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.
This paper examines a priori equation to describe recovery factors of EOR processes in oil shale plays. The existing studies imply promising future for implementing gas cyclic injection through hydraulically fractured wells completed in shale plays; the EOR agent (a mixture of HC gas or CO2) is injected and after a soaking period, the well is put back on production. However, translation of lab-scale EOR results to field-scale is yet to be resolved. Dynamic penetration volume (DPV) controls the amount of contacted oil by the EOR agent (fluid-fluid interface), slowly grows with
We use a combination of modeling, theoretical, and experimental work to investigate potential recovery loss in well-scale compared to recovery measured in the lab-scale. In our formulation, the recovery in pilot-scale is defined as the product of recovery in lab-scale by field factor. Recovery in lab-scale is a function of pressure drawdown during production (choke effect). Choke-size controls how fast the mixture of gas and vaporized oil components will be produced back after soaking time.
Field factor entails two parameters that control how much of in-situ liquid hydrocarbon can potentially interact with EOR agent; basically, field factor is evaluated as a fraction of reservoir volume prescribed within inter-well spacing accessible to the EOR agent when injection process begins. Field factor is calculated as a product of fraction of stimulated reservoir volume (SRV) accessible to EOR agent (DPV/SRV) at any given time by fraction of reservoir volume stimulated during fracturing; SRV is controlled by the efficiency of fracturing treatment. The pore connectivity loss can occur because of the physical closure of flow path at the fracture-matrix interface and/or two-phase blockage. The limiting two phase phenomena that can potentially prevent the injected gas from getting into pore space because of capillary forces.
Our results suggest that recovery in the pilot-scale can be significantly reduced owing to pore connectivity loss (a factor of two). The pore connectivity is reduced as pore pressure decreases and effective stress increases. We evaluate change of fluid conductivity under stress and differentiate contribution of pore connectivity loss and pore shrinkage. Moreover, our results suggest that chokes size effect observed in the experiments can be explained by loss of pore connectivity.
For the first time, an equation is presented to upscale the EOR results obtained in lab-scale to pilot-scale. The outcome is expected to help operators with the pilot-test performance evaluations.
The recovery factor of Eagle Ford shale is estimated around six percent, which means that considerable amount of oil will be left behind after primary production. A major technique to enhance oil production in Eagle Ford could be gas injection since waterflooding is not plausible. This paper presents a novel inhouse multi-component, multi-phase, dual-porosity numerical model including molecular diffusion. This model evaluates ethane-rich gas EOR schemes to recommend on the injection mechanisms and maximize the production performance in support of field design and applications.
There is a great interest to develop an enhanced oil recovery technique for the unconventional shale reservoirs to increase its oil production beyond the primary production. The model, we present, was developed to address this issue while adhering to the thermodynamic complexities of the confined space, which includes crossing the phase boundaries during phase evolution, the wall effects in efficient and computationally robust procedures. It also determines the effect of molecular diffusion on transport mechanisms. The analysis of production data from Eagle Ford wells is used in conjunction with the simulation results to evaluate the increase in recovery after gas injection.
To model the flow for both primary and enhanced recovery, an appropriate model involving advective flow and molecular diffusion is needed since Darcy flow is by no means the dominant flow mechanism considering the average pore throat size measured in Eagle Ford formation. One major requirement for the process is providing adequate residence time to the injected gas for molecular diffusion to take place across the matrix-fracture interface. The simulation results demonstrate that the ethane-rich produced gas injection as an enhanced oil recovery mechanism will improve the production. In particular, an increase of at eleven percent in cumulative oil production is achieved. Furthermore, we present the usefulness of the formulation in analyzing pressure and rate variation with time as well as forecasting future performance of unconventional reservoirs.
In this paper, we present a new compositional diffusivity model which determines the appropriate injection mechanisms using different gas injection scenarios for the field applications in Eagle Ford. Our method provides a better understanding of the physical phenomena of fluid flow processes in unconventional reservoirs which affect the reservoir performance for both primary and enhanced recovery.
Wang, Haitao (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development) | Lun, Zengmin (Petroleum Exploration & Production Research Institute, SINOPEC) | Lv, Chengyuan (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development) | Lang, Dongjiang (Petroleum Exploration & Production Research Institute, SINOPEC) | Luo, Ming (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development) | Zhao, Qingmin (Petroleum Exploration & Production Research Institute, SINOPEC) | Zhao, Chunpeng (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development)
The reservoirs in Qian 34 10 rhythmic layer of Qianjiang Basin were shale oil with intersalt sediments. During natural depletion development process production rapidly decreased. Water injection and CO2 injection were considered as potential technology for shale oil EOR. Due to high salt content of shale rock and dissolution of salt in water, water injection damaged the reservoirs. CO2 injection didn't react with salt to damage the reservoirs. Meanwhile, CO2 could enter micro pores of reservoir rock and mobilize oil by the mechanisms of diffusion, extraction and swelling and so on. In order to verify oil mobilization in shale exposed to CO2 exposure experiments based on nuclear magnetic resonance (NMR) were conducted in this study.
NMR T2 spectrum can measure the oil signal and determine the oil content of rock with low permeability. In this study 10 fresh shale samples (from 6 depths) were measured and oil contents were determined using NMR T2 spectrum. Two shales with higher oil content were selected and performed exposure experiment. Under the temperature of 40 °C and the pressure of 17.5 MPa fresh shale was exposed to CO2 and NMR T2 spectrum was used to measure the oil content of shale continuously. Oil mobilization in shale exposed to CO2 was determined.
