Search

Harsh conditions, such as high temperature (>100 oC) and high salinity (>50,000 ppm TDS), can make the application of chemical enhanced oil recovery (EOR) challenging by causing many surfactants and polymers to degrade. Carbonate reservoirs also tend to have higher concentrations of divalent cations as well as positive surface charges that contribute to chemical degradation and surfactant adsorption. The objective of this work is to develop a surfactant-polymer (SP) formulation that can be injected with available hard brine, achieve ultra-low IFT in these harsh conditions, and yield low surfactant retention. Phase behavior experiments were performed to identify effective SP formulations. A combination of anionic and zwitterionic surfactants, cosolvents, brine, and oil was implemented in these tests. High molecular weight polymer was used in conjunction with the surfactant to provide a high viscosity and stable displacement during the chemical flood. Effective surfactant formulations were determined and five chemical floods were performed to test the oil recovery potential. The first two floods were performed using sandpacks from ground Indiana limestone while the other three floods used Indiana limestone cores. The sandpack experiments showed high oil recovery proving the effectiveness of the formulations, but the oil recovery was lower in the cores due to complex pore structure. The surfactant retention was high in the sandpacks, but it was lower in Indiana Limestone cores (0.29-0.39 mg/gm of rock). About 0.4 PV of surfactant slug was enough to achieve the oil recovery. A preflush of sodium polyacrylate improved the oil recovery.

Reservoir simulators often predict poor injectivity in polymer enhanced oil recovery (EOR) projects because of the high polymer viscosity, which is a deterrent for the project. However, field studies have shown much higher injectivity than predicted by the models. The objective of this work is to perform grain-scale, coupled fluid dynamics and geomechanics modeling to predict the injectivity of viscous, non-Newtonian polymers in wellbores. Fluid-rock interactions are modeled by coupling computational fluid dynamics (CFD) and the discrete element method (DEM). Fluid flow is determined using an open-source CFD software that solves the volume-averaged Navier-Stokes equation using the finite volume method on Eulerian grids. Grain-scale geomechanics (DEM) is used to explicitly solve the particle trajectories in a Lagrangian reference system. The simulation results confirm the hypothesis of fracture initiation and sand failure near the injector. The results show that the polymer-driven fracture initiation is associated with sand shear failure, while the fracture geometry is the result of the localization of sand shear failure and fluidization of unconsolidated sand at the fracture tip. The injection of a viscous fluid can create fractures in the direction perpendicular to the applied minimum principal stress. The presence of fractures increases the injectivity. The peak injection pressure is more than 3 times greater than the applied minimum principal stress. The viscosity increase of polymers promotes the initiation of fractures and results in a greater fracture aperture. The injection of polymer can promote the initiation of fractures, and therefore, increase the polymer injectivity. This work, for the first time, uses a grain-scale model to predict polymer-driven fracture initiation and demonstrates the improved injectivity observed in the field.

We performed coreflood experiments to determine the effect of polymer viscoelasticity on the residual saturation of low viscosity oils by varying the rock type, wettability, polymer rheology, and flow conditions. Several authors have shown that polymers, if viscoelastic, can recover a significant amount of capillary-trapped oil, beyond inelastic floods, in water-wet sandstones. We demonstrate that the polymer viscoelastic effect works for several different rock types, both water-wet and oil-wet media, and with low viscosity oils which broadens the applicability found in previous works. In polymer field studies, the rheology can be tailored to maximize the effect based on our findings. Eleven corefloods were performed in Bentheimer, Boise, and Berea cores. Two of the cores were made oil-wet using dichlorodiphenylsilane (DCDPS) and chlorotrimethylsilane (CTMS). The cores were initially saturated with brine and then displaced by low viscosity (4-10 cp) crude oil until steady state was reached. Brine was then injected to displace the oil until steady state and residual oil saturation was reached. In most experiments, HPAM polymer was then injected at ∼1 ft/day; the polymer rheology was tailored via the salinity, concentration, molecular weight, and degree of hydrolysis. Once steady state was reached, a second polymer solution (with the same viscosity but higher salinity) was injected until a final oil saturation was reached. A reduction in oil saturation was observed in all corefloods in which the polymer was viscoelastic. On average, the oil saturation was reduced by 5.6% in the first polymer flood and 4.0% in the second, high salinity polymer flood. Higher recoveries were found for some experiments in which the first polymer was more elastic (higher dimensionless Deborah number). Final oil saturations as low as 5% were achieved using only polymer (and no surfactant). Results were not dependent on the rock type (e.g. Bentheimer versus Boise) but the effect was more pronounced in water-wet cores than those changed to oil-wet.

