We present the first comprehensive experimental evaluation of CO2 EOR in organic rich shale. Experiments in preserved core demonstrated the potential of CO2 to extract the naturally occurring oil in organic rich shale reservoirs, whereas tests in re-saturated core plugs were used to compute accurate recovery factors, and evaluate the effect of soak time, operating pressure, and the relevance of slim-tube MMP on recovery. 18 core-flooding experiments were conducted in sidewall cores from different shale plays.
The cores re-saturated with crude oil, were first cleaned by Dean-Stark extraction, and submitted to porosity and compressibility determination. The re-saturation, confirmed by CT-scanning, was attained by aging the core plugs at high pressure for two to four months. In all experiments, glass beads surrounding core samples were used to simulate the proppant and physically recreate in the laboratory a hydraulic fracture connected to the shale matrix. The slim-tube MMP was measured with CO2, and core-flooding experiments were performed below, close to, and above the MMP. The displacement equipment was coupled to a medical CT-scanner that enabled us to track the changes in composition and saturation taking place within the shale cores during the experiments. Continuous CO2 injection and huff-and-puff were evaluated using soak time from zero to 22 hours. Fixed reservoir temperature was used in all the experiments.
Recovery factors ranged from 1.7 to 40%. The wide variation was the result of different experimental conditions for pressure and soak time. Both operational parameters were found to significantly affect the recovery. Increasing soak time at constant pressure consistently resulted in significant increase in recovery. The increase varied from 78 to 464% for different pressures and oil composition. Similarly, increasing operating pressure at constant soak time resulted in significant increase in recovery factor from 44 to 338% depending on soak time and oil composition. Unlike the typical response during CO2 EOR in conventional rocks, in organic rich shale, further pressure increases beyond the slim-tube MMP continued to increase the recovery factor significantly. In all runs, almost all oil recovery occurred within three days from the start of the experiment, and in all huff-and-puff tests the highest rate of recovery was observed in the first cycle, implying oil recovery with CO2 is a fast process, in comparison to oil re-saturation of the samples which occurs at a significantly slower rate.
This investigation demonstrates CO2 EOR is a technically feasible method to extract significant amounts of crude oil from organic rich shale reservoirs and it provides operational understanding of how to manage pressure and soak time to maximize recovery. The recovery factors obtained in this investigation, in the context of the vast reserves of crude oil contained in organic rich shale, can sustain a second shale revolution and further capitalize oilfield infrastructure.
The improved oil recovery of unconventional shale reservoirs has attracted much interest in recent years. Gas injection, such as CO2 and natural gas, is one of the most considered techniques for its sweep efficiency and effectiveness in low permeability reservoirs. However, the uncertainties of fluid phase behavior in shale reservoirs pose a great challenge in evaluating the performance of gas injection operation. Shale reservoirs are featured with macro-scale to nano-scale pore size distribution in the porous space. In fractures and macropores, the fluid shows bulk behavior, but in nanopores the phase behavior is significantly altered by the confinement effect. The integrated behavior of reservoir fluids in this complex environment remains uncertain.
In this study, we investigate the nano-scale pore size distribution effect on the phase behavior of reservoir fluids in gas injection for shale reservoirs using a multi-scale equation of state modeling. A case of Anadarko Basin shale oil is used. The pore size distribution is discretized as a multi-scale system with pores of specific diameters. The phase equilibria of methane injection into the multi-scale system are calculated. The constant composition expansions are simulated for oil mixed with various fractions of injected gas. Bubble point, swelling factor, criticality and fluid volumetrics are studied in comparison to the behavior of the bulk fluid. It is found that fluid in nanopores becomes supercritical with injected gas, but lowering the pressure below bubble point will turn it into the subcritical state. The swelling factor is slightly higher with nanopores, and bubble point is lower than the bulk. The degree of deviation depends on the amount of injected gas.
O'Brien, W. J. (Nitec LLC) | Moore, R. G. (Schulich School of Engineering, University of Calgary) | Mehta, S. A. (Schulich School of Engineering, University of Calgary) | Ursenbach, M. G. (Schulich School of Engineering, University of Calgary) | Kuhlman, M. I. (MK Tech Solutions)
This paper outlines the results of a comparative study of air- and immiscible CO2 - Water injection based Enhanced Oil Recovery (EOR) processes for a 30+ °API tight, light oil reservoir. This was accomplished by embedding multiple low- permeability core plugs in crushed reservoir core material to create a composite core that was contained in a 1.84 m long core holder. The objectives of this unscaled experimental work were: 1) to understand the suitability of each EOR process for a low permeability reservoir, 2) to define process parameters prior to a potential field pilot, and 3) to understand the relative merits of each EOR process to mobilize light oil from a tight matrix to a fracture network.
