The poor rock quality and matrix permeability several orders of magnitude lower than conventional oil reservoirs observed in unconventional liquid reservoirs (ULR) presents many uncertainties on the storage capacity of the rock and the possibility of enhancing recovery. The technological advances in multiple stage hydraulic fracturing and horizontal drilling have improved the overall profitability of oil shale plays by enhancing the matrix -wellbore connectivity. The combination of these technologies has become the key factor for the operators to reach economically attractive production rates in the exploitation of ULR, causing a lot of focus on their improvement. However, as the reservoir matures, primary production mechanisms no longer drive oil to the hydraulic fractures, making the improvement of matrix -wellbore connectivity insufficient to provide economically attractive production rates. Therefore, the need to develop enhanced recovery techniques in order to improve the displacement of the oil from the matrix, maintain profitable production rates, extend the life of the assets and increase ultimate oil recovery becomes evident.This study presents experimental results on the use of CO 2 as an enhanced oil recovery (EOR) agent in preserved, rotary sidewall reservoir core samples with negligible permeability. To simulate the presence of hydraulic fractures, the ULR cores were surrounded by high permeability glass beads and packed in a core holder. The high permeability media was then saturated with CO 2 at constant pressure and temperature during the experiment. Production was monitored and the experiment was imaged using x-ray computed tomography to track saturation changes inside the core samples.The results of this investigation support CO 2 as a promising EOR agent for ULR. Oil recovery was estimated to be between 18 to 55% of OOIP. We provide a detailed description of the experimental set up and procedures. The analysis of the x-ray computed tomography images revealed saturation changes within the ULR core as a result of CO 2 injection. A discussion about the mechanisms is presented, including diffusion and reduction in capillary forces. This paper opens a door to the investigation of CO 2 enhanced oil recovery in ULR.
We present the first comprehensive experimental evaluation of gas injection for 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.
In our previous publications (Tovar 2017; Tovar et al. 2018a, 2018b; Tovar et al. 2014), we presented a philosophy for the operation of gas injection processes in unconventional liquid reservoirs (ULR) that consisted in using a huff-and-puff scheme at the maximum possible pressure, regardless of the MMP. We also postulated a kinetically slow peripheral vaporizing gas drive as the main recovery mechanism underlying the rationale for such operational philosophy. We based all of our findings in a collection of 21 experiments performed using crude oil and core plugs from the Wolfcamp. The main focus of this paper is that the fundamentally different production mechanisms taking place in ULR cause the recovery factor to continue increasing when pressure is increased beyond the MMP. We do this using core plugs and crude oil from a different field, the Eagle Ford. Confirmation of this finding is necessary, since it directly contradicts the behavior in conventional reservoirs. We also demonstrate the addition of a dopant, into the crude oil, has little effect in the phase behavior, which widens the validity of all our work so far; and provides additional insights into the gas transport in the porous media. The production of oil from unconventional liquid reservoirs (ULR) has seen a significant increase in the last decade due to the implementation of horizontal drilling and hydraulic fracturing technologies. However, these reservoirs have mainly been exploited through primary production, which exhibits fast production decline and low ultimate recovery. Therefore, the need to understand different transport mechanisms and to develop enhanced oil recovery (EOR) techniques to improve ultimate oil recovery and extend the life of the asset is critical. This work investigates the effects of miscibility on enhancing recovery and the implementation benefits we can obtain from it. We performed five additional core-flooding experiments. The cores were cleaned using an extended Dean-Stark extraction and re-saturated to known initial oil in place in the laboratory. Gas injection through a hydraulic fracture was simulated using high permeability glass beads surrounding the cores that were then packed in a core holder. The high permeability media was then saturated with CO2 at constant pressure and reservoir temperature. The production was monitored using a CT scanning technology throughout the length of the experiments to track changes in composition and saturation as a function of time and space. Soak time was maintained constant and the experimental pressures were selected above and below the slim-tube MMP to show the effect of MMP on recovery. Our results are consistent with a kinetically slow, peripheral vaporizing gas drive production mechanism. Recovery factor was 50% at the highest pressure of 3,500 psig. This is higher than the maximum of 40% we previously observed in the Wolfcamp, possibly due to the higher concentration of intermediate hydrocarbon components in the Eagle Ford, and the higher experimental pressure. Recovery factor increases with pressure, even above the MMP. The addition of 5% Iodobenzene in the Wolfcamp oil, increased the MMP by only 136 psig, or 7 %, indicating our conclusions are valid. This work confirms our previous findings, which challenge the paradigm that establishing miscibility is enough to achieve the highest recovery factors during CO2 flooding, as is the case in conventional reservoirs. This finding has a significant impact on field operations and should be considered during the design of gas injection EOR processes in ULR.
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