Fractured Cores Research Articles

Stimulation of Calcite-Rich Shales Using Nanoparticle-Microencapsulated Acids

Summary Acid treatment is a common stimulation technique to increase the conductivity of calcite–rich reservoirs. Retarded acid systems such as acid–in–oil emulsions are typically used to minimize wellbore damage and long–distance propagation of acids from the wellbore. However, the stability of these emulsions under harsh reservoir conditions is still a challenge. This study investigates a novel, robust acid carrier system using silica nanoparticles (NPs) for acid treatment of calcite–rich shales. First, highly hydrophobic silica NPs were blended with concentrated acid solutions (0.5–15 wt%) to form acid–in–air powder or microencapsulated acid (MEA). The MEA was then placed in an unpropped fractured core system, and fracture closure was simulated by increasing the overburden pressure. It resulted in the mechanical crushing of the MEA and release of the acid. The conductivity of the cores before and after the MEA treatment was measured. Finally, the surface etching on the fracture face caused by acid was quantified by measuring the surface roughness using an optical profilometer. The qualitative characterization was performed using optical microscopy. The mixing of highly hydrophobic silica NPs with acids under high shear rates resulted in the formation of MEA by self–assembly of the NPs at the water/air interface. These MEA particles were found to be robust encapsulating agents for acids where the release could be triggered by means of mechanical crushing. The fracture–conductivity experiments showed that the MEA could dramatically improve (up to 40 times) the permeability of the unpropped fractures by creating concentration–dependent, nonuniform localized surface etching.

Experimental investigation on influencing factors of CO2huff and puff under fractured low‐permeability conditions

AbstractThe fracture system is a vital component of fractured low‐permeability reservoirs. The presence of fractures can improve reservoir flow capacity and injected carbon dioxide (CO2) utilization, thus leading to higher oil recovery. In this study, the effects of the presence of fracture, fracture morphology, soaking time, andCO2injection volume onCO2huff and puff were investigated through 11 low‐permeability cores with different properties. The experimental results indicated that the presence of fractures enhanced cyclic oil recovery and increased the effective cycle numbers duringCO2huff and puff in low‐permeability cores. Moreover, compared with low‐permeability cores without fractures, ultimate oil recovery ofCO2huff and puff was risen up by ~11% in fractured cores. Longer soaking time was conducive to enhancing ultimate oil recovery ofCO2huff and puff in fractured low‐permeability cores, but the excessive soaking time had little effect on ultimate oil recovery. Meanwhile, excessiveCO2injection volume did not significantly improve the performance ofCO2huff and puff, but it did reduce theCO2utilization. Moreover, gravity caused the produced oil to deposit on the bottom surface of the blowout end of the fracture, which made oil recovery of the core with a horizontal fracture slightly higher (~7%) than that of the core with a vertical fracture. In addition, variation in the intersection angle of fractures had little effect on ultimate oil recovery ofCO2huff and puff in fractured low‐permeability cores. It, however, did change the conductivity of the entire core, thus affecting oil recovery during the first two cycles remarkably.

Surfactant and a mixture of surfactant and nanoparticles to stabilize CO2/brine foam, control gas mobility, and enhance oil recovery

Injecting carbon dioxide into oil reservoirs has the potential to serve as an enhanced oil recovery (EOR) technique, mitigating climate change by storing CO2 underground. Despite the successful achievements reported of CO2 to enhance oil recovery, mobility control is one of the major challenges faced by CO2 injection projects. The objective of this work is to investigate the potential of using surfactant and a mixture of surfactant and nanoparticles to generate foam to reduce gas mobility and enhance oil recovery. A newly developed anionic surfactant and a mixture of the surfactant and surface-modified silica nanoparticles were used to assess the ability of generating a stable foam at harsh reservoir conditions: sc-CO2 and high temperature. Dynamic foam tests and coreflood experiments were conducted to evaluate foam stability and strength. To measure the mobility of injected fluids in sandstone rocks, the foam was generated by co-injection of sc-CO2 and surfactant, as well as a mixture of surfactant and nanoparticles at 90% quality. The coreflood experiments were conducted using non-fractured and fractured sandstone cores at 1550 psi and 50 °C. The use of surfactant and mixture was able to generate foam in porous media and reduce the CO2 mobility. The mobility reduction factor (MRF) for both cases was about 3.5 times higher than that of injecting CO2 and brine at the same conditions. The coreflood experiments in non-fractured sandstone rocks showed that both surfactant and a mixture of surfactant and nanoparticles were able to enhance oil recovery. The baseline experiment in the absence of surfactant resulted in a total recovery of 71.50% of the original oil in place. However, the use of surfactant was able to bring oil recovery to 76% of the OOIP. The addition of nanoparticles to surfactant, though, resulted in higher oil recovery, 80% of the OOIP. In fractured rocks, oil recoveries during secondary production mechanisms for the mixture, the surfactant alone, and sc-CO2 alone were 12.62, 8.41, and 7.21% of the OOIP, respectively. Huge amount of oil remains underground following the primary and secondary oil production schemes. CO2 has been widely used to enhance oil recovery. However, its high mobility might result in unfavorable and unsuccessful projects. The use of specially designed surfactants and the synergistic effect of surfactant and nanoparticles may provide a solution to stabilize CO2/brine foam at harsh reservoir conditions and, therefore, reduce the gas mobility and, consequently, enhance oil recovery.

