New technology in horizontal drilling and stimulation has caused production from ultra-tight oil formations to increase rapidly over the last decade. While initial rates are high, recovery factors for these types of reservoirs are predicted to be low, around 5–10%. Unlike conventional reservoirs, water flooding does not appear to be a viable secondary option due to its low injectivity. Recent analysis has shown that gas injection may be an effective alternative. A 4-section area of the Elm Coulee field in eastern Montana is used to study the impact of different gas injection schemes: carbon dioxide, immiscible hydrocarbon and miscible hydrocarbon. This paper examines the difference in total recovery, production rate and efficiency using a flow simulation model. Recovery efficiency is similar for both miscible hydrocarbon gases and carbon dioxide with recoveries increasing from 6% on primary production to around 20% with gas injection. While the increased recovery is encouraging, both methods have some practical limitations. Carbon dioxide is currently unavailable in many basins, and while hydrocarbon gases are available in most oil fields, they are rarely used as injectants because they are marketable. We performed a cost-benefit analysis of selling the hydrocarbon gas versus using it to increase oil production. We assumed a $10 million investment in compression and facilities for the 4-section area, and used a $5/mscf cost for the gas and $80/stb revenue for the oil. The net present value for these criteria in this area is $68 million and the rate of return is 83%. The value of this work is that it demonstrates that injecting gas (both immiscible and especially miscible) will appreciably increase oil recovery in very low permeability reservoirs. These types of reservoirs are becoming more prevalent, and a large prize is available to those who find ways to increase recovery from them. In the case of hydrocarbon gas, the economics appear to be favorable for current commodity prices.

The Eagle Ford formation has been an overwhelming success producing around 2 billion barrels of oil over the last seven years, yet its potential may be even greater. The projected recovery factor is only 5-10%, and using improved oil recovery (IOR) methods to increase recovery could result in billions of additional barrels of production. Significant research is required to access this oil, and while a number of companies have field tested an IOR method called huff-n-puff gas injection, most of the published results are from lab and modeling studies. This paper evaluates the results from these field tests and discusses the successes and opportunities. The huff-n-puff process involves injecting a miscible gas into a well, and then after some amount of time, producing back from that same well. The first part of this paper evaluates the publically available data from the Texas Railroad Commission and other sources for these pilots. Analytical techniques are used to predict the amount of additional recovery and the pattern efficiency from this data. This is compared to pre-injection forecasts. All cases show increased production rates with injection, and in one pattern where the data was easiest to interpret, the incremental production has doubled since the huff-n-puff project started. This paper also proposes methodologies for implementing second generation pilots for unconventional reservoirs. It is important to define clear objectives that characterize the value of the pilots. The significance of developing optimum drilling and completion strategies for primary and IOR success is also highlighted. Long term information collecting strategies are proposed along with methods to optimize the projects during the pilot, and contingency plans to deal with difficulties that may arise. Finally, we discuss how the location and infrastructure needs of a pilot are paramount to its success. Using IOR to increase recovery from unconventional oil fields is important for the continued success of plays like the Eagle Ford. Pilot tests are an integral part of developing the best IOR techniques, and this paper provides a thorough analysis of implementing IOR pilots in the Eagle Ford. It also shows how and where it has been applied successfully and discusses ideas to further improve the likelihood of success in the future.

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.

No abstract

The Bakken is among the shale reservoirs which have been discovered to hold a vast amount of oil resource contributing to the production boom in the US. This unconventional reservoir, like most others, displays favorable initial production rates due to stimulation by hydraulic fracturing, but production rates quickly decline after few months. Due to the extremely low permeability and low recovery factors, miscible gas injection is considered for improving the recovery of oil in the Bakken formation. Feasibility of miscible gas injection in the Bakken depends on the analysis of minimum miscibility pressure (MMP) experiments. The Rising Bubble Apparatus (RBA) has been chosen for the purpose of these experiments. The RBA provides results in a short amount of time using small amounts of fluid samples. The RBA consists of a cell gage containing a flat glass tube where oil samples are placed and an injection needle where gas is injected into the flat glass tube. To simulate reservoir conditions, the glass tube is pressurized using de-ionized water and heating plates surrounding the cell are used to regulate temperature. Visual observation of the injected gas bubble behavior is captured by a camera as it rises and moves upward along the oil column. The MMP occurs when the gas bubble dissolves into the oil before reaching the top of the oil column. MMP results from a Bakken crude sample show a range from 2340 to 3000 psia at a temperature of 215 °F using CO2 as the injection fluid. Other injection fluids such as nitrogen and hydrocarbon gases have been tested and provided MMP values from 3500 to over 5000 psia depending on the gas. MMP results from Bakken crude oil samples were compared to existing correlations and more correlations were found to produce unreliable MMP results. Further comparison using an equation of state phase-behavior program has shown similar results with the RBA MMP results. The impact of different injection fluids, inclusive of CO2 and enriched hydrocarbon gases is the subject of this study. MMP results are influenced by the choice of injection fluids, providing valuable information for economic production and increased recovery in the Bakken formation. The results from this study provide MMP data for a range of injection fluids that can be used in planning pilot tests for miscible gas injection in the Bakken.

The rising energy demand is causing the petroleum industry to develop unconventional oil resen'oirs; however, the primary recovery factor is low in these types of reservoirs. Alternative methods to increase recovery need to be studied. This paper analyzes the impact of CO2 flooding a sector of the Elm Coulee field using reservoir modeling. The sector is two miles by two miles and consists of six original single-lateral horizontal wells. Two different reservoir models are built for the sector: a primary recovery black oii model and a CO2 flood solvent 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 the 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 and producers aiong 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 recoveiy factor over 15% after eighteen years of injection.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper presents an innovative methodology to integrate prior geologic information, well log data, seismic data and production data into a consistent 3D reservoir model. Furthermore, the method is applied to a real channel reservoir from the African coast. The methodology relies on the probability perturbation method. Perturbing probabilities rather than actual petrophysical properties guarantees that the conceptual geologic model is maintained and that any history matching related artifacts are avoided. Creating reservoir models that match all types of data are likely to have more prediction power than methods where some data are not honored. The first part of the paper reviews the details of the probability perturbation method (PPM), and the next part of this paper describes the additional work that is required to history match real reservoirs using this method. Then, a geological description of the reservoir case study is provided, and the procedure to build 3D reservoir models that are only conditioned to the static data is covered. Due to the character of the field, the channels are modeled with a multiple-point geostatistical method. The channel locations are perturbed in a manner such that the oil, water, and gas rates from the reservoir more accurately match the rates observed in the field. Two different geologic scenarios are used, and multiple history matched models are generated for each scenario. The reservoir has been producing for about five years, but the models are matched only to first three years of production. Afterwards, to check predictive power, the matched models are run for the last one and a half years, and the results compare favorably with the field data.

No abstract