The results of NMR T2 spectrum showed that NMR signals of 9 fresh shale samples were good and oil contents of fresh shales were high. Recovery of S5# shale exposed to CO2 was 51.2% after 8 days. Recovery of S9# shale exposed to CO2 was 55.8% after 6.1 days. These results indicated that more than half of shale oil were mobilized with relative long exposed time during CO2 injection. The results of NMR T2 spectrum showed that oil in all pores could be mobilized as exposure time increased.
This study showed the quantitative results for CO2 injection and EOR in shale oil of Qianjiang Basin. All conclusions provided confidence to start CO2 EOR pilot project in shale oil with intersalt sediments with ultra-low permeability.
The goal of this work is to develop surfactant systems that can improve oil flow from shale wells after fracturing or re-fracturing. Surfactants can reduce oil-water interfacial tension and wettability of the shale, which in turn can improve water imbibition, increase oil relative permeability and reduce water blockage at the matrix-fracture interface. Temperature in typical shale reservoirs are high and the surfactants need to be aqueous stable to be effective in these treatments. Mixing two surfactants often gives higher aqueous stability than those of the single surfactants. A large number of surfactants (anionic, non-ionic and cationic) and their blends were studied for aqueous stability, contact angle and spontaneous imbibition. Seven single surfactants and nine surfactant blends were found to be stable in both high and low salinity brines at 125 °C. All aqueous stable blends changed wettability of oil-wet shale to preferentially water-wet in both high and low salinity brines. Seven single surfactants and five surfactant blends were tested for imbibition. Surfactant solutions improved water imbibition to the extent of 20% PV. Surfactant blends improved imbibition more than the single surfactants. Imbibition in cores reached a plateau in about 3 days. Surfactant blends have the potential to be used in low salinity fracturing or refracturing fluids to stimulate shale wells.
Post-fracturing production data analysis indicates stimulation of some west Texas wells with surfactant additives did not enhance production as high as expected. Analysis of flowback and produced water for surfactant residues revealed 99% of surfactant was retained inside wells (
Literature precedent exists that polyelectrolyte (PET)-based SAs could significantly reduce surfactant adsorption not only onto a variety of outcrop minerals (Carlpool dolomite, calcite, kaolinite, Berea sandstone, Indiana limestone, etc.) and metal oxide nanoparticles, but also unconventional shale formulations in which surface area can be up to 700 m2/g. In this study, the adsorptions of surfactant and SA to proppants were first examined. Results indicate no adsorption was observed to proppant for both surfactants and PET-based SAs. SAs (0.5 to 1 gal/1,000 gal (gpt)) were then injected with surfactant (1 to 3 gpt) at an appropriate ratio into column-packed shale formulations (primarily composed of calcite, dolomite, quartz, illite, pyrite, and plagioclase feldspar) to investigate its effectiveness in controlling surfactant retention caused by adsorption. Laboratory testing revealed injection of 3 gpt mixture of surfactant and SA has a similar adsorption profile (surface tension as a function of time) as 3 gpt surfactant alone based on the dynamic surface tension measurement. Notably, the addition of SAs resulted in lower surface tension and enhanced hydrocarbon solubility; and thus, an improved oil recovery by surfactant was achieved as evidenced by the oil recovery tests. Additionally, 68% friction reduction of the fracturing fluid with surfactant and SA was sufficient for the field operation compared to the guar-based fluid used in the hydraulic fracturing applications.
As a result of the laboratory findings, field trials were executed on a three well pad in the Permian basin (PB). For the first 30 days oil and gas production appeared to be significantly higher than the average production from offset wells in the same area that were previously fractured with the same surfactant.
Production from tight formation resources leads the growth in U.S. crude oil production. Compared with chemical flooding and water flooding, gas injection is a promising EOR approach in shale reservoirs. A limited number of experimental studies concerning gas flooding in the literature focus on unconventional plays. This study is a laboratory investigation of gas flooding to recover light crude oil from nano-permeable shale reservoirs.
In this work, the N2 flooding process was applied to Eagle Ford core plugs saturated with dead oil. To investigate the effects of flooding time and injection pressure on the recovery factor, two groups of core-flood tests were performed. In group one, flooding time ranged from 1 to 5 days in increments of 1 day; in the other group, the injection pressure ranged from 1,000 psi to 5,000 psi in increments of 1,000 psi. The experimental setup was monitored using X-ray CT that helped to visualize phase flow and estimate the recovery efficiency during the test.
The potential of N2 flooding for improving oil recovery from shale core plugs was examined, and the recovery factor (RF) of each case was presented. The results from group one showed that more oil was produced with a longer flooding time. However, the incremental RF decreased with the increase of flooding time. The oil recovery was significant at the initial period of the recovery process, and a longer flooding time had less effect on extracting more oil. With flooding time constant in 1-day, the results from the second group indicated that RF increased with injection pressure, especially rising pressure, from 1,000 psi to 2,000 psi. The gas breakthrough time became shorter with the increase of injection pressure. The analysis of the CT number showed that the oil recovery process mainly occurred before the gas breakthrough. Once a fluid flow path was established, the injected gas flowed through the limited communication channels; thus, no extra oil could be extracted without increasing the injection pressure. This experimental study illustrates that gas flooding has liquid oil production potential in shale reservoirs.
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.