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The developmental plasticity of the maize inflorescence depends on meristems, which directly affect reproductive potential and yield. However, the molecular roles of upper floral meristem (UFM) and lower floral meristem (LFM) in inflorescence and kernel development have not been fully elucidated. In this study, we characterized the reversed kernel1 (rk1) novel mutant, which contains kernels with giant embryos but shows normal vegetative growth like the wild type (WT). Total RNA was extracted from the inflorescence at three stages for transcriptomic analysis. A total of 250.16-Gb clean reads were generated, and 26,248 unigenes were assembled and annotated. Gene ontology analyses of differentially expressed genes (DEGs) detected in the sexual organ formation stage revealed that cell differentiation, organ development, phytohormonal responses and carbohydrate metabolism were enriched. The DEGs associated with the regulation of phytohormone levels and signaling were mainly expressed, including auxin (IAA), jasmonic acid (JA), gibberellins (GA), and abscisic acid (ABA). The transcriptome, hormone evaluation and immunohistochemistry observation revealed that phytohormone homeostasis were affected in rk1. BSA-Seq and transcriptomic analysis also provide candidate genes to regulate UFM and LFM development. These results provide novel insights for understanding the regulatory mechanism of UFM and LFM development in maize and other plants.

Genomic imprinting is a classic epigenetic phenomenon related to the uniparental expression of genes. Imprinting variability exists in seeds and can contribute to observed parent-of-origin effects on seed development. Here, we conducted allelic expression of the embryo and endosperm from four crosses at 11 days after pollination (DAP). First, the F1 progeny of B73(♀) × Mo17(♂) and the inducer line CAU5 were used as parents to obtain reciprocal crosses of BM-C/C-BM. Additionally, the F1 progeny of Mo17(♀) × B73(♂) and CAU5 were used as parents to obtain reciprocal crosses of MB-C/C-MB. In total, 192 and 181 imprinted genes were identified in the BM-C/C-BM and MB-C/C-MB crosses, respectively. Then, by comparing the allelic expression of these imprinted genes in the reciprocal crosses of B73 and CAU5 (BC/CB), fifty-one Mo17-added non-conserved genes were identified as exhibiting imprinting variability. Fifty-one B73-added non-conserved genes were also identified by comparing the allelic expression of imprinted genes identified in BM-C/C-BM, MB-C/C-MB and MC/CM crosses. Specific Gene Ontology (GO) terms were not enriched in B73-added/Mo17-added non-conserved genes. Interestingly, the imprinting status of these genes was less conserved across other species. The cis-element distribution, tissue expression and subcellular location were similar between the B73-added/Mo17-added conserved and B73-added/Mo17-added non-conserved imprinted genes. Finally, genotypic and phenotypic analysis of one non-conserved gene showed that the mutation and overexpression of this gene may affect embryo and kernel size, which indicates that these non-conserved genes may also play an important role in kernel development. The findings of this study will be helpful for elucidating the imprinting mechanism of genes involved in maize kernel development.

Maize (Zea mays) is a monoecious plant, in which inflorescence morphogenesis involves complicated molecular regulatory mechanisms. Although many related genes have been cloned, our understanding of the molecular mechanism underlying maize inflorescence development remains limited. Here, we identified a maize semi-dominant mutant Silky3 (Si3), which displays pleiotropic defects during inflorescence development, including loss of determinacy and identity in meristems and floral organs, as well as the sexual transformation of tassel florets. We cloned the si3 gene using a map-based approach. Functional analysis reveals that SI3 is a nuclear protein and may act as a transcriptional regulator. Transcriptome analysis reveals that the ectopic expression of si3 strongly represses multiple biological processes, especially the flower development pathways. RNA in situ hybridization similarly shows that the expression patterns of genes responsible for flower development are changed in the Si3 mutant. In addition, the homeostasis of jasmonic acid and gibberellic acid are altered in the Si3 young tassels, and application of exogenous jasmonic acid can rescue the sex reversal phenotype of Si3 The defects we characterized in various regulatory pathways can explain the complex phenotypes of Si3 mutant, and this study deepens our knowledge of maize inflorescence development.

Most chemical EOR formulations are surfactant mixtures, but these mixtures are usually modeled as a single pseudo-component in reservoir simulators. However, the composition of an injected surfactant mixture changes as it flows through a reservoir. For example, as the mixture is diluted, the CMC changes, which changes both the adsorption of each surfactant component and the microemulsion phase behavior. Modeling the physical chemistry of surfactant mixtures in a reservoir simulator was found to be more significant than anticipated and is needed to make accurate reservoir-scale predictions of both chemical floods and the use of surfactants to stimulate shale wells.

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Heterosis or hybrid vigor refers to the superior phenotypic traits of hybrids relative to their parental inbred lines. An imbalance between the expression levels of two parental alleles in the F1 hybrid has been suggested as a mechanism of heterosis. Here, based on genome-wide allele-specific expression analysis using RNA sequencing technology, 1689 genes exhibiting genotype-dependent allele-specific expression (genotype-dependent ASEGs) were identified in the embryos, and 1390 genotype-dependent ASEGs in the endosperm, of three maize F1 hybrids. Of these ASEGs, most were consistent in different tissues from one hybrid cross, but nearly 50% showed allele-specific expression from some genotypes but not others. These genotype-dependent ASEGs were mostly enriched in metabolic pathways of substances and energy, including the tricarboxylic acid cycle, aerobic respiration, and energy derivation by oxidation of organic compounds and ADP binding. Mutation and overexpression of one ASEG affected kernel size, which indicates that these genotype-dependent ASEGs may make important contributions to kernel development. Finally, the allele-specific methylation pattern on genotype-dependent ASEGs indicated that DNA methylation plays a potential role in the regulation of allelic expression for some ASEGs. In this study, a detailed analysis of genotype-dependent ASEGs in the embryo and endosperm of three different maize F1 hybrids will provide an index of genes for future research on the genetic and molecular mechanism of heterosis.