Long-term integrity and practical storage of CO2 is contingent upon its seal performance and the dynamic sealing capacity of faults for the CO2 storage site. Faults are prone to reactivation with reservoir pressurization caused by CO2 injection. The goal of this study is to create and verify a reservoir elasto-plastic model capable of capturing short-term evolution of fault reactivation and the resulting change of permeability. This model is then used to explore the effects of coupling geomechanics with reservoir fluid flow on the reactivation of faults. In this paper, we introduce a workflow for modeling of fault reactivation with fault elements as gridblocks instead of surfaces. Reservoir simulation, with coupled fluid flow and geomechanics, was used for this purpose. The simulation models utilize a geomechanical module to capture elasto-plasticity and a compositional numerical scheme based on an equation of state (EOS) to calculate CO2-brine interaction. The geomechanical module used in this study is based on Hierarchical Single Surface (HISS) model that captures strain softening and hardening, and therefore post-yield plastic deformations related to fault reactivation. The compositional numerical scheme based on EOS calculates the amount of CO2 solubilization in brine as well as the density and viscosity of the CO2- and aqueous-rich phase. In this approach, the flow properties, i.e. permeability and porosity, dynamically change in response to geomechanical effects. The dynamic change was captured through a volumetric strain-permeability law. Our simulation results show that the model is capable of capturing short-term evolution of fault reactivation and the resulting change of permeability along the fault. The dynamic changes of fault properties control the extent of fault reactivation, the pressure relief during injection, and the fault sealing capacity.

Wellbore integrity is a critical subject in oil and gas production, and CO2 storage. Successful subsurface deposition of various fluids, such as CO2, depends on the integrity of the storage site. In a storage site, injection wells and pre-existing wells might leak due to over-pressurization, mechanical/chemical degradation, and/or a poor cement job, thus reducing the sealing capacity of the site. Wells that leak due to microannuli or cement fractures on the order of microns are difficult to seal with typical workover techniques. We tested a novel polymer gelant, originally developed for near borehole isolation, in a pilot experiment at Mont Terri, Switzerland to evaluate its performance in the aforementioned scenario.The polymer gel sealant was injected to seal a leaky wellbore drilled in the Opalinus Clay as a pilot test. The success of the pH-triggered polymer gel (sealant) in sealing cement fractures was previously demonstrated in laboratory coreflood experiments (Ho et al. 2016, Tavassoli et al. 2018). pH-sensitive microgels viscosify upon neutralization in contact with alkaline cement to become highly swollen gels with substantial yield stress that can block fluid flow. The leaky wellbore setup was prepared by heating-cooling cycles to induce leakage pathways in the cased and cemented wellbore. The leakage pathways are a combination of fractures in the cement and microannuli at the cement-formation interface. The exact nature of these leakage pathways can be determined by over-coring at the end of the experiment life. We used polyacrylic acid polymer (sealant) to seal these intervals. The process comprises of three stages: (1) injection of a chelating agent as the preflush to ensure a favorable environment for the polymer gel, (2) injection of polymer solution, and (3) shut-in for the polymer gelation. Then, we evaluated the short-/long-term performance of the sealant in withholding the injected fluids (formation brine and CO2 gas).The novel sealant was successfully deployed to seal the small aperture pathways of the borehole at the pilot test. We conducted performance tests using formation brine and CO2 gas to put differential pressure on the polymer gel seal. Pressure and flow rate at the specific interval were monitored during and after injection of brine and CO2. Results of performance tests after polymer injection were compared against those in the absence of the sealant.Several short-term (4 min) constant-pressure tests at different pressure levels were performed using formation brine, and no significant injection flow rate (rates were below 0.3 ml/min) was observed. The result shows more than a ten-fold drop in the injection rate compared to the case without the sealant. The polymer gel showed compressible behavior at the beginning of the short-term performance tests. Our long-term (1-week) test shows even less injectivity (~0.15 ml/min) after polymer gelation. The CO2 performance test shows only 3 bar pressure dissipation overnight after injection compared to abrupt loss of CO2 pressure in the absence of polymer gel. Sealant shows good performance even in the presence of CO2 gas with high diffusivity and acidity.Pilot test of our novel sealant proves its competency to mitigate wellbore leakage through fractured cement or debonded microannuli, where other remedy techniques are seldom effective. The effectiveness of the sealing process was successfully tested in the high-alkaline wellbore environment of formation brine in contact with cement. The results to date are encouraging and will be further analyzed once over-coring of the wellbore containing the cemented annulus occurs. The results are useful to understand the complexities of cement/wellbore interface and adjust the sealant/process to sustain the dynamic geochemical environment of the wellbore.