Evaluation of oil production potential in fractured porous media

Based on rock samples of tight oil reservoirs in the buried hills of North China, conventional gas flooding and high-speed centrifugal experiments at different pressures were carried out. Combined with nuclear magnetic resonance experiments, an evaluation method of oil production potential in fractured porous media was established to quantitatively study the gas flooding potential of target reservoirs. Results indicated that the “gas fingering phenomenon” is serious in conventional gas flooding experiments of fractured cores even under low pressures because of fractures. With an increase in flooding pressure, the changes of T2 (T2 relaxation time) spectrum and displacement percentage are relatively small, which means that the displacement efficiency has not been improved significantly (the flooding pressure for these three cores increased from 0.014 MPa to 2.6 MPa, with an average increase in displacement percentage of 6.3%). High-speed centrifugation can realize “homogeneous displacement” of the cores and overcome the influence of gas channeling. With an increase in the displacement pressure, the T2 spectrum and percentage of displaced oil varied obviously, and the displacement efficiency improved greatly (the flooding pressure for these three cores increases from 0.014 MPa to 2.6 MPa, with an average percentage of displaced oil being increased to 16.16%). Using the method of this study, 13 cores of the target reservoir were evaluated for gas flooding potential. The percentage of available pores in the target reservoir ranges from 17.64% to 58.54%, with an average of 33.84%. Movable fluid controlled by microthroats in the reservoirs larger than 0.1 mD is about 20%, while that in the reservoirs smaller than 0.1 mD is about 5%. This study indicates that the development of fractures and microfractures controls the physical properties and fluid productivity of reservoirs.

Exploring Low-IFT Foam EOR in Fractured Carbonates: Success and Particular Challenges of Sub-10-md Limestone

SummaryThe high formation heterogeneity in naturally fractured limestone reservoirs requires mobility control agents to improve sweep efficiency and boost oil recovery. However, typical mobility control agents, such as polymers and gels, are impractical in tight sub-10-md formations due to potential plugging issues. The objective of this study is to demonstrate the feasibility of a low-interfacial-tension (low-IFT) foam process in fractured low-permeability limestone reservoirs and to investigate relevant geochemical interactions.The low-IFT foam process was investigated through coreflood experiments in homogeneous and fractured oil-wet cores with sub-10-md matrix permeability. The performance of a low-IFT foaming formulation and a well-known standard foamer [alpha olefin sulfonate (AOS) C14-16] were compared in terms of the efficiency of oil recovery. The effluent ionic concentrations were measured to understand how the geochemical properties of limestone influenced the low-IFT foam process. Aqueous stability and phase behavior tests with crushed core materials and brines containing various divalent ion concentrations were conducted to interpret the observations in the coreflood experiments.Low-IFT foam process can achieve significant incremental oil recovery in fractured oil-wet limestone reservoirs with sub-10-md matrix permeability. Low-IFT foam flooding in a fractured oil-wet limestone core with 5-md matrix permeability achieved 64% incremental oil recovery compared to waterflooding. In this process, because of the significantly lower capillary entry pressure for surfactant solution compared to gas, the foam primarily diverted surfactant solution from the fracture into the matrix. This selective diversion effect resulted in surfactant or weak foam flooding in the tight matrix and hence improved the invading fluid flow in the matrix. Meanwhile, the low-IFT property of the foaming formulation mobilized the remaining oil in the matrix. This oil mobilization effect of the low-IFT formulation achieved lower remaining oil saturation in the swept zones compared with the formulation lacking low-IFT property with oil. The limestone geochemical instability caused additional challenges for the low-IFT foam process in limestone reservoirs compared to dolomite reservoirs. The reactions of calcite with injected fluids—such as mineral dissolution and the exchange of calcium and magnesium—were found to increase the Ca2+ concentration in the produced fluids. Because the low-IFT foam process is sensitive to brine salinity, the additional Ca2+ may cause potential surfactant precipitation and unfavorable over-optimum conditions. It, therefore, may cause injectivity and phase-trapping issues especially in the homogeneous limestone.Results in this work demonstrated that despite the challenges associated with limestone dissolution, the low-IFT foam process can remarkably extend chemical enhanced oil recovery (EOR) in fractured oil-wet tight reservoirs with matrix permeability as low as 5 md.