CD40 agonistic antibody is emerging as a front-line immunotherapy for patients with cancer. However, despite its remarkable curative effects, serious immune-related adverse reactions limit the clinical application of CD40 agonists. Crosslinking-dependent activation is one of the promising approaches to diminish the adverse effects of CD40 agonists. Agonistic CD40 stimulation on antigen presenting cells (APCs) not only promotes activation of T cells, but also results in PD-L1 upregulation on APCs, thus creating a negative feedback loop to dampen the anti-tumor immune response. Therefore, we hypothesized that the combination of CD40 agonist and blockade of PD-1/PD-L1 interaction may further induce a synergistic effect on T cell activation and anti-tumor activity. Here, we report a novel PD-L1xCD40 Bispecific Antibody (BsAb) designed to have synergistic curative effects as well as improved safety profiles. The PD-L1/CD40 BsAb was generated using the Harbour HBICE࣪® platform. It exhibited superior binding activities to both PD-L1 and CD40, respectively. CD40 activation was fully relied on the PD-L1 crosslinking. The PD-L1xCD40 BsAb showed potent tumor growth inhibition in preclinical efficacy models. Meanwhile, it showed much improved safety profile compared to a reference anti-CD40 agonistic antibody in the preclinical tox models. Overall, the PD-L1xCD40 BsAb demonstrated remarkable in vivo anti-tumor efficacy and improved safety profiles in preclinical models, which presents it as a promising candidate for the development of next-generation cancer immune therapeutics. Citation Format: Haishan luo, Zihong Meng, Jimmy Rong, Yuandong Wang, Yunxing Yang, Fei Chen, Youhong Wang, Victor Chen, Gang Deng, Yebo He, Xin Gan, Yiping Rong. Development of a novel PD-L1xCD40 bispecific antibody with excellent efficacy and safety profile for cancer therapy [abstract]. In: Proceedings of the American Association for Cancer Research Annual Meeting 2022; 2022 Apr 8-13. Philadelphia (PA): AACR; Cancer Res 2022;82(12_Suppl):Abstract nr 5559.

This paper presents a new three-phase relative permeability model for use in chemical flooding simulators. Numerical simulation test cases are presented to illustrate the continuity of the new relative permeability model. Comparisons are made with a three-phase relative permeability model that has been widely used in chemical flooding simulators for decades. These comparisons show the old model has numerical discontinuities that are not physical in nature and that can lead to oscillations in the numerical simulations. The proposed model is simpler, has fewer parameters and requires less experimental data to determine the relative permeability parameters compared to the original model. Simulations using the new model showed excellent agreement with ASP coreflood data.

Unstable displacement and the resulting viscous fingers remain a challenge for reservoir simulation as practical gridblock sizes are usually much larger than the viscous finger wavelength. Traditional reservoir simulators do not consider sub-grid viscous fingering effects and tend to overestimate the oil recovery at the field scale. Several previous studies suggested that fingering can be ignored at the field scale because channeling (caused by heterogeneity) is dominant, but they missed the existence of viscous fingering at the small scale, which affects the displacement efficiency. In our work, we consider that fingering and channeling coexist in the field across different scales, based on the fact that the heterogeneity increases with the scale. At the small-scale (e.g., lab-scale) where heterogeneity is small, fingering is dominant and causes oil bypassing. An effective-fingering model was developed to scale up fingering effects. The model divides each gridblock into three dynamic regions: two-phase flow, oil single-phase flow, and bypassed-oil regions. Model parameters represent the maximum fraction of viscous fingering and the growth factors of different regions, and they are used to modify flow functions. Model parameters from history-matches of a set of laboratory experiments show clear power-law correlations with a dimensionless viscous finger number, a function of viscosity ratio, fluid velocity, permeability, interfacial tension, and core cross-sectional area. The correlation was achieved at the lab-scale by considering relatively homogeneous cores. We extended it further to the field scale by performing high-order spatially accurate numerical simulations at the intermediate scale using gridblock sizes that are roughly the same as that of the core. Geostatistical realizations of the permeability field were generated with various variances and correlation lengths. In a statistical way, we were able to quantify the viscous finger number for a gridblock at the field-scale affected by various heterogeneities. It is also observed that channelized permeability distributions increase the viscous finger number drastically, showing the important role of channeling in such cases. This new model was applied to a synthetic field case with high heterogeneity undergoing water/polymer floods. It is observed that the oil recovery was improved by the polymer slug because of the enhancement in both local displacement efficiency and sweep efficiency.

Gene imprinting is a widely observed epigenetic phenomenon in maize endosperm; however, whether it also occurs in the maize embryo remains controversial. Here, we used high-throughput RNA sequencing on laser capture microdissected and manually dissected maize embryos from reciprocal crosses between inbred lines B73 and Mo17 at six time points (3-13 days after pollination, DAP) to analyze allelic gene expression patterns. Co-expression analysis revealed sequential gene activation during maize embryo development. Gene imprinting was observed in maize embryos, and a greater number of imprinted genes were identified at early embryo stages. Sixty-four strongly imprinted genes were identified (at the threshold of 9:1) on manually dissected embryos 5-13 DAP (more imprinted genes at 5 DAP). Forty-one strongly imprinted genes were identified from laser capture microdissected embryos at 3 and 5 DAP (more imprinted genes at 3 DAP). Furthermore, of the 56 genes that were completely imprinted (at the threshold of 99:1), 36 were not previously identified as imprinted genes in endosperm or embryos. In situ hybridization demonstrated that most of the imprinted genes were expressed abundantly in maize embryonic tissue. Our results shed lights on early maize embryo development and provide evidence to support that gene imprinting occurs in maize embryos.

