Zhang, Peng (University of Texas at Austin) | Sen, Mrinal K. (University of Texas at Austin) | Sharma, Mukul M. (University of Texas at Austin) | Gabelmann, Jeff (E-Spectrum Technologies Inc.) | Glowka, David (E-Spectrum Technologies Inc.)
A tool concept using downhole electrical measurements for mapping electrically conductive proppant in hydraulic fractures is presented in this paper. The method relies on direct excitation of the casing, which is expected to overcome the severe limitations of induction tools in casedhole wells. An array of insulating gaps is installed and cemented in place as a permanent part of the casing string. The envisioned electrical measurements are performed by imposing a voltage across each insulating gap, one at a time, before and after hydraulic-fracture operations. The voltages across other insulating gaps near the transmitter gap are recorded.
The proposed tool's response to the geometry of a single fracture was modeled by solving for the electrical potential with a finite-volume method. Previous simulation results have shown that the electrically conductive proppant alters the path of the electrical current in the formation, and this is recorded as differential signals by the string of insulating gaps surrounding the source gap. The simulated differential signals are highly sensitive to a fracture's location, length, and orientation, and less sensitive to the fracture's aspect ratio. However, to enable the implementation of such a practical system, various aspects of the tool concept must be investigated further through simulations. Following our previous work, this paper focuses on the forward modeling of the tool's response to multiple fractures, which demonstrates the influence of these fractures on the signals, and provides important guidance for inverse modeling. Parametric inversion of fractures from synthetic data, generated by exciting various insulating gaps, is solved with very fast simulated annealing (VFSA).
Simulation results show that, when multiple hydraulic fractures are present, the voltages measured at the receiver gaps are determined primarily by the fracture that is in direct contact with the excited section of casing. When two fractures touch the same casing section, they induce voltages very similar to those from a single fracture with the same conductivity and volume. Preliminary inversion results that use synthetic data computed from circular fractures indicate that the proposed VFSA can solve for the multiple fractures' widths and radii at the same time, without requiring numerous forward simulations. Even with noisy synthetic data, VFSA can make good estimates of the fractures' parameters. This indicates that the VFSA technique is a proper and robust inversion technique for the measured voltages at various receiver gaps.
Souza, Márcio R. A. (Federal University of Paraíba) | Contreras, Fernando R. L. (Federal University of Pernambuco) | Lyra, Paulo R. M. (Federal University of Pernambuco) | Carvalho, Darlan K. E. (Federal University of Pernambuco)
In this paper, we propose a full-cell-centered finite-volume approach to simulate two-phase flow in heterogeneous and anisotropic petroleum reservoirs. We adopt a segregated formulation where the pressure equation is discretized by a multipoint flux approximation with a diamond-type support (MPFA-D). To solve the saturation equation, we propose a higher-order modified flow-oriented scheme (M-FOS). In this scheme, adaptive weights tune the formulation multidimensionality according to the grid distortion. Also, we adopt a multidimensional limiting process (MLP) and an efficient entropy fix to produce convergent solutions. We evaluate the performance of our numerical schemes by solving some relevant benchmark problems.
The critical gas saturation in permeable sands was studied as a function of depletion rate and the presence of an aqueous phase as the major experimental variables. Voidage-replacement ratios (VRR = injected volume/produced volume) less than 1 were used to obtain pressure depletion with active water injection. Three different live crude oils were considered. Two of the oils are viscous Alaskan crudes with dead-oil viscosities of 87.7 and 600 cp, whereas the third is a light crude oil with a dead-oil viscosity of 9.1 cp. The critical gas saturation for all tests ranged from 4 to 16%. These values for critical gas saturation are consistent with the finding that the gas phase displayed characteristics similar to those of a foamy oil. For a given oil and depletion rate, the critical gas saturation was somewhat larger for VRR = 0 than it was for VRR = 0.7. The oil recovery correlates with the critical gas saturation (i.e., for a given VRR, tests exhibit greater oil recovery when the critical gas saturation is elevated). For the conditions tested, there was not a strong correlation of critical gas saturation over more than two orders of magnitude of the rate of pressure depletion, for a given VRR. Such behavior might be consistent with theoretical studies reported elsewhere that suggest that the critical gas saturation is independent of the pressure-depletion rate when the rate of depletion is small.
