ISSN / EISSN : 1086-055X / 1930-0220
Published by: Society of Petroleum Engineers (SPE) (10.2118)
Total articles ≅ 2,311
Latest articles in this journal
SPE Journal pp 1-13; https://doi.org/10.2118/206721-pa
Summary Oil/water interfacial tension (IFT) is an important parameter in petroleum engineering, especially for enhanced-oil-recovery (EOR) techniques. Surfactant and low-salinity EOR target IFT reduction to improve oil recovery. IFT values can be determined by empirical correlation, but widely used thermodynamic-based correlations do not account for the surface-activities characteristic of the polar/nonpolar interactions caused by naturally existing components in the crude oil. In addition, most crude oils included in these correlations come from conventional reservoirs, which are often dissimilar to the low-asphaltene crude oils produced from shale reservoirs. This study presents a novel oil-composition-based IFT correlation that can be applied to shale-crude-oil samples. The correlation is dependent on the saturates/aromatics/resins/asphaltenes (SARA) analysis of the oil samples. We show that the crude oil produced from most unconventional reservoirs contains little to no asphaltic material. In addition, a more thorough investigation of the effect of oil components, salinity, temperature, and their interactions on the oil/water IFT is provided and explained using the mutual polarity/solubility concept. Fifteen crude-oil samples from prominent US shale plays (i.e., Eagle Ford, Middle Bakken, and Wolfcamp) are included in this study. IFT was measured in systems with salinity from 0 to 24% and temperatures up to 195°F.
SPE Journal pp 1-17; https://doi.org/10.2118/205213-pa
Summary Optimally designed drilling campaigns are essential for improving oil recovery and value creation. They are required at different stages of the hydrocarbon-field life cycle, including exploration, appraisal, development, and infill. A significant fraction of the revenue risk comes from geological uncertainty, and for this reason, subsurface teams are frequently responsible for optimizing campaign parameters such as the number of wells, the corresponding locations, and the drilling sequence. Companies use the information and learning from drilled wells to adapt the remainder of the campaign, but classical optimization methods do not account for such learning and flexibility over time. Accounting for sequential geological information acquisition and decision making in the optimization of drilling campaigns adds value to the project. We propose a method to optimize drilling campaigns under geological uncertainty by using a sequential-decision model to obtain the optimal drilling policy and applying analytics over the policy to obtain the optimal number of wells and corresponding locations. The novel contribution of policy analytics provides better access to information within the complex data structure of the optimal policy, providing decision support for different decision criteria. The method is demonstrated in two different cases. The first case considers a set of eight candidate wells on predefined locations, mimicking the situation where the method is used after a prior subsurface optimization. The second case considers a set of 12 candidate wells regularly scattered in the same area and uses the method as the first optimization approach to filter out less-attractive regions. Exploiting the geological information on a well-by-well basis improved the expected campaign value by 65% in the first case and by 183% in the second case. The value of spatial geological information and value of flexibility from having more drilling candidates are two byproducts of the method application.
SPE Journal pp 1-25; https://doi.org/10.2118/204351-pa
Summary Engineered water injection (EWI) has gained popularity as an effective technique for enhancing oil recovery. Surfactant flooding is also a well-established chemical enhanced-oil-recovery (EOR) technique in the petroleum industry. The hybrid surfactant flooding/EWI (surfactant/EWI) technique has been studied experimentally and showed promising results. However, there are very limited numerical applications on the hybrid surfactant/EWI technique in carbonates in the literature. Also, the studies applied under harsh conditions of high temperature and high salinity are even fewer. In this study, a numerical-simulation model is developed and used to investigate the hybrid effect of surfactant/EWI in carbonates under harsh conditions. This developed model was validated by history matching a recently conducted surfactant coreflood in the secondary mode of injection. Oil recovery, pressure drop, and surfactant-concentration data were used. The surfactant-flooding model was then coupled with a geochemical model that captures different reactions involved during EWI. The geochemical reactions considered include aqueous, dissolution/precipitation, and ion-exchange reactions. The proposed model has been further validated by history matching another experimental data set. Furthermore, different simulation scenarios were considered, including waterflooding, surfactant flooding, EWI, and the hybrid surfactant/EWI technique. For the case of EWI, wettability alteration was considered as the main mechanism underlying incremental oil recovery. However, both wettability alteration and interfacial-tension (IFT) reduction mechanisms were considered for surfactant flooding depending on the type of surfactant used. The results showed that for the hybrid surfactant/EWI, wettability alteration is considered as the controlling mechanism where surfactant boosts oil-recovery rate through increasing oil relative permeability while EWI reduces residual oil. Moreover, the simulation runs showed that the hybrid surfactant/EWI is a promising technique for enhancing oil recovery from carbonates under harsh conditions. Also, hybrid surfactant/EWI results in a more water-wetting rock condition compared with that of EWI alone, which leads to lower injectivity, and hence, lower rate of propagation for ion-concentration waves. The hybrid surfactant/EWI outperformed other injection techniques followed by EWI, then surfactant flooding, and finally waterflooding. This work gives more insight into the application of hybrid surfactant/EWI on enhancing oil recovery from carbonates. The novelty is further highlighted through applying the hybrid surfactant/EWI technique under harsh conditions. In addition, the findings of this study can help in better understanding the mechanism behind enhancing oil recovery using the hybrid surfactant/EWI technique and the important parameters needed to model its effect on oil recovery.