In a conventional reservoir simulation, analytical well models relate well block pressure, wellbore pressure, fluid mobility, and geometric factors such as wellbore radius and grid size. Basically, fluid viscosity is assumed to be Newtonian in these models. Commercial reservoir simulators using these well models often predict unrealistic well injectivity in simulation of processes involving non-Newtonian fluids such as polymer solutions. Apparent viscosity of a polymer solution is a complicated function of flow velocity, polymer properties, permeability, porosity, salinity, etc. As the distance away from an injection well increases, flow velocity decreases; meanwhile, the apparent polymer viscosity changes drastically. For shear-thinning polymers, the average flow velocity in a well block is several orders of magnitude smaller than the flow velocity near the wellbore, especially when grid size is large. Using the average flow velocity for apparent viscosity calculation leads to an underestimate of well injectivity. Thus it is crucial to consider non-Newtonian effects in simulation of injectivity of polymer solutions. UTCHEM, a general purpose chemical flooding simulator developed at the University of Texas, uses a semi-analytical polymer injectivity model based on an extension of Peaceman's well model to non-Newtonian fluids. This model corrects the apparent viscosity in well index calculation and gives a more realistic estimate of polymer injectivity. However, the model needs to be programmed and implemented in a code. It is not practical for users of commercial simulators which do not have semi-analytical polymer injectivity model. Compared with UTCHEM, CMG-STARS, the thermal and advanced processes reservoir simulator developed by Computer Modeling Group, uses an apparent skin factor to account for non-Newtonian effects of power law fluids. The apparent skin factor can be used as an input parameter to the simulator. In this study, we revisited the analytical polymer injectivity model and proposed a general form for the calculation of apparent skin factor. The apparent skin factor is estimated using polymer rheological properties, grid size, wellbore radius, etc., and can apply to any polymer rheology. Simulation studies of polymer flooding cases were conducted to verify the concept of apparent skin factor. The results show that for shear-thinning polymers, the apparent skin factor can be estimated properly and correct the analytical well model to give close predictions compared to the semi-analytical polymer injectivity model and fine-grid simulation. The concept of apparent skin factor was proved to be useful for improving the accuracy of well injectivity calculations by commercial simulators. However, it is also worth pointing out that the apparent skin factor cannot be used for polymers which show shear-thickening behavior at high shear rates for cases of heterogeneous reservoir.

Waterflood in a viscous oil reservoir is not very efficient because the water fingers through the oil due to adverse viscosity. Typically, thermal methods are used to recover viscous (and heavy) oil. However, thermal methods can be inefficient when the depth of the reservoir is high and pay thickness is low. Nonthermal chemical enhanced-oil-recovery (EOR) methods are being developed as alternatives. Recently, a new low-cost chemical EOR technology called alkali–cosolvent–polymer (ACP) flooding has been developed which does not use any synthetic surfactant. In viscous oil reservoirs, the oil recovery in the first 30 years is more important than the ultimate recovery, which may take many hundreds of years. The purpose of this study is to identify the optimum ACP slug viscosity and the optimum timing for the initiation of the ACP process. ACP formulations that achieve ultralow tension were developed. Since the sweep efficiency is challenging in viscous oil reservoirs, ACP floods were performed in a quarter 5...

Screening optimum formulation for surfactant flooding is usually time consuming, and correctly modeling microemulsion phase behavior is critical for chemical flooding simulation. This paper extends the physics based Hydrophilic Lipophilic Difference (HLD) Net Average Curvature (NAC) model, and comprehensively demonstrated its capabilities in predicting the optimum formulation and microemulsion phase behavior. This paper uses quantitatively characterized HLD parameters, accurately predicted four optimum surfactant formulations for a target reservoir. This paper measured surfactant head area of extended surfactants and further predicted the equilibrium interfacial tension of four phase behavior test. Comparing to the empirical Hand's rule phase behavior model, the HLD-NAC equation of state shows great advantages in helping formulation design and modeling microemulsion phase behavior. Surfactant flooding sandpack laboratory tests are also interpreted by UTCHEM chemical flooding simulator coupled with the HLD-NAC phase behavior model. The results indicate the significance of HLD-NAC equation of state in not only shorten the surfactant screening processes for formulators, but also predicting microemulsion phase behavior based on surfactant structure. A compositional reservoir simulator with such an equation of state will increase its predictability and hence help with the design of surfactant formulation.

Low-Tension Gas (LTG) has emerged as a novel enhanced oil recovery injection strategy, employing foam in place of polymer to displace the oil bank created with the help of ultra-low-IFT (ULIFT). In our prior work, the process was successfully employed, both in sandstones and carbonates, to achieve attractive oil recoveries with relatively low surfactant retention. However, earlier experiments were carried out at high flow rates in relatively high permeability cores. To improve the robustness of this novel injection scheme, it is necessary to examine it under wider practical environments. Therefore, in this work, experiments are conducted in carbonate and sandstone cores, at lower injection rates and rock permeabilities, to determine whether the foam could provide the necessary mobility control with this novel EOR technique. Initially, a lower flow rate (1 ft/D) experiment is conducted in relatively high permeability (388 md) sandstone core to compare it with the earlier results under a higher injection rate (4 ft/D). Subsequently, even further reduced injection rate (0.5 ft/D) is employed in a sandstone core with one order of magnitude lower permeability (36 md). Two other corefloods with Estaillades limestone (166 md) and Richmont (7 md) are carried out to extend the comparison to carbonate rocks. Surfactant retentions are determined. It is found that four-times-lower injection rate (1ft/D) just slightly delayed oil production, and achieved comparably high oil recovery (87%), indicating a good mobility control. Proportionally reduced pressure drop during slug injection implies similar total fluid mobility. Accordingly, salinity propagation examined from effluents shows slight delays. Even with ten-times-lower permeability sandstone (36 md) at a lower total injection rate (0.5 ft/D), comparable oil recovery (84%) and salinity propagation are found, despite of much lower foam strength. With an intermediate-permeability Estaillades limestone (166 md), compared to high permeability sandstone, oil production is delayed, but comparable eventual oil recovery (88%) is obtained. The delay could be due to higher surfactant retention (0.301 mg/g). The delayed effluent salinity propagation is noticeable, which may be caused by increased total fluid mobility. Finally, extremely low permeability Richmont (7 md) indeed adversely impacts the oil recovery (~58%) and the salinity propagation. This could be attributed to higher surfactant retention and/or decreased foam stability due to oil-wet rock surface. The works here test the robustness of the LTG process in more practical reservoir conditions and have widened its applicability. Demonstration of its feasibility in low-permeability reservoirs, where use of polymer is not currently feasible, will greatly promote the testing and deployment of this technology in the future.