Experimental data in numerous publications show that viscoelastic polymers can significantly reduce residual oil saturation under favorable conditions. The effect of viscoelasticity is in addition to improved sweep efficiency of polymer flooding. The residual oil saturation decreases with increasing dimensionless Deborah number (a measure of the relative elasticity). We used these extensive coreflood data to develop a new model that is referred to here as an Elastic Desaturation Curve (EDC). The new EDC model was implemented into a reservoir simulator and used to simulate polymer floods at both the lab and field scales. The simulated coreflood results match the experimental oil cut, oil recovery and pressure drop data. The simulator was then used to predict the effectiveness of polymer floods in a quarter five-spot well pattern under favorable field conditions. The field-scale simulations show that a viscoelastic polymer flood can recover significantly more oil (12% OOIP for the base case simulation) compared to an inelastic polymer flood of the same polymer viscosity. A sensitivity analysis shows that polymer concentration, salinity, well spacing, permeability, heterogeneity and injection rate affect the incremental oil recovery due to elasticity. The results suggest that the use of viscoelastic polymers could be a beneficial enhanced oil recovery strategy at the field scale under favorable conditions.

The reduction of pore pressure caused by depletion can induce significant reservoir compaction, especially in unconsolidated reservoirs. Experiments using unconsolidated core samples are often sparse and costly. We develop a numerical approach based on computer-based simulations of rock samples and mechanical tests. The numerical sample consists of crushable grains simulated with the discrete element method (DEM) and the bonded-particle model (BPM). Model parameters are calibrated through numerical single-grain-crushing tests which reproduce the experimentally-measured sand strength. Grain crushing induced by the uniaxial strain stress path results in a pronounced reduction of porosity and permeability, which manifests more readily for samples with large grain size. The change of particle size distribution indicates that the high effective stress causes grain crushing and produces a significant amount of fines. We perform numerical uniaxial strain tests on numerical samples comprising stiff and soft mineral grains. Simulation results indicate that the presence of soft grains and inclusions (e.g. shale fragments) facilitates the grain crushing. Reservoir simulations, incorporating the change of porosity and permeability as a compaction table, show that the upscaled compaction can enhance production due to compaction drive but also reduces production rate by impairing the reservoir permeability. This multiscale numerical workflow bridges particle-scale compaction behavior and field-scale reservoir production. In this paper, (a) DEM simulations provide a useful tool to investigate compaction effects and complement laboratory experiments; (b) the multi-scale numerical approach can predict the depletion-induced evolution of reservoir production.

