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.
Ralston, Matt (EIWT, LLC) | Braile, Lawrence (Purdue University) | Helprin, Olivia (Humboldt State University) | Maguire, Henry (University of Vermont) | McCallister, Bryan (Wright State University) | Orubu, Akpofure (Montana Tech) | Rijfkogel, Luke (Fort Hays State University) | Schumann, Harrison (Southern Methodist University)
Three refraction traveltime tomography methods were applied to a 6.4 km crooked-line seismic profile acquired in the dry riverbed of the Rio de Truches, located in the Espanola Basin in northern New Mexico. The methods are based on ray-tracing, Fresnel volumes, and the adjoint-state. Each method was able to provide refraction statics for reflection processing that sufficiently accounted for changes in near-surface velocity and/or thickness. The purpose of this paper is to describe, compare, and contrast these tomographic methods and detail their application to a crooked-line survey. Velocity models and static solutions from each method are quantified by comparison of stacks, to which refraction statics have been applied, with a stack using delay-time refraction statics serving as a baseline.
Presentation Date: Wednesday, October 17, 2018
Start Time: 1:50:00 PM
Location: 204A (Anaheim Convention Center)
Presentation Type: Oral
ABSTRACT: Photogrammetric data collection and analysis techniques are increasingly being used for geotechnical characterization of rock masses, and rock slopes, in particular. There is a growing selection of software packages that can create georeferenced digital 3D models from a photoset and control points. Although each software package is able to create the desired point clouds, different techniques are used to produce them. For a geotechnical investigation, it is important to understand the accuracy of the software being used in order to have confidence in the reliability of the digital 3D models that are created.
In a study similar to one conducted in conjunction with the GoldenRocks ARMA conference in 2006 (and described in Tonon and Kottenstette, 2006), a rock outcrop was selected to be the location for a digital photogrammetry model comparison. Two sets of control points were surveyed on the rock outcrop; one set was provided for the creation of each model, and one set was used to evaluate the accuracy of the model by measuring the difference in the location of the point in the model and in the survey data. An unmanned aerial vehicle (UAV) was used to collect video footage of the site. A set of still frames were extracted from the video that contain overlapping images of the rock outcrop. The set of image files was used to create models with the following photogrammetry software packages: Bentley ContextCapture, Agisoft PhotoScan, and Pix4Dmapper. The accuracy of each of the software packages was compared by quantifying the error in the control points and check points between the model and the field survey. As this comparison is intended to provide guidance for selecting software tools to aid in rock mass characterization, other features were evaluated as well, including user-friendliness. Understanding the accuracy of digital photogrammetry software is critical for justifying the use of such models in a geotechnical investigation. The advantages of these models are numerous but of little value if the data provided by the models do not adequately represent the field conditions.
Bentley ContextCapture was found to have the least error in the control points and Pix4Dmapper was found to have the least error in the check points. The Bentley ContextCapture model also had the highest resolution, closely followed by the Pix4Dmapper model. Based on these qualities and several others including the general usability, Bentley ContextCapture creates the most effective models for potential geotechnical investigations.
Utilizing photogrammetric techniques for geotechnical investigations is becoming increasingly common because of the many benefits when compared to more traditional analytical techniques. There are many software packages available on the market that can build georeferenced digital 3D models from a photoset and control points. Each software package is capable of creating a point cloud and mesh; however, the varying techniques used by each software package introduce different sources of error and distortion. When building a point cloud for a geotechnical investigation, it is important to understand the accuracy of the software being used in order to have confidence in the reliability of the digital 3D models that are created.
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.
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.
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.
Low primary recovery percentages from unconventional reservoirs have long motivated interest in Enhanced Oil Recovery (EOR) for these reservoirs, resulting in numerous simulation studies and injection pilots. However, performance from injections pilots has typically been disappointing compared to the simulations, suggesting that reservoir permeability and heterogeneity are not adequately described in the reservoir simulation models.
In this study, a simulation and history-matching approach was used to quantify the permeability matrix over a six-section, nine-well area. Twelve years of production data were history-matched, using a combination of pressure-dependent permeability and enhanced permeability to represent natural fractures or other high-permeability features. Also, the performance of a failed injection pilot was history-matched to determine the level of reservoir heterogeneity needed to explain the pilot failure.