Recovering oil from oil-wet matrix in fractured carbonate rocks is highly challenging. Recent experiments have indicated that ultra-low-interfacial-tension (ULIFT) foam flood could significantly boost the oil recovery from such rocks. However, there is limited information available about the foam and the microemulsion transport in the fractured system to extract the oil from low permeability matrix. Adaptation of this technology in the field would not be possible without a good understanding of the process. The aim of this work is to model and history match the ULIFT foam flood in fractured carbonate cores for further gaining insight into the complex four-phase flow. The model was set up based on a group of experiments using cores split lengthwise to simulate axially confined fractures. Pre-generated foam was tested in this system due to the lack of in-situ generation of foam in the straight fracture at the core scale. Various foam coalescence mechanisms, with/without oil, were modeled, and a dynamic-texture population-balance foam model was developed for this purpose. Our model incorporates the effects of oil and permeability as well as the coexistence of foam and microemulsion on the foam apparent viscosity. The model is able to reasonably well history match both the oil recoveries and the total pressure drops of the ULIFT foam floods in fractured carbonate cores. More impressively, the modeling results agree very well with the pressure gradient of each section of the core, indicating that the spatial variation and distribution of the foam texture are largely captured. The simulation results also show that the pre-generated foam greatly resists the fluid flow in the fracture close to the injector side and enhances the diversion of injected fluids into the matrix layers, leading to improved oil displacement. The resulting oil crossflow from the matrix to the fracture destabilizes the foam at the foam front thereby slowing the transportation of foam in the fracture. Additional case studies suggest that significantly more oil can be recovered if the foam destabilization by oil could be reduced/mitigated. Test results disclosed in this paper demonstrate for the first time the successful modeling and history-match of ULIFT foam floods in fractured rocks. Valuable insight into this complex process has been gained through this innovative research. This is of great value with respect to the further optimization of the corefloods, the design of the surfactant formulation, and the feasibility of applying this new technology to the field scale.

The targeted reservoir for foam mobility control is usually layered or heterogeneous. However, a major limitation of existing foam models is that there are no dependencies of the foam modeling parameters on permeability, even though the permeability is accounted inherently only through changes in gas-water capillary pressure and shear rate. This results in considerable errors in predicting the foam mobility at largely varying permeabilities, which prevents users from simulating correctly the conformance achievable with the help of foam in heterogeneous reservoirs. Developing a foam simulator with systematic permeability-dependencies of foam properties is a key enabler for the rigorous simulation of foam floods in the field. An advanced population-balance foam model has been developed with reasonable physical mechanisms associated with the effect of permeability on the bubble density, foam generation and stability in porous media. The derivations indicate that the gas viscosity scaling constant increases with permeability exponentially, while the upper limit of foam texture, the foam generation coefficient, and the limiting capillary pressure decrease exponentially as the permeability increases. All these factors collectively affect the foam mobility. The upper limit of foam texture and the foam generation coefficient share the same power-law exponent with permeability because of the similar fundament. As a result, three additional power-law exponents are needed to correlate with permeability in the new model. To verify the correlations of the parameters with the permeability change, an automated regression program was applied to fit the resistance factors of several groups of foam flood experiments with foam quality scans at different permeabilities. The newly developed permeability-dependency functions showed its great competency in matching all the experimental data in a wide range of permeability. The optimized parameters are largely consistent with the theoretical exponents of the power-law functions of the aforementioned physical properties correlated to permeability, but also suggest extra modifications. In particular, the exponent for the limiting capillary pressure is about -0.5, which is equivalent to that the limiting water saturation is approximately independent of the permeability according to the Leverett J-function. As a result, the new functions of permeability dependencies for the foam-model parameters in the population-balance model enables the foam modeling with only a single input of foam parameters at a referenced permeability. A 2D layered reservoir case was used to test the new permeability functions, which shows the significant difference in terms of the oil recovery and the injector BHP between whether considering the permeability effect or not. This paper proposed, for the first time, a systematic methodology to account for the critical permeability effect to simulate foam flooding in heterogeneous reservoirs. This is a key advance in consideration of the major limitation of existing reservoir simulators using fixed or ad-hoc foam-model parameters throughout the entire reservoir. This new model enables the reservoir engineers to simulate and optimize the foam performance in real fields with better accuracy of foam physics in porous media.

Summary The upscaling of unstable immiscible flow remains an unsolved challenge for the oil industry. The absence of a reliable upscaling approach hinders effective reservoir simulation and optimization of heavy-oil recoveries by use of waterflood, polymer flood, and other chemical floods, which are inherently unstable processes. The difficulty in scaling up unstable flow lies in estimating the propagation of fingers smaller than the gridblock size. Using classical relative permeabilities obtained from stable flow analysis can lead to incorrect oil recovery and pressure drop in reservoir simulations. Extensive experimental data in water-wet cores indicate that the heavy-oil recovery by waterfloods and polymer floods has a power-law correlation with a dimensionless number (named “viscous-finger number” in this paper), a combination of viscosity ratio, capillary number, permeability, and the cross-sectional area of the core. On the basis of the features of unstable immiscible floods, an effective-fingering model is developed in this paper. A porous-medium domain is dynamically identified as three effective regions, which are two-phase flow, oil single-phase flow, and bypassed-oil region, respectively. Flow functions are derived according to effective flows in these regions. Model parameters represent viscous-fingering strength and growth rates. The new model is capable of history matching a set of heavy-oil waterflood corefloods under different conditions. Model parameters obtained from the history match also have power-law correlations with the viscous-finger number. This model is applicable to water-wet reservoirs; it has not been tested for mixed-wet and oil-wet systems, low-interfacial-tension (IFT) environments, low permeability, and heavy-oil reservoirs with free gas cap. In reservoir simulations, having such a correlation enables the estimation of model parameters in any gridblock of the reservoir by knowing the local viscous-finger number. The model was first applied to a heavy-oil field case with channelized permeability by waterfloods. Simulation results with the new model indicated that viscous fingering strengthened the channeling. Also, the new model shows that a lower injection rate leads to a higher oil recovery. In contrast, oil recovery in waterflooding of viscous oils is overpredicted by classical simulation methods that do not incorporate viscous fingering properly. We further showed that coarse-grid simulations with the new model were able to obtain saturation and pressure maps consistent with fine-grid simulations. The new model was then used to model a real field case in the Pelican Lake heavy-oil field. It was able to match the field-production data without major adjustment of reservoir/fluid properties from the literature, showing its competence in capturing subgrid viscous-fingering effects. Overall, the new model shows encouraging capability to simulate unstable water and polymer floods in heavy-oil reservoirs, and hence can facilitate the optimization of heavy-oil enhanced-oil-recovery (EOR) projects.