A detailed experimental investigation was conducted at realistic reservoir conditions to evaluate the feasibility of an air injection-based EOR process. The air injection results were compared with those from an immiscible CO2-Water injection EOR experiment using the same experimental setup and reservoir conditions. Both the air- and CO2 - Water coreflood tests were performed at 10.3 MPa (1500 psig) and 99 °C in a 100 mm diameter, 1.84 m long composite core-holder using 38 mm diameter reservoir core plugs (that represented the matrix) and mounted within the crushed reservoir core material (that represented the fracture); inert helium gas was used to pressure up the core-holder to reservoir pressure. Permeability of the core plugs was from 0.3 to 3 millidarcies, while the permeability of the crushed core material was 1 to 3 Darcies.
Air injection was performed as a standard combustion tube test with injection of 2.3 pore volumes (PV) of air to burn 71% of the packed core length (including helium, a total of 4.3 PV of gas injected). The CO2-Water coreflood was performed with the injection of 2.86 PV of CO2 followed by an extended soak period, then a second injection of an additional 2.86 PV of CO2, followed by the injection of 2.6 PV of water.
The pre- and post-test core plug measurements of oil saturation show that the air injection process removed significantly larger quantities of hydrocarbons than the immiscible CO2-Water injection process. Relative to the initial conditions of the core plugs for the Air-Injection experiment, 95+ percent of the hydrocarbons were removed; noting that some fraction of original oil was consumed as fuel. In the post-test CO2-Water injection core plugs, oil recovery was in the range of 30 to 55 percent of OOIP. These findings suggest, under an appropriate field design, that both processes have the potential to recover incremental oil from tight reservoirs. However, the air-injection may be better suited to mobilize oil, due to thermal expansion, rather than the CO2 - Waterflood process.
Cronin, M. (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University, University Park) | Emami-Meybodi, H. (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University, University Park) | Johns, R. T. (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University, University Park)
Enhanced oil recovery (EOR) by solvent injection offers significant potential to increase recovery from shale oil reservoirs, which are typically between 3 and 7% OOIP. The rather sparse literature on this topic typically models these tight reservoirs based on conventional reservoir processes and mechanisms, such as by convective transport using Darcy's law, even though there is little physical justification for this treatment. The literature also downplays the importance of the soaking period in huff'n'puff.
In this paper we propose for the first time a more physically-realistic recovery mechanism based solely on diffusion-dominated transport. We develop a diffusion-dominated proxy model assuming first-contact miscibility (FCM) to provide rapid estimates of oil recovery for both primary production and the solvent huff'n'soak'n'puff (HSP) process in ultra-tight oil reservoirs. Simplified proxy models are developed to represent the major features of the fracture network.
The key results show that diffusion-transport only can reproduce the primary production period within the Eagle Ford shale and model the HSP process well, without the need to use Darcy's law. The mechanism for recovery is based solely on density and concentration gradients. Primary production is a self-diffusion process, while the HSP process is based on counter-diffusion. Incremental recoveries by HSP are several times greater than primary production recoveries, showing significant promise in increasing oil recoveries. We calculate ultimate recoveries for both primary production and for the HSP process, and show that methane injection is preferred over carbon dioxide injection. We also show that the proxy model, to be accurate, must match the total matrix contact area and the ratio of effective to total contact area with time. These two parameters should be maximized for best recovery.
With the synergy of horizontal drilling and hydraulic fracturing techniques, commercial production of Unconventional Liquid Reservoirs (ULR) has been successfully demonstrated. Due to the low recovery factor of these reservoirs, it is inevitable that Enhanced Oil Recovery (EOR) will ensue. Experimental results have shown promising oil recovery potential using CO2. This study investigates oil production mechanisms from the matrix into the fracture by simulating two laboratory experiments as well as several field-scale studies, and evaluates the potential of using CO2 huff-n-puff process to enhance the oil recovery in ULR with nano-Darcy range matrix permeability in complex natural fracture networks.