Recent research indicates that even small viscous transverse pressure gradients can increase the rate of surfactant imbibition into the matrix of a fractured reservoir. However, surfactants are commonly tested using static imbibition cells without any imposed pressure gradient. Therefore, the effect of viscous pressure gradients was investigated by conducting a series of surfactant corefloods using fractured Silurian Dolomite and Texas Cream Limestone cores. The viscosity of the surfactant solution was increased by adding polymer or by changing the salinity of the aqueous surfactant solution, which affects the in-situ microemulsion viscosity. The fractured cores had a permeability contrast between the fracture and the matrix ranging from 2500 to 90,000. Non-fractured corefloods were also performed and compared with the fractured corefloods. The more viscous surfactant solutions achieved greater oil recovery from the fractured carbonate cores. These results indicate that a viscous microemulsion can serve as a mobility control agent in naturally fractured reservoirs (NFRs) that is analogous to mobility control with foams and polymers, but with less complexity and cost.

Water-based polymers are often used to improve oil recovery by increasing displacement sweep efficiency. However, recent laboratory and field work has suggested these polymers, which are often viscoelastic, may also reduce residual oil saturation. The objective of this work is to investigate the effect of viscoelastic polymers on residual oil saturation in Bentheimer sandstones and identify conditions and mechanisms for the improved recovery. Bentheimer sandstones were saturated with a heavy oil (120cp) and then waterflooded to residual oil saturation using brine followed by an inelastic Newtonian fluid (diluted glycerin). These floods were followed by injection of a viscoelastic polymer, hydrolyzed polyacrylamide (HPAM). Significant reduction in residual oil was observed for all core floods performed at constant pressure drop when the polymer had significant elasticity (determined by the dimensionless Deborah number, NDe). An average residual oil reduction of 5% OOIP was found during HPAM polymer floods for NDe of 0.6 to 25. HPAM floods with very low elasticity (NDe25). All experiments at constant pressure drop indicate polymer viscoelasticity reduces the residual oil saturation. Results from CT scans further support these observations. A correlation between Deborah number and residual oil saturation is also presented.

Miscible gas injection is proposed here for improved oil recovery in unconventional, oil-rich shale reservoirs. The ultra-low permeability of shale makes injection from well to well difficult; thus it is proposed that gas is injected into a hydraulic fracture along a horizontal well and production occurs from an adjacent fracture, intersecting the same well. Compositional reservoir modeling was performed to investigate the effectiveness of the proposed gas injection scheme. The computational domain consists of two hydrofrac half-stages along a horizontal well to capture detailed information of the fluid flow near the well bore. The results show 15.7% OOIP incremental recovery for the base model with matrix permeability kmatrix = 10 μD over 5000 days (nearly 14 years) of CO2 injection, and 12.5% OOIP for the one with kmatrix = 1 μD, indicating that the gas injection scheme has the potential to vastly improve oil recovery in oil-rich shale formations. The effects of reservoir properties and injection conditions on oil recovery were investigated by changing the injection pressure, reservoir heterogeneity, hydrofrac spacing, dispersion, and compositions of the injection gas. Increasing injection pressure leads to higher production before breakthrough and faster recovery of the oil in the stimulated region. Reducing the hydrofrac spacing has similar effect, although the production declines more rapidly after breakthrough. Introducing heterogeneity to the reservoir results in lower recovery, but the effect of spatial continuity (correlation length) on recovery is insignificant. It was also found that dispersion is mainly dominated by diffusion and mechanical dispersion is less important in most cases. Injection of hydrocarbon gas outperforms CO2, especially if the economics is also taken into account.