Surfactant Prefloods During Carbon Dioxide Foam Injection for Integrated Enhanced Oil Recovery in Fractured Oil-Wet Carbonates

Summary An integrated enhanced-oil-recovery (EOR) (IEOR) approach is used in fractured oil-wet carbonate core plugs where surfactant prefloods reduce interfacial tension (IFT), alter wettability, and establish conditions for capillary continuity to improve tertiary carbon dioxide (CO2) foam injections. Surfactant prefloods can alter the wettability of oil-wet fractures toward neutral/weakly-water-wet conditions that in turn reduce the capillary threshold pressure for foam generation in matrix and create capillary contact between matrix blocks. The capillary connectivity can transmit differential pressure across fractures and increase both mobility control and viscous displacement during CO2-foam injections. Outcrop core plugs were aged to reflect conditions of an ongoing CO2-foam injection field pilot in west Texas. Surfactants were screened for their ability to change the wetting state from oil-wet using the Darcy-scale Amott-Harvey index. A cationic surfactant was the most effective in shifting wettability from an Amott-Harvey index of –0.56 to 0.09. Second waterfloods after surfactant treatments and before tertiary CO2-foam injections recovered an additional 4 to 11% of original oil in place (OIP) (OOIP), verifying the favorable effects of a surfactant preflood to mobilize oil. Tertiary CO2-foam injections revealed the significance of a critical oil-saturation value below which CO2 and surfactant solution were able to enter the oil-wet matrix and generate foam for EOR. The results reveal that a surfactant preflood can reverse the wettability of oil-wet fracture surfaces, lower IFT, and lower capillary threshold pressure to reduce oil saturation to less than a critical value to generate stable CO2 foam.

Experimental Investigation of the Damage Mechanisms of Drilling Mud in Fractured Tight gas Reservoir

Mud pollution seriously restricts the development of tight gas reservoirs. For the Dabei tight gas field in Tarim Basin, lots of wells show a higher skin factor on the pressure buildup test curves after drilling. Little researches on mud damage have been conducted for the fracture gas reservoir. Based on the previous researches, a dynamic filtration experimental method utilizing full diameter cores is established for fracture-porous cores under reservoir temperature. Twelve sets of dynamic filtration tests with full diameter cores (D = 10 cm) on the established device and some cuttings microscopic analysis on environmental-scanning-electron microscope/energy dispersive X-ray detector (ESEM/EDX) have been conducted. The effects of core type, fracture width, pressure difference, and mud type on mud damage are all investigated. The results show that the fractured cores suffer a more serious damage degree and exhibit lower return permeability ratio, compared with the porous cores. And the damage degree of fractured cores is proportional to the fracture width and pressure difference. The solids invasion is the key factor damaging the fractured cores, while the porous is mainly impaired by the filtrate invasion. This paper provides a scientific, in-depth understanding of the behaviors, laws, and characteristics of mud damage in fractured and porous cores.