SPE Journal pp 1-11; https://doi.org/10.2118/206738-pa
Summary The expansion of the steam chamber is very important for the recovery performance of steamflooding. In this paper, we discuss 1D and 2D sandpack experiments to performed analyze the effect of flue gas on steam chamber expansion and displacement efficiency in steamflooding. In addition, we examine the effect of flue gas acting on the steam condensation characteristics. The results show that within a certain range of injection rate, flue gas can significantly enlarge the swept volume and oil displacement efficiency of steam. However, when the flue gas injection rate is excessively high (the ratio of gas injection rate to steam injection rate exceeds 4), gas channels may form, resulting in a decline of oil recovery from steamflooding. The results of the 2D visualization experiments reveal that the swept volume of the steam chamber during steamflooding was small, and the remaining oil saturation in the reservoir was high, so the recovery was only 28%. The swept volume of the steam chamber for flue-gas-assisted steamflooding was obviously larger than that of steamflooding, and the recovery of flue-gas-assisted steamflooding in 2D experiments could reach 40.35%. The results of the steam condensation experiment indicate that flue gas could reduce the growth and coalescence rates of steam-condensed droplets on the cooling wall and increase the shedding period of the droplets. Macroscopically, flue gas could reduce the heat exchange rate between the steam and the reservoir and inhibit the rapid condensation and heat exchange of the steam near the injection well. As a result, flue gas could expand the steam chamber into the reservoir for heating and displacing oil.
SPE Journal pp 1-16; https://doi.org/10.2118/202337-pa
Summary This work studies 1D steady-state flow of gas from compressible shale matrix subject to water blocking toward a neighboring fracture. Water blocking is a capillary end effect causing wetting phase (e.g., water) to accumulate near the transition from matrix to fracture. Hydraulic fracturing is essential for economical shale gas production. Water is frequently used as fracturing fluid, but its accumulation in the matrix can reduce gas mobility and production rate. Gas transport is considered at a defined pressure drop. The model accounts for apparent permeability (slip), compressibility of gas and shale, permeability reduction, saturation tortuosity (reduced relative permeability upon compaction), and multiphase flow parameters like relative permeability and capillary pressure, which depend on wettability. The behavior of gas flow rate and distributions of gas saturation, pressure, and permeability subject to different conditions and the stated mechanisms is explored. Water blockage reduces gas relative permeability over a large zone and reduces the gas flow rate. Despite gas flowing, strong capillary forces sustain mobile water over the entire system. Reducing drawdown gave lower driving force and higher resistance (by water blockage) for gas flow. The results show that 75% reduction of drawdown made the gas flow rate a couple orders of magnitude lower compared to if there was no blockage. The impact was most severe in more water-wetsystems. The blockage caused most of the pressure drop to occur near the outlet. High pressure in the rest of the system reduced effects from gas decompression, matrix compression, and slip-enhanced permeability, whereas rapid gradients in all these effects occurred near the outlet. Gas decompression resulted in an approximately 10 times higher Darcy velocity and pressure gradient near the outlet compared to inlet, which contributed to removing blockage, but the added resistance reduced the gas production rate. Similarly, higher gas Corey exponent associated gas flow with higher pressure drop. The result was less blockage but lower gas production. Slip increased permeability, especially toward the outlet, and contributed to increase in gas production by 16%. Significant matrix compression was associated with permeability reduction and increased Corey exponent in some examples. These effects reduced production and shifted more of the pressure drop toward the outlet. Upstream pressure was more uniform, and less compression and permeability reduction were seen overall compared to a system without water blockage.
