts the choices available; for example, water flooding results in low injectivity. CO2 flooding may prove to be the most suitable option; however, the performance of CO2 flooding in this type of reservoir is not well understood. Using this field as an example, this paper presents the effects of CO2 flooding horizontal wells in a tight oil reservoir where hydraulic fractures provide the main path for fluid flow. To analyze the impact of CO2 flooding in the Elm Coulee Field, a sector of the field is selected for reservoir modeling. The sector is two miles by two miles and consists of six, single-lateral horizontal wells. Two different reservoir models are built for the sector: a primary recovery and a CO2 flood model. They are used to determine the additional recovery due to a CO2 flood. Furthermore, the CO2 flood model is executed with different scenarios to determine the best well locations and injection schemes. The models demonstrate that CO2 flooding horizontal wells in Elm Coulee Field increases production. Comparison of vertical and horizontal injection techniques indicates continuous horizontal CO2 injection is more efficient; it yields higher injection rates, and it is also beneficial for long-term recovery. Focusing on horizontal injection, the best scenario involves the practice of drilling new injectors along with converting existing producers to injection wells. In order to satisfy production requirements, production wells can be drilled such that there is an injector between two producers. This type of arrangement on horizontal injection increases the field recovery factor by 16 % after eighteen years of injection. The increase associated with single-well cyclic injection treatment is only 1 %; but in the absence of continuous CO2 supply, this method may be applicable for increasing recovery from reservoirs similar to Elm Coulee Field. This research project demonstrates the technical aspects of CO2 injection in the context of Elm Coulee Field, while the economics are not considered. Developing a CO2 flood in this field appears feasible; however, the price of oil and the cost of drilling or converting wells will affect which, if any, is the best option. Introduction The rising energy demand is influencing the petroleum industry to exploit unconventional oil reservoirs and develop them to the maximum potential. The Elm Coulee Field, located in Richland County, Montana, is a distinctive example and the focus of this research. Discovered in 2000, the Elm Coulee Field is producing approximately 50,000 barrels of oil per day from the Bakken Formation in the Williston Basin Province of Montana. The Bakken Formation, located in the subsurface of Williston Basin, covers parts of Montana, North Dakota, South Dakota, Saskatchewan, and Manitoba (Figure 1). Geology-based assessments conducted on the Bakken Formation of Montana and North Dakota alone have estimated mean undiscovered volumes of 3.65 billion barrels of oil and 1.85 trillion cubic feet of associated/dissolved natural gas1. For the case of Elm Coulee Field, which is a tight oil reservoir covering an area of 529 square miles, it has an estimated oil-in-place of 5 million barrels per square mile2 and expected to produce over 270 million barrels of oil3. In order to secure the economic future of such a novel development, it is necessary to evaluate the application of enhanced oil recovery (EOR) in this region.

Hydraulic Fracture Orientation for Miscible Gas Injection EOR in Unconventional Oil Reservoirs

“…Miscible gas injection may become the most effective method in such lower permeability fields, because conventional water flooding may result in extremely lower injectivity. This work expands on previous research from Shoaib and Hoffman (2009) which focused on the Elm Coulee field in Eastern Montana and showed miscible gas injection may be a possible solution for shale oil reservoirs. The wells in their study had longitudinal hydraulic fractures, whereas today most wells have transverse fractures.…”

A numerical simulation study of CO2 injection for enhancing hydrocarbon recovery and sequestration in liquid-rich shales

“…The initial water saturation is 0.30. The relative permeability curves closely matched the curves obtained by history matching for the Elm Coulee field in North Dakota (Shoaib and Hoffman 2009).…”

Effect of large gas-oil capillary pressure on production: A compositionally-extended black oil formulation

“…Thus, the reservoir model is a single porosity system. Relative permeability curves are adapted from Shoaib and Hoffman (2009) and are shown in Fig. 16.…”