This research assesses the potential for Enhanced Oil Recovery (EOR) techniques to boost oil production in Montana. Eight major oil basins in Montana, comprising over 350 oil fields, were analyzed. Using a volumetric analytical method, the original oil in place (OOIP) was estimated for 42 fields where sufficient data were available for the calculation. By comparing the cumulative oil production with the OOIP, fields with significant remaining reserves were identified. Data for this project was obtained from the Montana Geological Society (MGS) and the Montana Board of Oil and Gas (MBOG), which provided comprehensive information on reservoir properties, fluid characteristics, and production histories. The analysis identified that approximately 3.51 billion stock tank barrels (STB) of oil remain within the 42 reservoirs suggesting considerable untapped potential. The study utilized a screening criterion based on reservoir rock properties and fluid characteristics to select appropriate EOR methods for the 42 fields. Carbon dioxide (CO2) injection, hydrocarbon injection and polymer flooding were identified as the most viable techniques. In general, fields at depths greater than 4,000 feet were recommended for CO2 injection, while fields at shallower depths were more suited to polymer flooding. The Breed Creek oil field was selected for detailed modeling and simulation due to its available reservoir data. Preliminary simulations indicated that CO2 injection could increase recovery by approximately 10%, potentially extracting an additional 880,000 STB of oil from this field. Applying the results from this field to other fields in Montana could result in hundreds of millions of additional barrels of oil production, unlocking significant potential across the region. This study validates that EOR techniques could significantly enhance oil production in Montana, and further simulations and economic analyses will guide the feasibility and implementation of these methods in the field. This research not only provides valuable insights for the revitalization of Montana’s oil industry but also offers a scalable pathway for improving oil recovery in other states facing similar challenges. The methodologies and EOR techniques explored in this study can be adapted to diverse geological settings across the U.S., offering a broader impact on oil production. By tailoring these approaches to the specific reservoir characteristics of various oil fields nationwide, states with declining oil output can benefit from increased hydrocarbon recovery, contributing to both regional and national energy sustainability.

Summary Unconventional reservoirs have had tremendous success over the last decade due to technical advances including long horizontal wells and multi-stage hydraulic fracturing; however, their potential may be even higher. There are trillions of barrels of oil in these resources, and while wells start out at high rates, they decline quickly and primary recovery factors are low, often in the single digits. This clearly indicates a need for some form of enhanced oil recovery (EOR) for these types of reservoirs. Efforts to implement EOR in unconventional reservoirs has occurred, and those efforts are examined in detail in this paper. Multiple field trials have occurred in the Eagle Ford and Bakken reservoirs, and we use modelling and decline curve analysis to evaluate the potential success of the pilot projects. The Eagle Ford projects that use huff-n-puff gas injection appear to be technically and economically successful. The Bakken is more uncertain; the field trials there were not successful, but flow modelling shows potential if a better injection strategy is used. While much has been achieved over the last decade in unconventional reservoirs, implementing EOR in these types of reservoirs may bring about even greater success.

Pore-scale dependent phase behavior describes a decrease in the hydrocarbon phase envelope as pore throat size decreases. This phenomenon is well documented in terms of confining effects on phase behavior with several analytical fluid models proposed that account for these effects. Results from a limited number of numerical reservoir models show the effects pore-scale phase behavior has on total production. However, fewer studies consider fluid transfer between different scale pore networks as a function of scale-dependent phase behavior. This work investigates fluid transfer between different scale pore networks related to scale-dependent phase behavior and the affects it has on production and fluid composition in the pore networks. A commercially available reservoir simulator is used with a dual porosity/permeability grid and scale-dependent fluid models to study the fluid transfer between pore networks. Fluid tracking is used to trace fluid phases and components that originate in both the nanoscale and macroscale pore networks. Fluid transfer between pore networks is considered at both the pore network scale and at the well stream scale by tracking the fluid components from nano-scale pores into macro-scale pores and ultimately to the well bore. The results from the model are used to quantify fluid transfer between pore networks. The results of the study show how the confining effects on fluid phase behavior affect fluid production rates and gas-oil ratios by linking the pore scale processes to the well stream scale production. For example, as fluid moves from the nanoscale pores, where the bubble point is suppressed and the fluid retains the initial solution gas-oil ratio (Rs), into the macro scale pores, the fluid in the macroscale pores is enriched by the nanoscale pore fluid. This work provides three main contributions to an improved understanding and characterization of unconventional plays. The first is demonstrating the ability to simulate the confining effects on fluid phase behavior using commercially available reservoir simulators. Second is the ability to capture some of the unique production trends observed for tight oil reservoirs, e.g., extended periods of stable GOR, when modeling these reservoirs. The third contribution is in tight oil EOR, providing insight into the composition of the fluid that remains in the pore networks following primary depletion or at the onset of an EOR process.