Tagavifar, Mohsen (University of Texas at Austin) | Sharma, Himanshu (U. of Texas at Austin) | Wang, Denning (The University of Texas at Austin) | Jang, Sung Hyun (The University of Texas at Austin) | Pope, Gary (University of Texas at Austin)
We recently used sodium hydroxide (NaOH) in Indiana limestone coreflood experiments to lower anionic-surfactant adsorption. This study presents analysis of the limestone geochemistry and the surfactant adsorption under static and dynamic conditions. Analysis of the effluent ionic composition using ion chromatography and inductively coupled plasma showed the presence of sulfate (SO2–4) aluminum (Al), and iron (Fe), as well as calcium (Ca) and magnesium (Mg). To determine the likely source of each geochemical species and to characterize how the dissolution kinetics changes the slug chemistry, PHREEQC was used to inverse-model Indiana limestone rock using the bulk X-ray-diffraction (XRD) mineralogical composition and the influent and effluent water chemistry. Results showed that all Indiana limestone cores contained anhydrite, which was not detected by XRD. The effluent concentration of Al increased with pH to approximately 15 mg/L, whereas Fe concentration remained fairly independent of pH at 0.4 ± 0.02 mg/L. These trends suggest the likely source of Al and Fe to be either clay dissolution or the release of natural clay colloids with NaOH. Simulations suggested that in Fe-bearing carbonates, alkali consumption is fast but limited with NaOH, which is observed as pH-front delay, whereas alkali consumption is slow but severe with sodium carbonate (Na2CO3) resulting in minimal pH-front delay but lower effluent pH compared with influent pH for prolonged injection times. Using the PHREEQC calculations, the ionic composition of the chemical slug in subsequent alkali/surfactant/polymer (ASP) experiments was adjusted. In addition, the coupled adsorption/transport of anionic surfactants in carbonate rocks was also investigated using surface-complexation-model adsorption under static and dynamic conditions. Model predictions agree with the single-phase-adsorption coreflood results and suggest that the adsorption on the metal oxides or clay could be comparable with that on calcite. This arises from the higher surface area and the point of zero charge of pH (pHpzc) of metal oxides.
Steam foams have been considered effective additives for unconventional oil-recovery processes. Conventionally, for steam-foam applications, chemical additives are injected with steam. However, this procedure can have serious challenges because of poor thermal stability of additives and high volume of additives loss caused by adsorption to the rock surface. To overcome these limitations, nanoparticles can be used as novel additives to improve generation and stabilization of the foams for steam-foam applications.
In this study, silica nanoparticles in synergy with surfactants have been used as steam additives. Dynamic light scattering (DLS), a foam-height test using N2 at reservoir conditions, and thermal-stability analysis were designed to measure nanoparticle size distribution in brine, foamability, and thermal stability of the additive solutions, respectively. Subsequently, coreflooding tests were performed to evaluate the synergistic effect of nanoparticles and surfactants on the foam performance and oil recovery. We observed an optimal ratio of nanoparticle and surfactant that yields the best foam-generation performance in bulk medium. Herein, surface-treated silica nanoparticles have been tested with two of our candidate surfactants. The nanoparticles alone generate a small amount of foam, whereas each surfactant generates a small-to-moderate amount of foam. Synergy is demonstrated by the system that contains 0.1-wt% nanoparticles (the optimal concentration) and 0.5-wt% surfactant solution at neutral pH (~7), as it leads to approximately 67 and 50% greater foam height, respectively, for Surfactants A and B than foam height observed in tests with surfactants only, in bulk medium. Corefloods with coinjected steam and water containing nanoparticles and surfactant confirm the synergy, exhibiting measurable improvement in mobility-reduction factor (MRF) and steam control, compared with coinjection of steam and water containing only surfactant.
Preformed-particle gels (PPGs) have been applied for reducing excessive water production caused by fractures in reservoirs. A portion of the fractures existing in reservoirs is composed of a void part and a fracture tip. The PPG placement behavior and plugging performance could be mainly affected by the fracture tips. A fracture with a tip, called a "partially open fracture" in this paper, was designed to investigate the placement and water-plugging performance of PPG. Cylindrical sandstone cores were used to manufacture partially open fractures. Pressure data of PPG injection, post-gel water breakthrough, and stable injection were analyzed to investigate the PPG propagation and plugging performance with respect to water. Experiments with different PPG placing pressures were conducted to explore the effects of pressure on PPG water-plugging performance and dehydration. In the fractures with tips, the PPG injection pressure increased rapidly, and could reach any designed pressure with continued injection after gel filled the fracture. By setting the PPG placing pressure at 500, 1,000, and 2,000 psi, the blocking efficiency to water showed a growth with the increase of placing pressure. The reswelling experiments show that PPG samples dehydrated when exposed to a high pressure difference between fracture and porous rock. Moreover, the placed PPG dehydrated relatively evenly along the fracture. Some gel particles were found whitening and reducing the capability of reswelling at the placing pressure of 2,000 psi. Scanning-electron-microscope (SEM) images indicated that the distinct 3D network of the PPG was compressed or damaged in the whitish sample. In addition, a discussion about PPG dehydration and fracture-tip extension is provided. In general, this study experimentally characterized PPG placement and plugging performance with respect to water in the fracture with tips. The PPG dehydration and fracture extension in PPG treatment, which have not drawn much attention in the literature, are investigated in this paper.