Multi-scale Model of Reactive Transport in Fractured Media: Diffusion Limitations on Rates

Reactive transport in fractured media is conceptualized as a multi-scale problem that couples a pore-scale component, which comprises Navier–Stokes flow, multi-component transport and aqueous equilibrium in the fracture, and a Darcy-scale component, which comprises multi-component diffusive transport, aqueous equilibrium and mineral reactions in the porous matrix. The model that implements this multi-scale approach builds on an existing pore-scale model and is able to capture complex fracture geometries with the embedded-boundary method. The embedded boundary acts as the interface between pore- and Darcy-scale domains. Adaptive mesh refinement is used to match resolutions at the interface while using coarser resolution away from the interface when not needed in the Darcy-scale domain. The new model is validated and then compared to results from a pore-scale model. Multi-scale model results are shown to be equivalent to pore-scale results under diffusion-controlled reactions in the pore scale and very fast dissolution in the Darcy scale. The multi-scale model provides a more accurate solution for a given resolution as it effectively sets the equilibrium concentrations as boundary conditions. The multi-scale model is capable to capture flow channelization observed in an experimental fractured core and, at the same time, limitations in the dissolution of calcite by diffusive transport through an altered porous layer. Discrepancies in effluent calcium concentrations between the multi-scale results and results from a reduced-dimension Darcy-scale model for this fractured core experiment are attributed to the solution of the flow field and the gradients that develop inside the fracture. Discrepancies in effluent magnesium concentrations exemplify the limitations of the approach because the multi-scale model requires calibration of reactive surface areas as Darcy-scale continuum models.

Effect of fracture on production characteristics and oil distribution during CO2 huff-n-puff under tight and low-permeability conditions

CO2 injection is an effective technique to enhance the oil recovery of tight or low-permeability reservoirs, which also achieves resource utilization and geological storage of CO2. While the fractures in the formation have remarkable effect on the performance of CO2 injection. In this study, CO2 huff-n-puff experiments were carried out with fractured cores, and the NMR was used to investigate the oil distribution. The effects of fractures on CO2 huff-n-puff and remaining oil distribution at different permeability levels were evaluated. The experimental results show that fracture can significantly increase the CO2 sweep volume of the core, and the oil recovery rate is sharply improved in the initial and middle stages during CO2 huff-n-puff. Besides, the remaining oil saturation significantly decreases near the fracture. The final oil recovery of the fractured cores enhanced by ∼14% compared with that of fracture-free cores. The permeability of matrix remarkably affects the CO2 huff-n-puff of fracture-free cores, whereas its effect on fractured cores is relatively small, fractures can reduce the effect of permeability on recovery. The crude oil is mainly produced from the macropores and the remaining oil in the cores is mainly distributed in the small and medium pores. Moreover, an increase in the number of cycles can improve the cumulative oil recovery, but as the number of cycles increases, the production of new crude oil decreases. This study provides a reference to evaluate the oil production characteristics of fractured reservoirs and improve the production performance.

Upscaling of CO2 injection in a fractured oil reservoir

The purpose of this study is to present the numerical evaluation of the upscaling of secondary and tertiary CO2 flooding at reservoir pressure and temperature. In all simulation cases, CO2 is injected from the top of the fracture in a fracture-matrix block system and displaces oil toward the bottom of the block. Our numerical models provide comprehensive sensitivity analyses that are proved to be important for the upscaling of CO2 injection from lab to reservoir scale. In addition, we address the scale dependency of the diffusion mechanism in a large matrix-fracture domain.In our earlier studies, we have conducted a significant number of reservoir-condition CO2 flood experiments by employing fractured core systems and North Sea reservoir oil. Our experimental and numerical studies are proved to be useful to investigate the complex physical phenomena affecting the efficiency of CO2 injection in oil recovery from a fracture reservoir. The height of the core plugs used in our experiments varies from 7 to 28 cm while the fracture spacing varies between ∼4 cm and 12 cm. In all cases, we find the important role of diffusion mechanism in increasing oil recovery in a fracture-matrix system at the lab scale. However, the field matrix block size is often 1-to-2 orders of magnitude larger than that in the lab scale. Recovery mechanisms are significantly affected by the matrix dimension. For instance, the impact of diffusion mechanism on oil recovery may alter with the size of the matrix block and the fracture spacing. This highlights the importance of upscaling from lab to the field scale that is addressed in this study.We employ a compositional reservoir simulation with a developed equation of state (EOS) to model CO2 injection in a fracture-matrix system at reservoir conditions. In all the numerical simulations, the single-porosity (SP) model consists of a single axial fracture with a typical fracture aperture of 1 mm. The SP model also contains a single matrix block that feeds the producer through fracture next to it. The dimension of the fracture-matrix block varies in the SP models to account for the scale dependency of the results. In our modeling framework, we assume a network of open fractures that are homogenously distributed in the reservoir and links the oil in the matrix to the production wells. We initialize the matrix with the North-Sea-Chalk-Field (NSCF) live oil and the fracture with the injected gas (CO2). The whole displacement process is operated at the constant reservoir conditions of 3750 psia and 110 °C, representing typical NSCF reservoir conditions. Prior to conducting simulations, we successfully tune EOS parameters against the extensive PVT data, sampled from a specific fractured NSCF reservoir. The tuned EOS model assures the proper estimation of the complex phase and volumetric properties for CO2 and oil mixtures at reservoir conditions. In addition, the multi-component diffusion coefficients that are tuned using experimental data are employed as input parameters for the compositional simulations.We study the effect of several key parameters on oil recovery; e.g. matrix block size, fracture spacing, CO2 injection rate, density difference, vaporization and the diffusion. The results show that the mass transport is mainly dominated by diffusion in the lab scale which is not the case for the large matrix block size. Finally, we test the accuracy of the dual-porosity (DP) model against the SP model at various displacement conditions. Results show that when diffusion and vaporization are significant the DP model fails to predict the results of the SP reservoir model.Our findings are an important step towards modeling the tertiary-CO2 flooding in an actual fracture-chalk system. We also provide some important inputs that are necessary for upscaling tertiary-CF from a lab-scale into a field-scale reservoir model.