Based on this study, a reservoir description capable of matching twelve years of production and injection history has been developed. Formation properties in the high-permeability streaks capable of causing the disappointing injection pilot performance have been quantified. Recovery has been forecast to depletion, and EOR under hydrocarbon gas injection has been forecast for a variety of scenarios. Optimal operating strategies and recommendations for technology development to mitigate early breakthrough are made. Realistic cost estimates were made for each scenario, and economics were run for each recovery method. These results give insight into the economic potential of enhanced oil recovery in the Elm Coulee Bakken formation. Recommendations for favorable tax treatment and scheduling of expenses/investments are made.
Developing the permeability matrix using the history matching approach is a novel and versatile way of quantifying unconventional reservoir properties. However, it is important to match both injection and production data, since the permeability vector appears to have pressure-dependent effects. The effect of controlling injection thief zones by controlling local wellbore outflow is quantified, and a need for in situ permeability modification of fracture thief zones has been determined.
In this study, a glass reinforced vinyl ester (GRV) liner was systematically designed to produce a corrosion resistant, toughened, liner with superior corrosion resistance and strength characteristics. This GRV liner system was designed as an alternative to previously tested glass reinforced epoxy systems . The composite liner could theoretically be used in conjunction with standardized oil and gas production tubing to alleviate the effects of corrosion in offshore exploration applications. This particular system was designed using netting analysis for filament wound pressure vessels and tested in accordance with ASTM D2290 split-disk procedures. To ensure that the finalized design would be capable of withstanding the immense pressures and temperatures seen during use in offshore oil and gas production, the project used an API controlled steel alloy already employed by industry as a benchmark for determining the necessary yield stress and internal yield pressure required for the proposed application. To further define the physical characteristics of the proposed system, tests were conducted to verify the coefficient of thermal expansion (CTE) of the composite material. The CTE data was then used to evaluate the potential for interfacial thermal stresses induced when bonding dissimilar materials at elevated temperatures. Furthermore, the vinyl ester composite was environmentally conditioned in accordance with ASTM G202 rotating cage procedures, and evaluated to assess the proposed system's susceptibility to degradation caused by corrosive fluids. The study was conducted with the intent to utilize the design principles of filament wound pressure vessels to produce an oil and gas production liner that emulates the strength characteristics of its steel counterpart, while retaining the corrosion resistance associated with vinyl ester matrix.
Zhou, Zhou (China University of Petroleum Beijing) | Hoffman, Todd (Montana Tech) | Bearinger, Doug (Nexen Energy ULC) | Li, Xiaopeng (Colorado School of Mines) | Abass, Hazim (Colorado School of Mines)
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.
Unconventional formations such as the Eagle Ford, Niobrara and Bakken have made a significant impact on the oil industry over the last decade, but primary recovery factors are still low, typically less than 10%. The need for improved oil recovery (IOR) has been documented, but most published studies have focused on simulation models and lab tests. The next logical step includes field trials or pilot projects.
Over the last 7-8 years, there have been a number of pilot tests for both water and gas injection in the Bakken. Results from these small pilots were reported to state agencies, and the first part of this paper analyzes the available public data on these pilots. Injectivity of gas or water does not appear to be an issue in the Bakken; however, the projects, in general, show early breakthrough times and poor reservoir sweep efficiencies. Offset wells showed little to no additional oil recovery, but the pilots were limited in scope and duration. Mitigating procedures were not fully implemented to deal with the problems that occurred.
This paper also proposes methodologies for implementing second generation pilots for unconventional reservoirs. Methods are devised to improve understanding of the near well formation before injection starts, detect where fluids are entering and leaving along the lateral and correct for any associated poor sweep efficiency. We also propose long term information collecting strategies and contingency plans to deal with difficulties that may arise during the pilot.
Using EOR to increase recovery from unconventional oil fields is important for the continued success of these plays, and this paper provides a thorough analysis of implementing IOR pilots in these fields.