This study fully explores mechanisms contributing to the oil recovery with numerical modeling of experimental work, and provides a systematic investigation of the effects of various parameters on oil recovery. The core scale modeling utilizes two methods of determining properties that are used to construct 3D heterogeneous models. The findings are then upscaled to the field scale where both simple and complex fractures in a single stage are modeled. The effects of reservoir properties and operational parameters on oil recovery are then investigated. In addition, this study is the first to present simulation results of CO2 huff-n-puff using complex fracture networks which are generated from microseismic-constraint stochastic models.
Diffusion is proven to be the dominant oil recovery mechanism at the laboratory scale. However, the field-scale reservoir simulation indicates diffusion is negligible compared to the well-known mechanisms accompanying multi-contact miscibility. This includes swelling, viscosity reduction, and gas expansion in the matrix. Overall, the CO2 huff-n-puff process was found to be beneficial in both models in terms of enhancing the ultimate oil recovery in ULR.
Ampomah, W. (Petroleum Recovery Research Center) | Balch, R. S. (Petroleum Recovery Research Center) | Grigg, R. B. (Petroleum Recovery Research Center) | Will, R. (Schlumberger Carbon Services) | Dai, Z. (Los Alamos National Laboratory) | White, M. D. (Pacific Northwest National Laboratory)
The Pennsylvanian–age Morrow sandstone within the Farnsworth field unit of the Anadarko basin presents an opportunity for CO2 enhanced oil recovery (EOR) and sequestration (CCUS). At Farnsworth, Chaparral Energy's EOR project injects anthropogenic CO2 from nearby fertilizer and ethanol plants into the Morrow Formation. Field development initiated in 1955 and CO 2injection started December 2010. The Southwest Regional Partnership on Carbon Sequestration (SWP) is using this project to monitor CO2 injection and movement in the field to determine CO2 storage potential in CO2-EOR projects.
This paper presents a field scale compositional reservoir flow modeling study in the Farnsworth Unit. The performance history of the CO2 flood and production strategies have been investigated for optimizing oil and CO2 storage. A high resolution geocellular model constructed based on the field geophysical, geological and engineering data acquired from the unit. An initial history match of primary and secondary recovery was conducted to set a basis for CO2 flood study. The performance of the current CO 2miscible flood patterns were subsequently calibrated to the history data. Several prediction models were constructed including water alternating gas (WAG), and infill drilling using the current active and newly proposed flood patterns.
A consistent WAG showed a highly probable way of ensuring maximum oil production and storage of CO2 within the Morrow formation.
The production response to the CO2 flooding is very impressive with a high percentage of oil production attributed to CO2 injection. Oil production increasingly exceeded the original project performance anticipated. More importantly, a large volume of injected CO2 has been sequestered within the Morrow Formation.
The reservoir modeling study provides valuable insights for optimizing oil production and CO2 storage within the Farnsworth Unit. The results will serve as a benchmark for future CO2–EOR or CCUS projects in the Anadarko basin or geologically similar basins throughout the world.
Given limited CO2 supply, operational constraints, and pattern specific reservoir performance, WAG schedule can be customized such that NPV or other metrics are optimized. Depending on the WAG schedule, recovery can fluctuate between 5–15% at the pattern scale due to reservoir heterogeneity causing variations in sweep efficiency. An analytical method was developed to optimize WAG schedules that couples traditional reservoir modeling and simulation with machine learning, enabling the discovery of optimal WAG schedules that increase recovery at the pattern level. A history-matched reservoir model of Chaparral Energy's Farnsworth Field, Ochiltree County, TX was sampled intelligently to perform predictive reservoir flow simulations and artificially build an intelligent reservoir model that samples a broad range of possible WAG scenarios for optimization. The intelligent model generates the next "best" sample to investigate in the numerical simulator and converges on the optima, quickly reducing the number of runs investigated. Results in this paper demonstrate that there can be significant improvements in net present value as well as net utilization rates of CO2 using this analytical technique. The WAG design generated by the intelligent reservoir model should be deployed in the field in early 2016 for validation. It is intended that the intelligent reservoir model will be updated on a regular basis as injection and production data is obtained. This effort represents the beginning of a paradigm shift in the application of modeling and simulation tools for significant improvements in field production operations.
