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.
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.
Matskova, N. (Universite de Poitiers) | Pret, D. (Universite de Poitiers) | Gaboreau, S. (BRGM) | Cosenza, P. (Universite de Poitiers) | Brechon, R. (Universite de Poitiers) | Gener, I. (Universite de Poitiers) | Fialips, C. I. (Total E&P) | Dubes, G. (Total E&P) | Gelin, F. (Total E&P)
Non-conventional shale reservoirs are characterized by multi-scaled pore systems closely associated with a variable spatial distribution of mineral grains and organic matter. Therefore, only an integrated multi-technique approach can provide a quantitative balance in pore size distribution. Such a balance is not achievable when each of the different methods is applied on different samples that are randomly selected within the formation being studied. In this multi-technique study, the initial cores were first scanned by μ-tomography with an achieved resolution of 78.8 μm to visualize potential spatial heterogeneities at the core scale. This approach identified similar and homogenous areas of interest for localized bulk measurements. In particular, the sub-sample positions were selected, in the 3D views, in areas presenting (i) similar non-clay grain amounts, (ii) similar X-ray linear attenuation coefficients, and (iii) no cracks or macro-heterogeneities.
This approach was applied to seven core samples (dimensions of ~7x7 cm) from the Vaca Muerta formation (Argentina), taken from three different exploration wells in zones with various hydrocarbon types (condensate gas, dry gas, and oil). These samples were chosen on the basis of well log data and their petrophysical interpretations. Lithofacies with similar mineral distribution but contrasting physical properties (resistivity, porosity, and density) and organic matter content were selected.
Conventional bulk methods were used to characterize the pore network of the selected sub-samples: mercury intrusion porosimetry, gas adsorption, nuclear magnetic resonance spectroscopy and helium pycnometry. Some of these methods are generally applied to non-localized crushed powder samples, which is inappropriate for evaluating preserved microstructure from the micro- to the macro-porosity range. For this reason, most of the acquisitions were performed on preserved core blocks, including nitrogen gas adsorption experiments, which were performed with kinetic control of adsorption equilibrium. This innovative approach has provided, for the first time ever, a full set of truly comparable data, localized on 3D views, displaying quantitative balances of pore size distribution in shale reservoirs.
Yu, Hongyan (Northwest University) | Wang, Zhenliang (Northwest University) | Rezaee, Reza (Curtin University) | Su, Yang (China University of Petroleum) | Tan, Wei (Zhanjiang Branch of CNOOC Ltd.) | Yuan, Yujie (Curtin University) | Zhang, Yihuai (Curtin University) | Xiao, Liang (China University of Geosciences, Beijing) | Liu, Xi (Northwest University, China)
Pore size distribution is of extreme important in the shale gas reservoir evaluation and exploration. However, shale is kind of quit complicated material, and traditional well logs (i.e. acoustic, density and neutron) only measure total porosity, while it cannot quantity the different pore size. Also, the laboratory NMR test is not suitable for filed scale well evaluation. Thus, we used NMR well logs to analyze different pore size distribution, we found that relaxation time <4.5ms is the bound fluid volume, which occupied the most part of the total NMR porosity. Furthermore, we also found that another new cutoff (except T2 cutoff) presence in the T2 distribution figure. We conclude that such new cutoff is for routine free fluid volume and micro fractures volume. Finally, we found that bound fluid volume is the main part for shale gas storage, and the micro fractures did not contribute a lot.
Fully understanding of the shale’s pore size distribution and bound water T2 cutoff are key important for shale gas reservoir (Cao Minh et al. 2012, Odusina and Sigal 2011), especially for the reservoir capacity estimation and hydraulic fracturing (Yu et al. 2016a, Yu et al. 2016b). Shale gas reservoirs are of complex pore types which presented the multi pore system: nano-pores in the organic matter, micro pores between the hard minerals and clay and micro-fractures along the bedding (Sondergeld et al. 2010). However, such pore characteristic especially bound fluid volume and micro-fractures, which directly influence the gas storage and hydraulic fracturing method. Loucks (2012) reported that nanometer- to micrometer-size pores and the natural fractures along with them which is the flow path during gas production (Loucks et al. 2012). Saltt also claimed that microscale and nanoscale pores within organic matter in shales come from SEM is importance to storage (Slatt and O'Brien 2011). The former studies have fully investigated the pore types in the shale, but limited literature to demonstrate the method to quantity them. These different types of pore will show bound fluid volume and free fluid volume from the NMR data Nadia (2016) has reported that the T2 cutoff for shale is 0.24ms-0.26ms, this study data is from NMR experiment (Testamanti and Rezaee 2017), however, it is not suitable for NMR logs (Georgi et al. 1999). Therefore, no significant attention has been to given to evaluate the NMR well logs for pore size distribution in the shale gas reservoir. Thus in this paper, we used NMR log data to get different pore size distribution, and find the T2 cutoff for bound fluid volume.