Injection of viscous polymer solutions can lead to excessive wellbore pressure and dynamic fracture growth near wellbore which hence increases polymer injectivity. Polymer rheology can also play an important role in affecting the fracture growth due to the dramatic variation of fluid velocity. However, current reservoir simulations for chemical flooding generally overlook the induced fracture, which may lead to inaccurate modeling of polymer floods. In this paper, we developed a new polymer-injection-induced fracture model based on the GdK fracture model, and implicitly coupled it to a general-purpose chemical flood simulator. Mathematical description of the fracture mechanics is presented with consideration of different polymer rheology. The new model is used to simulate polymer floods in a five-spot field. The fracture growth predicted by the new model is verified against a semi-analytical numerical fracture model. The simulation results using the new model indicate that the fracture growth has positive effects on improving injectivity, pressure drop, oil recovery, etc. Also, the simulations illustrate for the first time how polymer rheology affects fracture growth during polymer injection, e.g., without consideration of polymer shear-thickening can postpone the prediction of fracture initiation. The simulations successfully explain why polymer can be economically injected in real polymer fields. The new simulator can be used to optimize polymer floods concerning polymer injectivity, impact of fracture growth on sweeping efficiency, flow out of zone, and others.

Summary Gas adsorption, stress dependence, non-Darcy flow, and surface diffusion of the adsorbed layer are significant mechanisms in shale-gas reservoirs. However, the volume occupied by the adsorbed layer is generally overlooked by current industry standards and numerical models. In addition, stress dependence of matrix pores does not draw as much attention as hydraulic fractures, and surface diffusion has not been included in commercial simulators. Moreover, all these effects significantly affect each other, which can lead to additional complexity of gas transport and production. Therefore, development of an integrative model with consideration of these complicated mechanisms is needed. In this paper, we develop such a fully coupled model for shale-gas-reservoir simulations. We present the derivation of models reflecting the time-dependence effects of gas adsorption/desorption upon original gas in place (OGIP) and petrophysical properties. In particular, both the Langmuir and Brunauer, Emmett, and Teller (BET) (Brunauer et al. 1938) isotherms are included by use of a unified formula. Surface diffusion of adsorbed layer is also added to this model on the basis of rigorous derivation. More features, such as non-Darcy flow and stress dependence in matrix, natural fractures, hydraulic fractures, and leakage effect between matrix and natural fractures, are incorporated. After that, we present an implicit numerical algorithm to solve the model. Numerical simulations were performed in both 1D and 3D cases and compared with two sets of experimental data and three sets of production data in Marcellus and Barnett shale-gas fields. The simulations indicated that the new simulator cannot only lead to consistent results with these data, but also gives an accurate estimation of OGIP, which traditional models failed to do. It is noted that the model parameters we used for the simulations were close to the values suggested by the literature, if available. By use of this validated simulator, we demonstrated applications with respect to real shale reservoirs, studied the effects of the model parameters upon the gas transport and production, and achieved a variety of new insights.

Summary The interest in low-salinity-water injection (LSWI) compared with seawater injection or high-salinity-produced-brine injection is increasing in both laboratory and field tests. The single-well chemical-tracer test (SWCTT) is also becoming increasingly popular as an in-situ test to assess the reduction in oil saturation caused by an enhanced-oil-recovery (EOR) process. Hence, accurate modeling of SWCTTs is essential. In this paper, modeling and simulation of the SWCTT of LSWI in a carbonate reservoir is investigated by use of the UTCHEM reservoir simulator, a nonisothermal, 3D, multiphase, multicomponent, chemical compositional simulator developed at the University of Texas at Austin (UTCHEM 2011). Both radial- and Cartesian-grid models are set up for a field-scale pilot by use of measured rock and fluid data of a Middle Eastern reservoir. Tracer reactions and the empirical LSWI model implemented in UTCHEM are used to estimate residual oil saturation (ROS) as a result of LSWI. Two approaches are used to estimate ROS to LSWI, including analytical and numerical methods. Results show that both approaches give consistent values for ROS for homogeneous radial- and Cartesian-grid models. The two approaches were inconsistent for the multilayer radial model, which highlights the necessity of the use of numerical approaches for layered reservoirs. The Cartesian-grid model was used to investigate the effect of heterogeneity on SWCTT results, where a new numerical approach is proposed for estimating ROS. This finding validates the approach used and the implementation of both tracer reactions and the LSWI model in UTCHEM. The proposed approach can now be used to estimate ROS of the SWCTT for reservoirs with different degrees of heterogeneity, which provides a clear insight into reservoir performance before planning multiwell demonstration pilots.

Summary The interest in modeling geochemical reactions has increased significantly for different improved-oil-recovery processes such as alkali/surfactant/polymer (ASP) flood, low-salinity waterflood, and ethylenediaminetetraacetic acid (EDTA) injection as a sacrificial agent in hard brine. Numerical simulation of multiphase flow coupled with geochemical reactions is challenging because of complex and coupled aqueous, aqueous/solid, and aqueous/oleic reactions. These reactions have significant impact upon oil recovery, and hence a robust geochemical simulator is important. UTCHEM (2000) is a chemical-flooding reservoir simulator with geochemical-modeling capability. Nevertheless, one major limitation in the geochemical-reactive engine of UTCHEM is assuming the activities of reactive species is equal to unity. In fact, the activity coefficients are strongly nonlinear functions of the ionic strength of solution. One approach to tackle this deficiency was to couple UTCHEM (flow and transport) with IPhreeqc (a geochemical reactive engine) (Kazemi Nia Korrani et al. 2013). However, the simulator proved to be computationally expensive. Therefore, it is desirable to improve the geochemical- reactive engine within UTCHEM. This paper presents the improvement of the geochemical-reactive engine in UTCHEM including implementing different activity-coefficient models for different reactive species, cation-exchange reactions, and numerical convergence. Certain unknown concentrations are eliminated from the elemental mass-balance equations and the reaction equations to reduce the computational burden. The Jacobian matrix and right-hand side of the linear-system equation in the Newton-Raphson method are updated accordingly in the Newton-Raphson method for performing the batch-reaction calculation. A low-salinity-waterflood case is presented to validate the updated UTCHEM against PHREEQC (Parkhurst and Appelo 1999) and UTCHEM-IPhreeqc. The simulation studies indicated that the updated geochemical simulator succeeds in tackling the inaccuracy concerned in the original UTCHEM. Also, the updated version is more efficient compared with PHREEQC and UTCHEM-IPhreeqc with the same degree of accuracy. The updated geochemical simulator is then applied to model an ASP coreflood in which EDTA is used as a sacrificial agent to chelate calcium and magnesium ions. The experimental data of pH, oil recovery, and pressure drop were successfully history matched with predictions of the effluent concentrations of calcium and magnesium ions. A synthetic 3D ASP pilot case is successfully simulated considering effects of acid equilibrium reaction constant on oil recovery.