Reactive Transport Simulation of Fracture Channelization and Transmissivity Evolution.

Underground fractures serve as flow conduits, and they may produce unwanted migration of water and other fluids in the subsurface. An example is the migration and leakage of greenhouse gases in the context of geologic carbon sequestration. This study has generated new understanding about how acids erode carbonate fracture surfaces and the positive feedback between reaction and flow. A two-dimensional reactive transport model was developed and used to investigate the extent to which geochemical factors influence fracture permeability and transmissivity evolution in carbonate rocks. The only mineral modeled as reactive is calcite, a fast-reacting mineral that is abundant in subsurface formations. The X-ray computed tomography dataset from a previous experimental study of fractured cores exposed to carbonic acid served as a testbed to benchmark the model simulation results. The model was able to capture not only erosion of fracture surfaces but also the specific phenomenon of channelization, which produces accelerating transmissivity increase. Results corroborated experimental findings that higher reactivity of the influent solution leads to strong channelization without substantial mineral dissolution. Simulations using mineral maps of calcite in a specimen of Amherstburg limestone demonstrated that mineral heterogeneity can either facilitate or suppress the development of flow channels depending on the spatial patterns of reactive mineral. In these cases, fracture transmissivity may increase rapidly, increase slowly, or stay constant, and for all these possibilities, the calcite mineral continues to dissolve. Collectively, these results illustrate that fluid chemistry and mineral spatial patterns need to be considered in predictions of reaction-induced fracture alteration and risks of fluid migration.

Experimental and numerical investigations on the effect of fracture geometry and fracture aperture distribution on flow and solute transport in natural fractures

The impact of fracture geometry and aperture distribution on fluid movement and on non-reactive solute transport was investigated experimentally and numerically in single fractures. For this purpose a hydrothermally altered and an unaltered granite drill core with axial fractures were investigated. Using three injection and three extraction locations at top and bottom of the fractured cores, different dipole flow fields were examined. The conservative tracer (Amino-G) breakthrough curves were measured using fluorescence spectroscopy. Based on 3-D digital data obtained by micro-computed tomography 2.5-D numerical models were generated for both fractures by mapping the measured aperture distributions to the 2-D fracture geometries (x-y plane). Fluid flow and tracer transport were simulated using COMSOL Multiphysics®.By means of numerical simulations and tomographic imaging experimentally observed breakthrough curves can be understood and qualitatively reproduced. The experiments and simulations suggest that fluid flow in the altered fracture is governed by the 2-D fracture geometry in the x-y plane, while fluid flow in the unaltered fracture seems to be controlled by the aperture distribution. Moreover, we demonstrate that in our case simplified parallel-plate models fail to describe the experimental findings and that pronounced tailings can be attributed to complex internal heterogeneities. The results presented, implicate the necessity to incorporate complex domain geometries governing fluid flow and mass transport into transport modeling.