Multi-stage hydraulic fracturing together with horizontal drilling plays an important role in the economic development of unconventional reservoirs. However, according to field analysis of stimulation effectiveness, only a small percentage of perforation clusters contribute to most of the well production. One reason for this low effectiveness is that multiple fractures do not take the same amount of fluid and proppant due to fracture interaction (i.e., stress shadow effects). Unfortunately, how best to minimize the negative effects of stress shadowing is still poorly understood in the petroleum industry. In this paper, we analyzed this problem in order to promote more uniform fracture growth using our complex hydraulic fracture development model. We employed our fracture propagation model that couples rock deformation and fluid flow in the fracture and horizontal wellbore. Partitioning of flow rate between multiple fractures was calculated by analogizing to the electric circuit network. Fracture development is dominated by flow rate distribution, which is controlled by flow resistance within the fractures. For simultaneous multiple fracture propagation, non-uniform flow rate distribution is induced because stress shadow effects exert additional flow resistance on the interior fractures. To balance the extra resistance introduced by the effects, we investigated two adjustment approaches to promote uniform fracture development. The first approach was to adjust perforation number or diameter to increase flow resistance entering the exterior fractures. The second was to mitigate stress shadow effects through managing non-uniform fracture spacing. We found that decreasing perforation diameter or numbers of the exterior fractures can divert fluid into the interior fractures and promote even fracture growth. Stress shadow effects can be mitigated by moving the two interior fractures away from each other and toward the exterior fractures. The key mechanism is to maintain even flow resistance within each fracture and facilitate fractures to obtain the same amount of injection fluid. Furthermore, flow resistance is affected by near-wellbore fracture tortuosity, natural fractures, and stress heterogeneity in the reservoirs. These factors might also be effectively controlled by adding extra flow resistance to pass perforations, provided that this extra resistance is larger than the extra resistance introduced by the factors. This work analyzes the problem of uneven development of multiple fractures along the horizontal wellbore and provides new insights into how to control simultaneous multiple fracture propagation. It offers potential approaches for engineers to apply in the field to optimize hydraulic fracturing treatment design and thereby maximize well production cost-effectively.

Understanding the flow behavior of viscoelastic fluids in porous media is critical for optimizing enhanced oil recovery (EOR). Polymers such as hydroxypolyacrylamide (HPAM) are used to improve sweep efficiency in reservoirs and these polymers often exhibit elasticity. Surprisingly, recent experimental and field observations indicate that these viscoelastic polymers improve oil recovery up to an additional 20%, contrary to the conventional wisdom that polymers should have no impact on residual oil saturation. Here, we attaempt to understand effects of viscoelasticity on residual saturation in water-wet and mixed-wet porous media. Static and dynamic computational fluid dynamics (CFD) simulations of oil droplets in the presence of viscoelastic polymer are conducted in geometries representative of pore throats. Results show that additional forces on the oil droplet are present for fluids that exhibit elasticity over those that do not (e.g. water) and those forces become larger as the oil droplet approaches a constriction. It is also shown using dynamic simulations that the amount of deformation of the oil droplet is greatly affected by the elasticity of the displacing fluid. These results are promising and provide a theoretical foundation for the laboratory and field observations of reduced residual oil.

An equation-of-state based compositional reservoir simulator, UT-COMP, is used to simulate the improved oil recovery by CO2 huff-n-puff in a shale matrix typical of the Bakken Formation. Non-aqueous components are carefully lumped into seven pseudo components. Permeability fields with various heterogeneity and correlation lengths are generated. UT-COMP is able to solve the compositional model, despite the permeability difference between the fracture and matrix being six orders of magnitude. Multiple cycles of CO2 huff-n-puff are simulated and compared with production by primary depressurization. The oil is first contact miscible with the injected CO2 under the reservoir pressure. Simulations show that primary recovery outperforms CO2 huff-n-puff in an ideally homogenous reservoir because injected CO2 moves deep into the reservoir without much increase in near-well pressure, while CO2 huff-n-puff outperforms primary recovery if there exists a low-permeability region which keeps CO2 in the near-well bore injection region. In the latter case, the final recovery using CO2 huff-n-puff is higher than that from primary depressurization; the recovery in a single cycle is about 3.3%, which increases to 3.5% in about 3 cycles. The recovery factor after 1000 days by primary depressurization with production pressure of 1000 psi is 11.6%, which is in agreement with existing studies. The recovery increase can be fit by a two-parameter exponential function and the rate coefficient is found to be insensitive to correlation length, while depends mainly on reservoir heterogeneity. A linear relationship between heterogeneity and rate coefficient is obtained. This work is the first to investigate the effect of heterogeneity on improved hydrocarbon recovery by CO2 huff-n-puff, and will be valuable in understanding the coupling between shale properties and oil recovery.