SPE Journal pp 1-22; https://doi.org/10.2118/206728-pa
Summary Nonuniform mixing during low-salinity waterflooding (LSWF) is a function of the pore geometry and flow patterns within the porous system. Salinity-dependent wettability alteration (WA) changes the entry capillary pressure, which may mobilize the trapped oil depending on the flow regime and salt dispersion pattern. The complex interplay between the wettability, capillary number (NCa), and salt dispersion caused by pore-scale heterogeneity on the efficiency of LSWF is not well understood. In this paper, direct numerical simulations in a pore-doublet model (PDM) were carried out with OpenFOAM® (OpenCFD, Berkshire, UK) using the volume-of-fluid (VOF) method. Oil trapping and remobilization were studied at relevant NCa as low as 10−6 under different initial wettability states. Depending on the effective salinity ranges (ESRs) for the low-salinity effect (LSE), three WA models were implemented, and the effects of WA degree and salinity distribution on LSWF flow dynamics were investigated. The slow process of WA by means of thin film phenomena was captured by considering a diffuse interface at the three-phase contact line. Because of the pore structure of the pore doublet, only in nonwater-wet cases, oil is trapped in the narrower side channel (NSC) after high-salinity waterflooding (HSWF) and may be remobilized by LSWF. In strongly oil-wet cases, oil is recovered gradually by LSWF by means of a film-flow mechanism near the outlet. In moderately oil-wet cases, however, the entire trapped oil ganglion can be mobilized, provided that the entry capillary pressure is sufficiently reduced. The degree of WA, ESR, kinetics of WA, and the wettability of pore surface at the outlet are determining factors in the drainage of the trapped oil. The salt dispersion pattern in the flowing region [i.e., wider side channel (WSC)] controls the wettability distribution and the rate and magnitude of oil recovery from the stagnant region (i.e., NSC). The difference between the WA models is more apparent near the outlet, where the salinity profile is more dispersed. The ESR in which WA occurs determines the speed of the entry capillary pressure reduction and, thus, the recovery factor. In cases where WA occurs at a salinity threshold (ST), the highest recovery is obtained, whereas with the full-salinity-range WA model, the oil recovery performance is lowest. From the capillary desaturation perspective, it is found that the LSE becomes more pronounced when NCa is less than 10−5, and the dispersion regime is in the power-law interval. Because the adverse effect of salt dispersion in the flowing region is delayed, the LSE is intensified. For the simulations to be representative of the actual conditions in the porous medium, much lower NCa than currently used in many research works must be studied. Otherwise, the simulations may lead to over- or underestimation of the LSE. The synergetic or antagonistic effects caused by the interplay between viscous and capillary forces and dispersion may lead to total recovery or entrapment of oil, regardless of WA. Based on the pore geometry, initial wettability state, and balance of forces, the mobilized oil may flow past the conjunction (favorable) or in the backward direction (unfavorable) to the WSC and get retrapped. Successful drainage of oil from the pore system after WA is essential for observing incremental oil recovery by LSWF.
SPE Journal pp 1-13; https://doi.org/10.2118/203991-pa
Summary Modern reservoir simulation must handle complex compositional fluid behavior, orders-of-magnitude variations in rock properties, and large velocity contrasts. We investigate how one can use nonlinear domain-decomposition preconditioning to combine sequential and fully implicit (FI) solution strategies to devise robust and highly efficient nonlinear solvers. A full simulation model can be split into smaller subdomains that each can be solved independently, treating variables in all other subdomains as fixed. In subdomains with weaker coupling between flow and transport, we use a sequential fully implicit (SFI) solution strategy, whereas regions with stronger coupling are solved with an FI method. Convergence to the FI solution is ensured by a global update that efficiently resolves long-range interactions across subdomains. The result is a solution strategy that combines the efficiency of SFI and its ability to use specialized solvers for flow and transport with the robustness and correctness of FI. We demonstrate the efficacy of the proposed method through a range of test cases, including both contrived setups to test nonlinear solver performance and realistic field models with complex geology and fluid physics. For each case, we compare the results with those obtained using standard FI and SFI solvers. This paper is published as part of the 2021 Reservoir Simulation Conference Special Issue.