Development of source-rock resources relies on the rigorous knowledge of their petrophysical properties such as porosity, permeability, and hydrocarbon saturation. In parallel, a concise description of the wettability and pore structures is commended. This paper presents a detailed Nuclear Magnetic Resonance (NMR) T2 study of the wetting characteristics and pore structure in organic-rich source rocks from different locations including the Eagle Ford formation. Although these rocks are highly laminated and calcite dominated, our studies indicated that they have distinct different pore structure and connectivity, and differ in how TOC is dispersed within the rock fabric. We believe that the entailed findings could influence our thinking on how best to produce these shales, wellbore stability, drilling fluid selection and other asset development actions.
Source-rock samples with varied amount of total organic content (TOC) were drilled perpendicular or parallel to the laminations. The samples were cut into twin plugs which were sequentially saturated by spontaneous imbibition of 5% KCl brine and diesel (oil). The NMR T2 measurements were used to determine the fluid imbibition rate and amount, as well as the porosity associated with organic and inorganic components of the source rocks. The fracture apertures were obtained via an application of characteristic T2 cutoff times to the NMR T2 distributions. The mineral elements, phases and TOC of the rocks were measured using X-ray Fluorescence (XRF), X-ray Diffraction (XRD) and HAWK pyrolysis, respectively.
The prevalence of surface relaxation on the NMR dynamics was prominent as the transverse relaxation took place at time scales (T2 ≤ 100 ms) much shorter than their bulk values. The overall wettability of the samples showed a mixed character as the brine and the oil had been intimately imbibed. Nevertheless, the details of the wetting behavior of the Eagle ford samples and the other samples were different. For instance, Eagle Ford samples imbibed larger volumes of brine and faster than oil, on the contrary the other samples imbibed larger volumes of oil and faster than brine.
The apparent preference of oil on the other samples is attributed to their high TOC compared to the Eagle Ford samples. Upon imbibition in these samples, brine is observed to flow along the clay rich bedding planes. In fact, the interaction between brine and clay is identified to be the potential driver of the rock stability problems especially near the wellbore; however it is constrained by the type of residing clays. The discrepancies in the wetting traits are magnified by the presence of fractures which enhanced the network connectivity of both hydrophobic and hydrophilic pores or even across them. Furthermore, the fractures allowed the fluids to surpass the vertical bedding planes and thus accelerating the fluid distribution processes inside the pore space. The fracture apertures were found to range from 1 μm to 15 μm which are typical values for source rocks (
Interpretation of NMR relaxometry in organic-rich mudrocks still remains a challenge for petrophysicists. A reliable numerical simulation of NMR response in these rocks helps in better understanding of the NMR relaxometry data and the corresponding petrophysical properties (e.g., the wettability and fluid distribution in the pore space). The hydrocarbon-wetting or mixed-wetting characteristics of organic-rich mudrocks have significant impacts on hydrocarbon recovery from the rocks, but quantification of wettability using conventional well-log interpretation methods remains a conundrum. The objectives of this paper are (a) to introduce a NMR two-phase simulation method to model the NMR responses in organic-rich mudrocks and (b) to investigate the effects of wettability alteration and fluid distribution on NMR relaxometry using numerical simulations.
We simultaneously simulate the NMR responses from both water and hydrocarbon phases in organic-rich mudrocks using a random-walk algorithm. The main input to this two-phase NMR simulator is a digital rock matrix reconstructed from 3D pore-scale images of organic-rich mudrock samples, including water, inorganic grains, hydrocarbon, and kerogen. The pore-scale digital images are obtained from FIB-SEM (Focused Ion Beam Scanning Electron Microscope) images. The output of the NMR simulator is the NMR transverse magnetization decay in the rock matrix. The NMR
We successfully simulated NMR