The adsorption/desorption effects impact the petro-physical properties of matrix pores during gas depressurizing production, such as effective pore radius, effective porosity, apparent permeability, which will further impact the gas flow regime. In this paper, the dynamic models of effective pore radius and apparent permeability under the action of gas adsorption/desorption are derived. The mathematical model of shale gas flow is established considering the effects of adsorbed gas on apparent properties and gas flow regime. After that, the model is solved and validated using a finite volume method and experimental and field data. Finally, the variations of apparent parameters of matrix pores and gas flow regimes during gas production, and the influences of adsorption on gas production are demonstrated. The results show that the effective pore radius, porosity and apparent permeability increase during gas production; the gas flow regime in stimulated reservoir volume (SRV) changes from slip flow to transition flow; if the impacts of adsorbed gas on gas production is overlooked, both original gas in place (OGIP) and gas production will be significantly overestimated. The cumulative gas production changes slightly as the adsorption layer thickness increases, but the gas recovery factor decreases. Key words: shale gas, adsorption, desorption, matrix pore, apparent properties, flow regime, flow model

Summary In most of transient foam core-flood studies, it is observed that multiple pore volumes of foam injection are needed before reaching the steady-state. The pore volumes needed appear to change with the degree of homogeneity of the porous media, orientation of the core, type of surfactant and the total injected flow rate. This is contrary to the foam-model results, which usually predict reaching the steady-state after approximately a single moveable pore volume of gas injection. It is important to understand whether this is a laboratory artifact due to core scale and/or gravity segregation, or could it also be present at reservoir scale, in order to have the reliable foam rheology predictive tools at reservoir scale. We designed the experimental set-up to investigate the phenomenon. In order to mitigate the gravity segregation in typical sand-pack systems, as well as to study the scale effect, we used slim-tubes of 1-ft and 6-ft length to understand the pore volumes needed to reach steady-state. Silica-sand-packed cylindrical slim tubes with an inner diameter of 0.66 inch were used in the foam flood experiments. Foaming surfactant solution and gas were co-injected into the slim-tube apparatus until a steady state is reached. Transient and steady-state pressure gradient data were recorded to investigate foam flow in the slim tube at a variety of injection conditions. Foam experiments with foot-long and 6-ft long slim tubes were compared in order to understand the effect of system length on foam generation and transport. One of the most important findings in this study is that the 6-ft long slim-tube requires significantly fewer pore volumes to reach a steady state than foot-long one under the same foam injection scheme. The analysis of our results revealed several key factors that played important roles in triggering foam generation in the slim tube. We found that the vertical configuration with gas and surfactant solution co-injected from the bottom significantly promoted foam generation in a relatively homogeneous system compared with the horizontal configuration. Foam generation in the slim tube was also facilitated by wider sand grain-size distribution in our tests possibly due to more favorable pore throat-to-body ratios for the snap-off mechanism. Additionally, higher injection velocity helped triggering foam generation in the slim tube. The results obtained in this study can be therefore used not only for improving fundamental knowledge of foam transport but also for upscaling foam models.

Summary Unlike conventional foams made of nitrogen or methane, CO2 emulsion exhibits more complex behaviors in porous media. For instance, CO2 emulsions are relatively weak and do not exhibit sudden loss of apparent viscosity at very high foam quality. Compared to conventional foams in porous media that capillary suction is the main mechanism of bubble coalescence, gas diffusion is significantly enhanced in CO2 emulsion, but the relative contribution of the two emulsion destruction mechanisms and how to account for gas diffusion are rarely seen in the literature. To better understand the key underlying mechanisms, a comprehensive investigation of the CO2 emulsion stability is carried out and bubble coalescence due to gas diffusion is introduced in a population-balance model. First, analytical models are set-up to evaluate the characteristic times of capillary suction and gas diffusion under the same conditions. The analytical solutions suggest that the characteristic time of gas diffusion is comparable to that of capillary suction for CO2 emulsion, while it is one to two orders longer in case of N2 foam. Based on these analyses, a foam/emulsion model is developed through incorporating an additional gas diffusion term as a function of gas solubility, diffusivity, capillary pressure, temperature and several other variables. The new foam/emulsion model is used to fit a set of experiments of CO2 and N2 foams ranging among different foam qualities in the same core. The fittings were carried out using three different selections of the coalescence terms, i.e., the capillary suction term only, the gas diffusion term only, and both terms, for N2 foam and CO2 foam. The results reveal that using the original coalescence model (only capillary suction) can fit the N2 foam data but leads to mismatch with the CO2 data, while using the gas diffusion term only leads to mismatch with the N2 foam data but better match with the CO2 foam data. Using both terms was found optimum for the CO2 emulsion model. In addition, having the gas diffusion term enables to capture the gradual change of the foam strength with foam quality for CO2 foam instead of the abrupt change of foam strength for N2 foam near the limiting capillary pressure. Our research on this subject has unveiled the fact that gas diffusion is important for CO2 emulsion instability. This methodology is a key to evaluate the feasibility of improving CO2 EOR through foaming and to optimize such a process.