Forecasting production from unconventional reservoirs is challenging because of the uncertainty that arises from intricate fracture networks, complex transport mechanisms, and convoluted flow configurations. The accuracy of decline curve analysis for such reservoirs has been questioned due to the limited amount of long-term production data available. That being so, some unconventional reservoirs, such as the Bakken and the Barnett, have produced for 15-20 years, providing an adequate amount of data to validate the accuracy of the hyperbolic decline curve method, shed light on proper parameters – b and Di, and determine the amount of production history necessary to trust regression techniques. To test this, an extensive and versatile regression analysis model was built in Python using least squares optimization to match specific durations of production data – first 6 months, first year, first two years, etc. The model outputs the optimal parameters – b and Di –to match the specific duration. Additionally, fixed b values from 0.5 to 1.5 are tested where only Di is optimized through the model. To understand how accurately the models predict production, they are validated against the most recent 5 years of data, which was not included in the matching period. For a statistically significant sample size, around 700 wells in the Bakken and 1800 wells in the Barnett with start dates between 2005 and 2010 were used. The results show that in order to have confidence in the model's ability to predict production, more than 3 years of production data must be available. If 3 years of data is not available, the hyperbolic exponent, b, should be set close to 1.0 for Bakken wells (and likely other unconventional liquid rich wells) and between 1.0 and 1.2 for Barnett wells (and likely other unconventional gas wells). Additionally, the initial nominal decline rate, Di, should be chosen in accordance with the hyperbolic exponent. Not only do these guidelines result in satisfactory, long-term predictions, but they mitigate any significant error influenced by the underlying relationships between b and Di. These curve-altering relationships induce both positive and negative impacts on the predictions. If b is improperly chosen, overestimation in late-life production profiles may ensue. Alternatively, if Di is improperly chosen, early-life production may be too high. Since production forecasting is a necessity for a company to determine its present value, this paper provides knowledge and guidance regarding forecasting procedures and parameter settings for North American unconventional operators. Using decline curve analysis to accurately predict oil and gas rates is pertinent to the longevity of these unconventional reservoirs.

Unconventional reservoirs hold vast amounts of untapped hydrocarbon resources; however, given current production capabilities and our understanding of unconventional reservoir production mechanisms only 5% to 10% of these hydrocarbons are typically recovered. The ability to recover additional hydrocarbons from unconventional reservoirs is dependent on an improved understanding of the production mechanisms which are a function of the complex lithology and reservoir fluid systems, and the interactions between these systems. The lithology and fluid systems present in most unconventional reservoirs result in production from several scale-dependent fluid flow and storage systems, or depletion systems, that combine to contribute to the total production. These depletion systems can include matrix level features defined by pore size, natural fracture systems within the matrix, and hydraulic fractures in addition to the traditional depletion systems defined by stacked pay. The fluid phase behavior within these systems also has a scale dependence that must be taken into consideration. As a result, the individual systems tend to deplete at different rates. The purpose of this work is to describe the production mechanisms in terms of the lithology and reservoir fluid interactions. By using numerical simulation to systematically isolate production from individual depletion systems, the role and significance of each system is quantified. A numerical model was developed to simulate the contributions to total hydrocarbon production from multiple depletion systems. Fluid tracers were placed within each depletion system to isolate the individual system production. The results show the stage of production when each depletion system is active and the associated hydrocarbon volumes. For example, the hydraulic fracture system provides most of the initial production, but contribution from the matrix and natural fractures quickly overtakes it. Composite production curves were developed by combining the simulated production contributions from each depletion system, highlighting the influence the different systems have on the total production. This paper provides insights into the production contributions from multiple depletion systems found in many unconventional reservoirs. Understanding the roles that the different depletion systems play on production will lead to better well spacing, reserve estimates, and improved reservoir production practices including enhanced oil recovery methods that may be optimized to target the most promising aspects of the reservoir.