SPE Journal pp 1-18; https://doi.org/10.2118/206733-pa
Summary Proppant placement plays a crucial role in maintaining the conductivity of fractures after a hydraulic fracturing treatment. The process involves the transport of particles by fluid flow in complex fractures. Many studies have focused on proppant transport and distribution in the fracture with a constant aperture, but relatively few studies have investigated the proppant-fluid flow in a vertical fracture with a contracted aperture. In this work, we examine experimentally proppant transport in a fracture with a contracted aperture. The objective is to evaluate the distribution of particle beds in the contracted fracture at different flow conditions. In this paper, particle-fluid flow in the contracted fracture is studied experimentally by a laboratory size slot. A planar slot with a constant width is used to benchmark the experimental results, and a published correlation validates the bed equilibrium heights in the planar slot. Six types of particles are chosen to simulate the effects of particle density and size. The proppant distribution is evaluated by the bed height when the bed reaches the equilibrium states. The effects of fluid velocity, fluid viscosity, particle density, particle size, and particle volume fraction on particle distribution are investigated. The results confirm that the proppant particle-fluid flow in the contracted slot is more complicated than that in the planar slot. The phenomena of particle vortices and resuspension were observed at the contraction of the cross-section. The shape on the top of the bed is like a descending stair in which the height gradually decreases in the length direction. The bed height in the contracted slot is lower and more irregular than that in the planar slot at the same flow conditions. Smaller sands injected at a high flow rate and fluid viscosity can form a lower bed. The trend would be reversed by using denser particles and high particle volume fraction. A reliable model expressed by four dimensionless numbers is developed by the linear regression method for predicting the bed equilibrium height. The model and experimental results provide directions to quantitatively evaluate the particle transport and distribution in a fracture with a contracted aperture.
SPE Journal pp 1-18; https://doi.org/10.2118/206724-pa
Summary The relative permeability functions of two-phase reservoirs are extensively used in modern reservoir-engineering theories for calculations and numerical simulations. In recent years, the theory of anisotropic reservoir development has advanced rapidly, and the anisotropic absolute permeability of reservoirs has been characterized and applied accurately. However, if only the anisotropy of absolute permeability is considered while neglecting the anisotropy of relative permeability, the effective permeability used in the calculations will differ significantly from that of an actual reservoir. In this study, an anisotropy experiment on two-phase relative permeability, with oil and water, was conducted using natural sandstone without fractures, which demonstrated the existence of anisotropy in relative permeability and analyzed its mechanism. The properties and calculation methods for anisotropic relative permeability were studied under the symmetry groups of a rhombic system. Numerical simulations of the reservoir considering anisotropic relative permeability were performed. The results demonstrated that the anisotropic relative permeability significantly affected the development of the oil reservoir, which is primarily indicated by the significant difference in the seepage direction of oil and water, and the complicated oil/water distribution. The results of this study differed significantly from the conventional understanding of remaining oil distribution. The deformed well pattern established for the anisotropy of the absolute permeability indicated a decrease in the oil-recoveryratio.
SPE Journal pp 1-17; https://doi.org/10.2118/203982-pa
Summary Numerical smearing is oftentimes a challenge in reservoir simulation, particularly for complex tertiary recovery strategies. We present a new high-resolution method that uses dynamic coarsening of a fine underlying grid in combination with local timestepping to provide resolution in time and space. The method can be applied to stratigraphic and general unstructured grids, is efficient, introduces minimal computational overhead, and is applicable to flow models seen in practical reservoir engineering. Technically, the method is based on three concepts: Sequential splitting of the flow equations into a pressure equation and a system of transport equations Dynamic coarsening in which we temporarily coarsen the grid locally by aggregating cells into coarse blocks according to cell-wise indicators on the basis of residuals (gradients and other measures of spatial and temporal changes can also be used) Asynchronous local timestepping that traverses cells/coarse blocks in the direction of flow We assess the applicability of the method through a set of representative cases, ranging from conceptual to realistic, with complex fluid physics and reservoir geology, and demonstrate that the method can be used to reduce computational time and still retain high resolution in spatial/temporal zones and quantities of interest.