Non-Darcy flow is often observed near wells and in hydraulic fractures where relatively high velocities occur. In these regions an empirical model, Forchheimer's equation, is used in place of Darcy's law. It includes a quadratic correction to the linear model and has been adequately fit to many experimental data sets, while found to be insufficient in others. Furthermore, a number of numerical and theoretical approaches have shown limitations of the Forchheimer model in the laminar flow regime. It is important to understand the applicability of Forchheimer's equation and to be able to obtain good predictions of macroscopic properties so that nonlinear flow may be properly modeled in reservoir simulators. In this work non-Darcy flow is modeled using a physically-representative1 pore-scale network model. Quantitative and predictive results are obtained using both computer-generated porous media and real sandstones digitized through x-ray computed microtomography (XMT). The permeability and non-Darcy coefficient, β, are determined for these isotropic and anisotropic media where Forchheimer's equation is applicable. The numerical model is compared to existing experimental data and good agreement is found. Furthermore, limitations to Forchheimer's equation at both low and high velocities are determined and discussed.

Proppant-packed fractures provide a relatively low-resistance pathway for the recovery of reservoir fluids. However, residual polymer left over from the proppant transport can greatly reduce the fracture conductivity and, therefore, productivity. Poor fracture cleanup is often observed and it is important to understand the fundamental reasons behind the phenomenon. It is believed that non-Newtonian fluid rheology, viscous fingering, and leak off may all contribute to the problem. The vast majority of fracture cleanup modeling has been limited to continuum-scale modeling. However, important aspects of the cleanup problem may be affected by pore-scale events. For this reason, it is desired to model flow at the pore-scale to obtain a better understanding of the qualitative fingering patterns and quantitative flowrates in a fracture during the cleanup process, as a function of basic parameters such as proppant size, fluid rheology, and imposed pressure gradients. These pore-scale results may help explain the fundamental reasons for the observed poor polymer cleanup and give insight on how to improve cleanup in the future. In this work, computer-generated, random sphere-packs are used to approximate a small portion of the propped fracture. The sphere-packs are transformed into physically representative networks of pores and connecting throats. The network models are used to model flow through the proppant pack at the pore-scale. Modeling the dynamic cleanup process consists simulating a low-viscosity, Newtonian fluid (e.g. water) displacing a high-viscosity, non-Newtonian polymer from the pack. A novel approach is used to couple the network to a continuum model for flow in the reservoir, and realistic boundary conditions are used that allow the displacing fluid to flow in from the side of the fracture. Current modeling is used to better understand displacement behavior under different conditions. Future results will be upscaled and integrated with large-scale reservoir models.

The retention of fracturing fluid in a proppant pack reduces the dimensionless fracture conductivity, Fcd, resulting in poor well productivity regardless of fluid type (gelled oil, crosslinked polymers, viscoelastic surfactants, or foams). Analytical expressions derived in this paper can be used to calculate the extent of fracture clean up, n* under a set of production conditions. Dimensionless parameters, β (reservoir: fracture mobility ratio), R (clean: fouled fracture permeability ratio), and τ0 (dimensionless fluid yield stress), which affect n* are identified in the model. A second fracture cleanup model is also proposed and is used to estimate the dimensionless parameter values. Fluid removal is a balance between the differential pressure within the fracture facilitating cleanup and the fluid yield stress resisting cleanup. The driving force for fracture cleanup weakens as fluid is removed, until an equilibrium cleanup extent, n*, is reached. The equilibrium model predicts that n* increases greatly with decreasing dimensionless yield stress, τo. The magnitude of η* is also greater for high clean: fouled permeability ratios, R. η* is expected to increase with an increase in the reservoir: fracture mobility ratio, β, until an optimum is reached and then decrease with increasing β. The critical process of parameter estimation is achieved by making experimental measurements and by history matching published fracture flowback data using the transient model. Practical application of this work is aimed at identifying pathways to improved well performance. For example, data from the Codell formation showed that η* was 45%. Parameter values of 0.92, 2.0, and 5.0 for τo, β, and R, respectively were found to fit the transient flowback data. If these parameters are accurate, η*, can be increased to 95% (doubling the expected production revenue) if a fluid with τo of 0.1 is used and all other parameters remain the same.