Production wells within the northeast (NE) Elm Coulee experience significantly higher water cuts than wells within Elm Coulee Proper. The increased water production has a negative economic impact on Bakken operators seeking to maximize profitability within the area. A reservoir engineering-based research project has been conducted to determine the source of the increased water production within the NE Elm Coulee, and to identify recommendations for operators to mitigate the water production related expenses in the area. One option for the increased water production is from the water saturation within the matrix of the Middle Bakken Shale, and another possibility is from the Three Forks formation by vertical migration through natural fracture networks. Previous work has identified the presence of natural fracture systems within the Bakken that may be creating flow networks between stratigraphic layers. Numerous flow simulation models of the NE Elm Coulee were constructed to determine the source of the produced water. The reservoir models consist of three hydraulically fractured horizontal wells within the Middle Bakken Shale, and it incorporates the naturally fractured state of the Bakken through a discrete fracture network (DFN). Various reservoir parameters were altered within the envelope of uncertainty to obtain a history match for the reservoir model to both scenarios, and the resulting parameters from the Middle Bakken saturation case are more realistic and produce better history matching results than the Three Forks water migration case. The Three Forks fracture model produces an unrealistically high volume of water, and the breakthrough pattern is not consistent with field measurements. Thus, the source of the increased water production appears to come from matrix water saturation within the Middle Bakken Shale. Many relevant aspects of unconventional reservoir simulation are incorporated into the project; therefore, the methodology used in the research can help assist reservoir engineers that are modeling unconventional petroleum reservoir with stacked stratigraphic intervals. Modeling natural fractures and complex completion fracture networks using a DFN, pressure dependent permeability, and history matching in unconventional reservoirs are important topics that are discussed in the paper. Operators within the Bakken can use this information to better understand the geologic implications of producing in the area.

Inter-well heterogeneities influencing fluid migration in deltaic reservoirs are controlled by lateral lithofacies changes and vertical complexities such as low permeability thin-beds (i.e. mudstones). Subsurface tools cannot adequately predict the spatial and stratigraphic organization of these architectural elements, nor their influence on effective reservoir properties and connectivity. Our outcrop-based geomodeling study of the Turonian Wall Creek Member of the Frontier Formation in the Powder River Basin, Wyoming, USA, integrates subsurface production and flow simulation data to quantify the impact of multi-scale stratigraphic heterogeneity on analogous reservoir behavior and horizontal well design. The upscaled representation of thin-bed complexity in our 500 m × 715 m x 15 m geomodel is derived through flow simulation of internally nested, facies specific, centimeter-scale models (basic depositional element models or BDEMs). These BDEMs are populated with quantitative data of mudstone thin-bed geometries directly derived from digital outcrop measurements and measurements in the field, and aided by subsurface (core) petrophysical properties. Reservoir simulations are performed using various landing zone and completion configurations, and under both single-phase and multi-phase flow conditions history matched to subsurface production data.

Unconventional reservoirs produce large volumes of oil; however, recovery factors are low. While enhanced oil recovery (EOR) with cyclic gas injection can increase recovery factors in unconventional reservoirs, the mechanisms responsible for additional recovery are not well understood. We examined cyclic gas injection recovery mechanisms in unconventional reservoirs including oil swelling, viscosity reduction, vaporization, and pressure support using a numerical flow model as functions of reservoir fluid gas–oil ratio (GOR), and we conducted a sensitivity analysis of the mechanisms to reservoir properties and injection conditions. All mechanisms studied contributed to the additional recovery, but their significance varied with GOR. Pressure support provides a small response for all fluid types. Vaporization plays a role for all fluids but is most important for gas condensate reservoirs. Oil swelling impacts low-GOR oils but diminishes for higher-GOR oil. Viscosity reduction plays a minor role for low-GOR cases. As matrix permeability and fracture surface area increase, the importance of gas injection decreases because of the increased primary oil production. Changes to gas injection conditions that increase injection maturity (longer injection times, higher injection rates, and smaller fracture areas) result in more free gas and, for these cases, vaporization becomes important. Recovery mechanisms for cyclic gas injection are now better understood and can be adapted to varying conditions within unconventional plays, resulting in better EOR designs and improved recovery.

Abstract Unconventional oil reservoirs such as the Eagle Ford have had tremendous success over the last decade, but challenges remain as flow rates drop quickly and recovery factors are low; thus, enhanced oil recovery methods are needed to increase recovery. Interest in cyclic gas injection has risen as a number of successful pilots have been reported; however, little information is available on recovery mechanisms for the process. This paper evaluates oil swelling caused by diffusion and advection processes for gas injection in unconventional reservoirs. To accurately evaluate gas penetration into the matrix, the surface area of the hydraulic fractures needs to be known, and in this work, three different methods are used to estimate the area: volumetrics, well flow rates and linear fluid flow equations. Fick's law is used to determine the gas penetration depth caused by diffusion, and the linear form of Darcy's law is used to find the amount from advection. Then, with the use of swelling test information from lab tests, we are able to approximate the amount of oil recovery expected from cyclic gas injection operations. During the gas injection phase, gas from the fractures can enter the matrix by both advection (Darcy driven flow) and diffusion. We estimate that over 200 million scf of gas can enter the matrix during a 100 day injection/soak period. Using typical reservoir and fluid parameters, it appears that 40% is due to diffusion and 60% is due to advection. Sensitivity analysis shows that these numbers vary considerable based on the parameters used. Analytical models also show that during a 100 day production timeframe, over 14,000 stock tank barrels (STB) of oil can be produced due to huff-n-puff gas injection. Both gas injection and oil recovery amounts are compared to recent Eagle Ford gas injection pilot data, and the model results are consistent with the field pilot data. By determining the relative importance of the different recovery mechanisms, this paper provides a better understanding of what is happening in unconventional reservoirs during cyclic gas injection. This will allow more efficient injection schemes to be designed in the future.