Summary Evaluation of modeling techniques for foam flow through porous media requires reliable laboratory measurements. Previously, a set of experimental data points have been collected in steady-state foam flood. Significant efforts have been made to mitigate foam hysteresis and to ensure experimental repeatability in each run by properly restoring the system. In this work, we have investigated the steady-state behavior of the Chen et al population-balance foam model in porous media. The classic Nelder-Mead search algorithm is used to estimate the foam-model parameters from the abovementioned experimental data with a variety of total fluid velocities and foam qualities. Our results show that this foam model does not correctly model the high-quality foam regime as the limiting capillary pressure is not reached. Further analysis reveals that, depending on the initial guesses, two different steady-state saturations at the same foam quality can be obtained. We have identified that the quadratic formula in the foam coalescence equation is the source of the issue, with which the same foam coalescence rate results in two saturation values. Therefore, we have resolved the problem with significantly reduced bubble density when the capillary pressure exceeds the limiting value. The improvement in this model results in physically meaningful fit to the steady-state data with a unique solution. Additionally, sensitivity studies of the parameters indicate that the trapped gas function could be combined with other parameters in the model based on our steady-state data fit. During this investigation we have discovered that the lack of proper initial guesses frequently causes convergence issues of the Nelder-Mead search algorithm. A new two-step approach is therefore developed with a combination of direct calculation and Nelder-Mead search to estimate the foam-model parameters. The new approach greatly reduces the parameter space explored in the algorithm, thus it significantly improves the computational efficiency and the convenience of probing a suitable set of initial guesses to mitigate convergence issues. For the first time, we have provided methodology with improved multi-variable parameter search and evaluation of hysteresis-free steady-state foam data with a population-balance foam model. The improvement in the model makes it not only correctly simulate the effect of the limiting capillary pressure but also potentially more stable in reservoir simulation practices due to the elimination of non-physical solutions.

Summary Low-Tension Gas (LTG) process has been studied for sandstone reservoirs. In the prior publication ( Nguyen et al. 2015 ), LTG was successfully used to achieve high oil recoveries with the proposed surfactant formulation and injection strategy. Sensitivity to change in optimum salinity was also investigated. However, some questions remained, particularly linked to the sudden drop of effluent salinity and the consequential oil recovery under Type I conditions. In this work, in-depth experimental investigations are carried out to understand the underlying mechanisms. Surfactant flooding without presence of gas is conducted to establish the incremental impact of the microemulsion on oil recovery and pressure drop. Constant salinity core flood experiments were carried out under Winsor Type I conditions at varying capillary numbers to examine the desaturation efficiency. Dynamic foamability tests were carried in the absence of oil to probe the foamability of the developed formula and the contribution of alkyl polyether sulfonate (APS). Effluent salinity when injecting brine only was compared with the case where both brine and gas are co-injected to better understand the role of gas. Further, the importance of foam in the drive was evaluated by conducting LTG without the foaming surfactant in the drive. The dynamic foam tests showed good foamability with the proposed formulation, presence of APS in the surfactant formulation further enhanced the foamability. Surfactant flooding without gas resulted in only 30% remaining oil recovery. Constant salinity coreflood confirmed that the oil recoveries observed under Type I conditions in LTG process indeed can be achieved at the prevailing capillary numbers. The effluent salinity comparison between brine only and brine/gas injections showed significant impact of gas on salinity distribution in the core. Much lower oil recovery was observed and the salinity propagation was delayed when no foaming agent was used in the drive. This implies that foam mobility control is critical for the success of LTG process. It is the first time that in-depth experimental studies were conducted for the LTG process. It improves the interpretation of the findings in prior work, and provides the guidance to the future experimental and theoretical studies.

Modeling foam flow through porous media in the presence of oil is essential for various foam-assisted enhanced oil recovery (EOR) processes. We performed an in-depth literature review of foam-oil interactions and related foam modeling techniques, and demonstrated the feasibility of an improved bubble population-balance model in this paper. We reviewed both theoretical and experimental aspects of foam-oil interactions and identified the key parameters that control the stability of foam lamellae with oil in porous media. Upon reviewing existing modeling methods for foam flow in the presence of oil, we proposed a unified population-balance model that can simulate foam flow both with and without oil in standard finite-difference reservoir simulators. Steady-state foam apparent viscosity as a function of foam quality was used to evaluate the model performance and sensitivity at various oil saturations and fluid velocities. Our literature review suggests that, among various potential foam-oil interaction mechanisms, the pseudo-emulsion-film (gas/aqueous/oil asymmetric film) stability has a major impact on the foam-film stability when oil is present. Based on the pseudo-emulsion-film mechanism, we therefore developed a new foam-coalescence function in the population-balance model using the gas-water capillary pressure (Pcgw) in oil-free cases and the pseudo-emulsion capillary pressure (Pcpf) when oil was present. The respective critical values Pcgw * and Pcpf * can be estimated through disjoining pressure measurements. A smooth transition, from no foam destabilization at zero or substantially low oil saturations to no foam beyond a critical oil saturation, was considered for this purpose. The new model was able to handle the extent of the detrimental effect of oil on foam with one adjustable parameter k-2. This work consolidated various findings of foam-oil interactions based on pseudo-emulsion films in the past through a comprehensive literature survey. We have developed a unified model to simulate foam flow in porous media with and without oil using the mechanistic population-balance approach for the first time. This model can therefore be used in foam EOR simulations both in the oil-bearing zones as well as zones with no oil or residual oil present.

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.