Petroleum fluids from shale light-oil and gas/condensate reservoirs generally have a high content of normal paraffins. Paraffin-wax deposition is among the challenges in shale gas and oil production and in offshore flow assurance. Low-dosage chemical additives can be effective in paraffin-wax mitigation because of their high efficiency and economics. These additives are divided into broad categories of crystal modifiers and dispersants with vastly different molecular structures and mechanisms in wax-crystal-particle stabilization and wetting. This investigation focuses on the understanding of the differences in the aggregate size and morphology of chemical additives, and it centers on (1) wax-particle sedimentation from diluted petroleum fluids in vial tests, (2) wax-crystal-particle-size distributions and morphology by dynamic light scattering (DLS) and polarized-light microscopy, and (3) the wetting state from the effect of water. In two of the three petroleum-fluid samples used in this work, there is no visible precipitation at the bottom of the vials at temperatures below the wax-appearance temperature (WAT). The microscopic image of fluids along the length of the tube shows that the wax-particle size and intensity increase from top to bottom. To observe precipitation, we dilute the crude with a hydrocarbon such as n-heptane. The sedimentation of wax is then observed. The petroleum fluids used in this work have very low asphaltene content, and there is no complication from asphaltene precipitation. Our study shows that a small amount of crystal modifier and dispersant can reduce crystal-particle size to the submicron scale, and change the crystal morphology. We investigate the differences in the mechanisms of dispersants and crystal modifiers in bulk. Water, which is often coproduced with petroleum fluids, can increase the effectiveness of dispersants significantly by altering the wetting state of the wax-particle surface. Such enhancement is not found in crystal modifiers. Both additives affect the rheology of petroleum fluids.
Compositional simulation is necessary for a wide variety of reservoir-simulation applications, and it is especially valuable for accurate modeling of near-miscible gas injection for enhanced oil recovery. Because the nonlinear behavior of gas injection is sensitive to the resolution of the simulation grid used, it is important to use a fine grid to accurately resolve the compositional and saturation gradients. Compositional simulation of highly detailed reservoir models entails the use of small timesteps and large, poorly conditioned linear systems. The high computational cost of solving such systems renders field-scale simulations practically unfeasible. The coupling of the flow and transport to the phase-equilibrium calculations adds to the challenge. This is especially the case for near-miscible gas injection, in which the phase state and the phase compositions are very strong functions of space and time.
We present a multiscale solver for compositional displacements with three-phase fluid flow. The thermodynamic phase behavior is described by general nonlinear cubic equations of state (EOS). The fully implicit (FI) natural-variables formulation is used as the basis to derive a sequential implicit (SI) solution strategy, whereby the pressure field is decoupled from the multicomponent transport. The SI scheme is mass conservative without the need to iterate between the pressure and transport equations during the timestep. This conservation property allows the errors caused by fixing the total-velocity field between the pressure- and transport-updating steps to be represented as a volume error. The method computes approximate pressure solutions—within a prescribed residual tolerance—that yield conservative fluxes on the computational grid of interest (fine, coarse, or intermediate). We use basis functions computed using restricted smoothing to allow for generally unstructured grids.
The new method is verified against existing research and commercial compositional simulators using a simple conceptual test case and also using more-complex cases represented on both unstructured and corner-point grids with strong heterogeneity, faults, and pinched-out and eroded cells.
The SI method and the implementation described here represent the first demonstrated multiscale method applicable to general compositional problems with complexity relevant for industrial-reservoir simulation.
Chen, Zhiming (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing, and University of Texas at Austin) | Liao, Xinwei (China University of Petroleum, Beijing) | Sepehrnoori, Kamy (University of Texas at Austin) | Yu, Wei (Texas A&M University)
The new formulation incorporates hysteresis and compositional consistency for both capillary pressure and relative permeability. This approach is completely unaffected by phase flipping and misidentification, which commonly occur in compositional simulations. Instead of using phase labels (gas/oil/solvent/aqueous) to define hysteretic relative permeability and capillary pressure parameters, the parameters are continuously interpolated between reference values using the Gibbs free energy (GFE) of each phase at each timestep. Models that are independent of phase labels have many advantages in terms of both numerical stability and physical consistency. The models integrate and unify relevant physical parameters, including hysteresis and trapping number, into one rigorous algorithm with a minimum number of parameters for application in numerical reservoir simulators. The robustness of the new models is demonstrated with simulations of the miscible water-alternating-gas (WAG) process and solvent stimulation to remove condensate and/or water blocks in both conventional and unconventional formations.