Abstract Over the last decade, unconventional resources like the Bakken formation have revolutionized the petroleum industry, but they have only produced by primary mechanisms, and recovery factors have remained low. The need for IOR processes is clear, but there has only been minor work in this area and no commercial field applications. Flow simulation models can be used to test different methods without interrupting field operations, but models have had a poor track record for unconventional IOR, partly because there is little field injection information to validate the models. In this work, we history matched the model to an IOR injection pilot location in Mountrail County, North Dakota that included both water and gas injection tests. A county sized geologic model was previously constructed based upon available core, log and geologic information. The model allows for easy extraction of smaller segments for flow simulation. For the current study, a segment around the pilot injection area was isolated. The injection well and two offset producing wells were included in the model. Fluids were added into the model based on a nearby PVT report, and the hydraulic fracturing was captured with a dual permeability grid. The model was matched to the historical production and injection data. At the offset wells, breakthrough times, water cuts and gas oil ratios were also reproduced by changing the fracture and matrix properties. By matching the injection data, the interwell connectivity is reproduced, which should improve predictions from the model. Various situations were then tested with the model including both gas and water injection scenarios. In the actual field pilot, gas was only injected for two months in the injection well, and there was only a minor response. In one scenario, therefore, we injected into all three wells in a huff-n-puff manner for ten years, and the results showed significant additional oil recovered – 30% more than the primary recovery. In other scenarios, water was injected in both a continuous and huff-n-puff manner. The continuous case had early breakthrough and poor sweep, but the huff-n-puff injection case indicated that oil rates would increase almost as much as the best gas injection cases. This work shows that by reproducing the field injection data in unconventional reservoirs, more realistic models are created. We evaluated a large number of scenarios, and some of them did not show any increase in oil production, but the models that did show an increase helped us identify IOR techniques that have a better chance of success in the Bakken, which will improve designing the much needed next generation of field pilot tests.

Abstract The Frontier Formation in the Powder River Basin has been re-discovered for oil and gas potential with the development of long horizontal wells and multi-stage hydraulic fracturing. Over the last decade, the Wall Creek member (WCM) of the Frontier formation has proven to be a successful hydrocarbon-producing target, yet a full understanding of the flow behavior of this complex stratigraphic unit has not been fully achieved. The fluid and rock properties have uncertainty and are not well defined due to the low permeability rocks. This study aims to describe the fluid flow behaviors of these features and create an outcrop model that includes all the reservoir properties and geologic features to better understand hydrocarbon recovery. This project consists of two distinct aspects: (1) defining the reservoir properties through a well flow model and (2) upscaling the permeability of the reservoir models with different geologic features into an outcrop model for the WCM. A single horizontal well flow simulation model was created to estimate the reservoir properties. Using three offset well logs, a 32 feet interval was selected to represent the net pay zone of the Wall Creek. The porosity was estimated using well logs, and permeability was established by applying a correlation of porosity and permeability found from core data. The historical production data was matched by modifying the initial fluid saturations and the rock physics parameters such as relative permeability and capillary pressure. As a result, representative fluid and rock physics models were obtained for the outcrop model. From the outcrop study, defined geologic models with different facies of Wall Creek member were created to include abundances and orientations of mud drapes as the most impacted features that may affect the the fluid flow ability. An outcrop model captures fine heterogeneities of all the facies using flow-based upscaling of the geologic models. The effective directional permeabilities of each facies were obtained to integrate into an outcrop model to capture the geologic features that may have a large impact on the hydrocarbon recovery. In this work, we developed methods to incorporate fine-scale (cm) geologic observations from the outcrop with well scale properties from the field in an integrated study that was ultimately used to help determine field level decisions such as well spacing and fracture spacing.