Production from liquid-rich shale has become an important contributor to domestic production in the United States, but recovery factors are low. Enhanced Oil Recovery (EOR) methods require injectivity and interwell communication on reasonable time scales. We conduct a feasibility study for the application of recycled lean gas injection to displace reservoir fluids between zipper fracs in liquid-rich shales.
Using new analytical solutions to the Diffusivity equation for arbitrarily-oriented line sources/sinks plus superposition, we analyze the time for inter-fracture communication development, i.e. interference, and productivity index for both classical bi-wing fractures in a zipper configuration and complex fracture networks. We are able to map both pressure and pressure temporal derivative as a function of time and space for production and/or injection from parallel motherbores under the infinite conductivity wellbore and fracture assumption. The infinite conductivity assumption could be later relaxed for more general cases.
We couch the results in terms of geometrical spacing requirement for both horizontal wells and stimulation treatments to achieve reasonable time frames for inter-fracture communication and sweep for parameters typical of various shale plays. We further analyze whether spacing currently considered for primary production is sufficient for direct implementation of EOR or if current practice should be modified with EOR in the field development plan.
The Green River, Utah holds the world's greatest oil shale resources. However, the hydrocarbon, which is namely kerogen, extraction from shales is limited due to environmental and technical challenges. In this study, we investigated the effectiveness of the combustion process for shale oil extraction. Samples collected from the Green River formation were first characterized by X-ray Diffraction (XRD) and Scanning Electron Microscopy (SEM). Then, series of dry combustion tests were conducted at different heating rates and wet combustion tests by water addition. The combustion efficiency was enhanced by mixing oil shale samples with an iron based catalyst. The effectiveness of dry, wet, and catalyst added combustion processes was examined by the thermal decomposition temperature of kerogen. Because the conventional oil shale extraction methods are pyrolysis (retorting) and steaming, the same experiments were conducted also under nitrogen injection to mimic retorting. It has been observed that the combustion process is a more efficient method for the extraction of kerogen from oil shale than the conventional techniques. The addition of water and catalyst to combustion has been found to lower the required temperature for kerogen decomposition for lower heating rate. This study provides insight for the optimization of the thermal methods for the kerogen extraction.
There is considerable and timely interest in oil and condensate production from liquid-rich regions, placing emphasis on the ability to predict the behavior of gas condensate bank developments and saturation dynamics in shale gas reservoirs. As the pressure in the near-wellbore region drops below the dew-point, liquid droplets are formed and tend to be trapped in small pores. It has been suggested that the injection of CO2 into shale gas reservoirs can be a feasible option to enhance recovery of natural gas and valuable condensate oil, while at the same time sequestering CO2 underground. This work develops simulation capabilities to understand and predict complex transport processes and phase behavior in these reservoirs for efficient and environmentally friendly production management.
Although liquid-rich shale plays are economically producible, existing simulation techniques fail to include many of the production phenomena associated with the fluid system that consists of multiple gas species or phases. In this work, we develop a multicomponent compositional simulator for the modeling of gas-condensate shale reservoirs with complex fracture systems. Related storage and transport mechanisms such as multicomponent apparent permeability (MAP), sorption and molecular diffusion are considered. In order to accurately capture the complicated phase behavior of the multiphase fluids, an equation of State (EOS) based phase package is incorporated into the simulator. Due to the large capillary pressure that exists in the nanopores of ultra-tight shale matrix, the phase package considers the effect of capillary pressure on phase equilibrium calculations. A modified negative-flash algorithm that combines Newton's method and successive substitution iteration (SSI) is used for phase stability analysis under the effect of capillary pressure between oil and gas phases.
In addition, a lower-dimensional discrete fracture and matrix (DFM) model is implemented. The DFM model is based on unstructured gridding, and can accurately and efficiently handle the non-ideal geometries of hydraulic fracture in stimulated unconventional formation. Optimized local grid refinement (LGR) is employed to capture the extremely sharp potential gradient and saturation dynamics in the ultra-tight matrix around fracture.
We apply the developed simulator to study the combined effects of capillary pressure and multicomponent storage and transport mechanisms that are closely associated with the phase behavior and hydrocarbon recovery in gas-condensate shale reservoirs. We present preliminary simulation studies to show the applicability of CO2 huff-n-puff for the purpose of enhanced hydrocarbons recovery. Several design components such as the number of cycles and the length of injection period in the huff-n-puff process are also briefly investigated.