Analytical and visual assessment of fluid flow in fractured medium

Most reservoirs consist of natural and artificial fractures, including isolated microscopic fissures. These fractures form complicated paths for reservoir characterization and fluid movement that ultimately impacts production performance and ultimate recovery. That's why recovery estimations of fractured reservoirs are considered to be extremely challenging due to complexity and heterogeneity of the geological patterns.Oil production from fractured reservoirs results in varying saturation values throughout the reservoir. This is due to the microscopic fissures and heterogeneity of the fracture environment, which could not be swept thoroughly. Higher production/injection ratios also enhance the fingering effect by passing oil through the reservoir.In this study, naturally and artificially fractured cores were used. Analytical and experimental calculations were performed in order to understand the physical structure of the cores. Moreover, in the literature the analytical solutions of the fractures were defined by cubic law (CL), local cubic law (LCL) and modified cubic law (MCL). However, due to the lack of consideration of fracture properties with limited experimental work, there needs still work on this field.Equivalent fracture aperture (EFA) measurements were done by microscope and compared with the analytical calculations. Laboratory results were defined by the equation developed for predicting equivalent fracture apertures as Improved Cubic Law (ICL). Shrinkage in equivalent fracture aperture was also defined by ICL observed by microscope.Using ICL, analytical calculations were done in different environments. Equivalent fracture apertures were calculated for all the experimental flow rates under laminar flow. ICL has worked with the fractured cores flow definition whereas not for homogeneous cores.That's why due to higher calculated values and the 15% error on EFA, a correction coefficient (C) included to the CL equation for the tortuosity or the roughness effect. This result was in th error range of previous results and gave more realistic estimation with respect to the previous studies carried out. Finally, C coefficient was calculated in a range of 0.53–0.65.

New Approach to Alternating Thickened–Unthickened Gas Flooding for Enhanced Oil Recovery

Direct gas thickening is a conventional mobility control method to improve volumetric sweep efficiency for miscible gas injection (MGI) projects. However, the viability of this approach with technically feasible thickeners has not been verified at the field-scale due to a combination of high costs and/or environmental issues. One approach to make this technique economically more attractive is the implementation of an alternating injection scheme (similar to water-alternating-gas (WAG)) that would require less of the thickened gas compared with a continuous injection scheme. In this study, the effectiveness of this approach where a miscible alternating injection of thickened associated gas (TAG) or thickened CO2 (TCO2) with unthickened AG is explored in both nonfractured and fractured composite carbonate cores. Twelve core-flooding experiments were conducted using different injection schemes (i.e., continuous unthickened, continuous thickened, and alternating thickened–unthickened). These tests demonstrate...

Microscale Analysis of Fractured Rock Sealed With Microbially Induced CaCO3 Precipitation: Influence on Hydraulic and Mechanical Performance

AbstractMicrobially induced CaCO3 precipitation (MICP) has shown great potential to reduce permeability in intact rocks as a means to seal fluid pathways in subsurface ground, for example, to secure waste storage repositories. However, much less is known about how to apply MICP to seal fractured rock. Furthermore, there is limited information on the hydraulic and mechanical properties of MICP filled fractures, which are essential criteria to assess seal performance. Here MICP injection strategies were tested on sandstone cores, aimed at obtaining a homogeneous porosity fill that reduced permeability by 3 orders of magnitude. The injection strategy resulting in the most homogenous calcite distribution was then applied to fractured granite cores, to yield transmissivity reduction of up to 4 orders of magnitude. Microscale analysis of these sealed granite cores using X‐ray‐computed tomography and electron microscopy showed that >67% of the fracture aperture was filled with calcite, with crystals growing from both fracture planes, and bridging the fracture aperture in several places. Shear strength tests performed on these cores showed that the peak shear strength correlated well with the percentage of the fracture area where calcite bridged the aperture. Notably, brittle failure occurred within the MICP grout, showing that the calcite crystals were strongly attached to the granite surface. If MICP fracture‐sealing strategies can be designed such that the majority of CaCO3 crystals bridge across the fracture aperture, then MICP has the potential to provide significant mechanical stability to the rock mass as well as forming a hydraulic barrier.