The Frontier Formation in the Powder River Basin has been re-discovered for oil and gas potential with the development of long horizontal wells and multi-stage hydraulic fracturing. Over the last decade, the Wall Creek Member (WCM) of the Frontier Formation has proven to be a successful hydrocarbon-producing target, yet a full understanding of this complex stratigraphic unit has not been fully achieved. Tisdale Anticline outcrop studies conducted by University of Montana have shown that thickening upward tidal bars within WCM play an important role in hydrocarbon production. Recent studies have analyzed the geometry and extent of muddy toe-sets within tidal bars to affect fluid flow behavior. Furthermore, the fluid and rock properties have uncertainty and are not well defined due to the low permeability rocks. This study aims to describe the fluid flow behaviors of these features and create a regional outcrop model (1 km by 1 km) that includes all the reservoir properties and geologic features to better understand hydrocarbon recovery. This project consists of defining the reservoir properties and upscaling the permeability of defined geocellular models with different geologic features into the reservoir model for the WCM. A single horizontal well flow simulation model was created to estimate the reservoir properties. Using three offset well logs, a 32 feet interval was selected to represent the net pay zone of the Wall Creek. The porosity was estimated using well logs, and permeability was established by applying a correlation of porosity and permeability found from core data. The historical production was matched by modifying the initial fluid saturations and the rock physics parameters such as relative permeability and capillary pressure. As a result, representative fluid and rock physics models were obtained for regional model. From the outcrop study, the defined geologic models (25 m by 1 5m) of 2 to 3 meters thick WCM tidal bars were created to include abundances and orientations of mud drapes as the most effective features of tidal bars. A regional model captures fine heterogeneities of tidal bars using flow-based upscaling of the geologic models. The effective directional permeabilities of each geologic scenario were obtained to create the correlations between the mud drapes characteristics and effective permeability to create the regional model based on the outcrop observations. Results from the regional model are used to optimize field development.

Abstract 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.

Summary After hydraulic fracturing, only 10 to 50% of the fracturing fluids is typically recovered. This paper investigates how the remaining fracturing fluids are imbibed by shale as a function of time, and it investigates the influence of various parameters on the imbibition process that include lithology, reservoir characteristics, and fluid properties. In addition, on the basis of experimental results, a numerical model has been developed to estimate the volume and rate of spontaneous imbibition over the entire fracture face. The rock samples are from the Horn River formation onshore Canada. The fracturing fluids used in the experiments included 2% KCl, 0.07% friction reducer, and 2% KCl substitute. In the experimental control group, distilled water was used. Through spontaneous-imbibition experiments, the relationship between imbibed fluid volume and time indicated that clay content was the most important factor that affected the total imbibed amount. Shale matrix with high clay content could imbibe more fracturing fluids than its measured porous space because of the clay's strong ability to expand and hold water. According to contact-angle-test results, the strongly water-wet shale samples had a faster imbibed rate. Total organic carbon (TOC) and porosity had no influence on imbibed volume and rate. These experimental findings can contribute to an improved fracturing-fluid design for different shale-formation conditions to reduce fluid loss. The experiment showed that 2% KCl and 2% KCl substitute fracturing fluids were imbibed from 10 to 40% less than 0.07% friction reducer in the shale formation with high clay content, whereas in the shale formation with low clay content, the opposite occurred. In the low-clay-content shale, 0.07%-friction-reducer test fluid was imbibed from 10 to 30% less than 2% KCl fluid, but had an imbibed amount similar to that of 2% KCl substitute fluid. The numerical-model result was matched with the experimental result to estimate a relative permeability in the model that could represent the rock properties. This model could be used to estimate the total imbibed volume along fracture faces through spontaneous imbibition.

The Bakken is one of the shale reservoirs that has been discovered to hold a vast amount of resource and is 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 recoveries, miscible gas injection is considered for improving the recovery of oil in the Bakken formation. Feasibility of miscible gas injection in the Bakken would depend 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. By observing the shape and dissolution behavior of the bubble, the MMP can be determined.MMP results from a Bakken crude sample are shown to range from 2100 to 3500 psi at temperatures from 160 to 240 degrees F using CO2 as the injection fluid. Other injection fluids such as nitrogen and hydrocarbon gases have been tested and also provided reasonable MMP values. MMP results from Bakken crude oil samples were compared to existing correlations, and the correlations were found to produce mostly unreliable MMP results for the Bakken oils evaluated in the study. On the other hand, an equation of state phase behavior program showed similarities 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 a range of MMP data that can be used in planning pilot tests for miscible gas injection in the Bakken. (C) 2016 Elsevier B.V. All rights reserved.