Water, CO2 and Argon Permeabilities of Intact and Fractured Shale Cores Under Stress

As shale is the caprock over many reservoirs targeted for CO2 storage, shale permeability to CO2 has become an important concern. Measurements of this permeability need to be performed under in-situ conditions, with realistic temperatures, confining pressures and fluid pressures, and the effects of variables such as pressure, temperature, and shale moisture content need to be thoroughly addressed. Furthermore, the exposure of wet shale to dry CO2 can lead to, for example, dehydration and two-phase flow, that in turn affect permeability. This paper reports shale permeability measurements performed on two shale core plugs from Svalbard, under in-situ pressure and temperature conditions relevant for CO2 storage, using argon, CO2, and water as the permeate, and using both transient pulse and constant flow techniques. Permeability was found to be dependent mainly on effective confining pressure and on shale moisture content. The following was observed: (1) permeability decreased with increasing effective confining pressure; (2) permeability to water was lower than permeability to Ar or CO2; (3) shale moisture content had a strong inhibiting effect on the flow of Ar and CO2; (4) when a high CO2-flow was applied to a shale sample containing a hydrous pore fluid, a breakthrough effect occurred; and (5) in the presence of pore water, compaction creep can occur, causing a permanent decrease in permeability.

Low-IFT Foaming System for Enhanced Oil Recovery in Highly Heterogeneous/Fractured Oil-Wet Carbonate Reservoirs

Summary Oil recovery in heterogeneous carbonate reservoirs is typically inefficient because of the presence of high-permeability fracture networks and unfavorable capillary forces within the oil-wet matrix. Foam, as a mobility-control agent, has been proposed to mitigate the effect of reservoir heterogeneity by diverting injected fluids from the high-permeability fractured zones into the low-permeability unswept rock matrix, hence improving the sweep efficiency. This paper describes the use of a low-interfacial-tension (low-IFT) foaming formulation to improve oil recovery in highly heterogeneous/fractured oil-wet carbonate reservoirs. This formulation provides both mobility control and oil/water IFT reduction to overcome the unfavorable capillary forces preventing invading fluids from entering an oil-filled matrix. Thus, as expected, the combination of mobility control and low-IFT significantly improves oil recovery compared with either foam or surfactant flooding. A three-component surfactant formulation was tailored using phase-behavior tests with seawater and crude oil from a targeted reservoir. The optimized formulation simultaneously can generate IFT of 10−2 mN/m and strong foam in porous media when oil is present. Foam flooding was investigated in a representative fractured core system, in which a well-defined fracture was created by splitting the core lengthwise and precisely controlling the fracture aperture by applying a specific confining pressure. The foam-flooding experiments reveal that, in an oil-wet fractured Edward Brown dolomite, our low-IFT foaming formulation recovers approximately 72% original oil in place (OOIP), whereas waterflooding recovers only less than 2% OOIP; moreover, the residual oil saturation in the matrix was lowered by more than 20% compared with a foaming formulation lacking a low-IFT property. Coreflood results also indicate that the low-IFT foam diverts primarily the aqueous surfactant solution into the matrix because of (1) mobility reduction caused by foam in the fracture, (2) significantly lower capillary entry pressure for surfactant solution compared with gas, and (3) increasing the water relative permeability in the matrix by decreasing the residual oil. The selective diversion effect of this low-IFT foaming system effectively recovers the trapped oil, which cannot be recovered with single surfactant or high-IFT foaming formulations applied to highly heterogeneous or fractured reservoirs.

Experimental and numerical investigations of permeability in heterogeneous fractured tight porous media

Analyzing gas flow behavior is important for production prediction in heterogeneous fractured shale reservoirs, which is complex due to the presences of nanopores and high-degree heterogeneity in these complex flow network. First, we applied the discrete fracture model to simulate gas pulse-decay experiments in core plugs with different configurations. The effective permeability ratio was proposed to evaluate the effects of heterogeneity, fracture, and vug on the flow behavior. Second, we performed pulse-decay experiments on one intact fractured shale core to examine the effects of pore pressure and effective stress on permeability variations. The measured pressure profiles were history matched by numerical methods to obtain the porosity and permeability of matrix and fracture. The matching degree is evaluated by the Global Matching Error (GME). Our results highlight the positive impact of dense fracture network to improve flow capacities in the tight reservoir: effective permeability of the fractured core with 8 pairs of 1.3-cm connected fractures increases 4.07 times that of the un-fractured core. Vugs might be important as well if they connect adjacent fracture networks, but their own contribution to flow capacity is negligible: effective permeability increases only 1.00 to 1.02 times when the number of vugs increase from 3 to 35. The GME ranges from 0.04% to 0.2% for history matching of the fractured core. Core heterogeneity is exhibited more obviously when gas flows through under low pressure than under high pressure, which can be used to guide the design of pulse-decay experiment properly depending on the purpose. The main contributions of this study are that we constructed the finite-element based numerical model to simulate the pulse-decay experiment, proposed a methodology to upscale core permeability when fractures and vugs are present, and measured porosity and permeability for the matrix and fracture simultaneously in one fractured core over a wide range of pressure and effective stress.

Effectiveness of oil displacement by sequential low-salinity waterflooding in low-permeability fractured and non-fractured chalky limestone cores

Low-salinity waterflooding has been recognized as a method of enhancing oil recovery in low-permeability reservoirs. This method is relatively inexpensive and can be easily implemented in the field. Various mechanisms of low-salinity flooding have been proposed including interfacial tension reduction, wettability alteration (cation exchange), change in pH (increase), emulsion formation, and clay migration. Hydraulic fracturing has been known as a technique of stimulating hydrocarbon flow from low-permeability matrix into wellbores by creating high-conductivity fractures. The objective of this study is to evaluate the effectiveness of sequential low-salinity brine flooding process to enhance oil recovery in low-permeability fractured and non-fractured chalky limestone core samples. The low-salinity waterflooding tests were conducted with synthetic brines of five different salinity concentrations, namely, 157,662, 72,927, 62,522, 6252, and 1250 ppm. The properties of these brines have been thoroughly investigated in the laboratory. The crude oil and chalky limestone core samples, permeability range between 0.01 and 1.2 millidarcy, were gathered from a selected oil field in United Arab Emirates. When used as an opening move in a three-stage sequential brine flooding (SW/10→SW/50→SW 6xSO4− 2), sea water diluted ten times at 6252 ppm (SW/10) has been found to yield the highest oil recovery in fractured and non-fractured tests at the prevailing reservoir conditions, of 82.64 and 76% of OOIP, respectively. In all sequential brine flooding scenarios tested, sea water with sulfate concentration spiked six times (SW 6 × SO4− 2) only slightly increased oil recovery. The highest observed incremental recovery with sulfate spiking was 2.083% of OOIP. The effectiveness of oil displacement by sequential brine flooding has been attributed to mineral dissolution and fines migration which resulted in a favorable wettability alteration. This postulation of flow mechanism is confirmed by introducing a “flow resistance index” concept and measurements of key properties of the injected and effluent brines of each stage of the attempted sequential brine flooding scenarios. Results of this study could be consulted when selecting most efficient EOR method to develop tight carbonate oil reservoirs in the UAE and worldwide.

Mobility control in carbon dioxide-enhanced oil recovery process using nanoparticle-stabilized foam for carbonate reservoirs

Recent developments in the subject of using silica-nanoparticles (SiNPs) for stabilizing carbon dioxide (CO2)-foam have led to a renewed interest in the enhanced oil recovery (EOR) in oilfields. This study investigates the mobility control in the process of CO2 EOR through unfractured and fractured limestone cores. Toward this aim, laboratory tests were performed by co-injection of CO2 and 12 nm methyl-coated SiNPs solution to generate stable CO2 foam in the cores. In addition, sodium chloride (NaCl) and decane were used to examine the sensitivity of foam generation to salinity and to signify hydrocarbon (HC) phase in the experiments, respectively. The results revealed that SiNPs were able to generate stabilized CO2 foam in both unfractured and fractured limestone cores. A critical shear rate was established in the generation of foam with different conditions in the core-flood experiments. The cores with lower matrix permeability had a lower value of critical shear rate for foam generation. Moreover, the magnitude of apparent viscosity was found to be a crucial factor for mobility control and to obtain an optimum quality of foam. The results indicated that increasing NaCl concentration to 3 wt.% causes a decrease in the value of critical shear rate at applied temperatures. Furthermore, the findings revealed that a real mobility control in CO2 EOR process can only be reached when the generated foam still interacts with HC in the reservoir.