Higher stability of the bulk and dynamic foam with polymer addition to the aqueous phase has been demonstrated experimentally. Recent experiments indicated that the efficacy of polymer enhanced foam (PEF) is dependent on polymer type and surfactant-polymer interaction. However, numerical modeling of PEF flow in porous media has been relatively less well understood due to the additional complexity. In this work, we propose modifications to the population-balance foam model for PEF modeling, and their successful use in matching the experimental results.The population-balance model proposed by Chen and co-workers has been used as development platform. Upon reviewing various aspects in the physics of foam generation, coalescence and mobility reduction in porous media with the addition of polymer, a modified population-balance model was proposed with new parameters pertaining to the polymer effect on the net foam generation and the limiting capillary pressure. The new model was implemented and used to history match foam coreflood experiments with and without polymer.In addition to the foam apparent viscosity increase due to higher viscosity of the aqueous phase, polymer also impacts foamability and foam stability of bulk foam as indicated in the literature. Our modified population-balance model introduce the viscosity terms in foam generation and coalescence coefficients to account for postulated positive impact on reducing liquid drainage and foam coalescence and negative impact on the characteristic time needed for bubble snap-off in porous media. Additionally, a modification in the limiting capillary pressure was proposed in the new model to include the polymer effect based on our analysis of the disjoining pressure. Two new model parameters are proposed and implemented accordingly. The new foam model succeeded in history-matching the anionic-surfactant-based and nonionic-surfactant-based PEF corefloods with different types of polymers through tuning the two new model parameters. The simulations also captured the transient increasing of the pressure drops induced by polymer transport and adsorption. The proposed model can be used to provide meaningful values of the model parameters that were able to explain the physical mechanisms behind the PEF floods and to guide future experimental design to further constraint the choices of model parameters.This work provided new methodology to model PEF flow in porous media using the mechanistic population-balance approach for the first time. With proper calibrations of the parameters proposed in the model, the new model can therefore be used to simulate PEF EOR processes to describe the combined effect of foam and polymer on the mobility control of the injectants.

Polymer injectivity is an important factor for evaluating the project economics of chemical flood, which is highly related to the polymer viscosity. Because the flow rate varies rapidly near injectors and significantly changes the polymer viscosity due to the non-Newtonian rheological behavior, the polymer viscosity near the wellbore is difficult to estimate accurately with the practical gridblock size in reservoir simulation. To reduce the impact of polymer rheology upon chemical EOR simulations, we used an efficient multilevel local grid refinement (LGR) method that provides a higher resolution of the flows in the near-wellbore region. An efficient numerical scheme was proposed to accurately solve the pressure equation and concentration equations on the multilevel grid for both homogeneous and heterogeneous reservoir cases. The block list and connections of the multilevel grid are generated via an efficient and extensible algorithm. Field case simulation results indicate that the proposed LGR is consistent with the analytical injectivity model and achieves the closest results to the full grid refinement, which considerably improves the accuracy of solutions compared with the original grid. In addition, the method was validated by comparing it with the LGR module of CMG_STARS. Besides polymer injectivity calculations, the LGR method is applicable for other problems in need of near-wellbore treatment, such as fractures near wells.

Compositional simulation of surfactant flooding highly depends on accurate modeling of surfactant/oil/brine microemulsion phase behavior. This paper introduces a physics-based Hydrophilic–Lipophilic Difference (HLD) equation and the Net-Average Curvature (NAC) called thereafter HLD–NAC equation of state to model the phase behavior of surfactant/crude oil/brine systems. A non-iterative and physics-based algorithm is developed and validated by modeling the solubilization ratio curves and phase volume fraction of different microemulsion systems. The HLD values are calculated by the natural logarithm of salinity over optimum salinity when lacking of oil hydrophobicity and surfactant Characteristic curvature information. Together with lab measured head area of per surfactant molecule, the HLD–NAC model reproduces the microemulsion phase behavior of various formulations for surfactant flooding with only one fitting parameter, the length constant L, which physically represents the surfactant tail length size. Modeling results show that the fitted parameter increases with the surfactant or surfactant mixture tail length in the formulation. Moreover, the length parameter determined from one system can be readily applied to other systems, indicating the physical significance of the HLD–NAC model, which can to some extent predict the performance of one surfactant in various systems. The fitted length parameter for formulations with alcohol is underestimated because of this paper assuming all alcohol partition on the interface leading to overestimated interfacial area. The effect of cosolvent partitioning on the micelle structure and phase behavior modeling will be demonstrated in future studies. In this paper, the HLD–NAC equation of state is proved to be a simple and robust tool for modeling phase behavior of surfactant/crude oil/brine systems. The HLD–NAC model can shorten the surfactant screening process hence help chemical EOR formulation design and optimization, and can also be used in compositional chemical flooding reservoir simulation to improve the predictability of surfactant floods.

Gas transport in nano-scale channels has been of high complexity. The extra properties of shale gas reservoirs make it even more complicated. Therefore, accurate modeling of the apparent permeability of gas transport in shale gas reservoirs is urgently needed. In this work, we developed apparent permeability models for real gas transport in both nano-capillary tube and nanopores which incorporate different mechanisms including gas adsorption, stress dependence, non-Darcy flow, and surface diffusion. In particular, both monolayer and multi-layer adsorptions were included using a unified equation. The models were verified using the experimental data of gas transport in nano-capillary tube and nanopores. After that, we used the models to study the behaviors of different mechanisms of apparent permeabilities focusing on their contributions to the total apparent permeability and their sensitivity to several important parameters. We investigated the variations of apparent permeabilities with different mechanisms for gas transport under four different cases, which are, in nano-capillary tubes or nanopores, and with monolayer or multi-layer adsorptions, respectively. The results indicated that, under most real shale-gas-reservoir conditions, the corrected permeability due to gas adsorption and the non-Darcy flow permeability are dominant in the apparent permeability, while the surface diffusion permeability caused by adsorbed gas can be largely overlooked. In addition, for the cases with relatively larger sizes of nano-capillary tubes or nanopores, we observe a smaller ratio of non-Darcy flow permeability over the corrected permeability due to gas adsorption and a smaller contribution of surface diffusion as well. However, if we artificially increase the diffusion coefficient, the contribution of surface diffusion to the total apparent permeability can rapidly increase. The findings are crucial for evaluating the contribution of surface diffusion.

Summary Many empirical and analytical models were developed to forecast oil production. Empirical models (including data-driven models) can, for example, find correlations between oil cut and production, but they lack explicit knowledge of the physical behavior. Classic analytical models are loyal to reservoir physics. Nevertheless, they often require estimation of water saturation as a function of time, which is difficult to obtain for multiwell reservoirs. It is desirable to combine advantages of both empirical and analytical models and develop a physical-model-based method that uses field data to infer oil rate. In this paper, we propose to infer fractional-flow models from field data by use of the Koval (1963) theory. We inversely solved the Koval fractional-flow equation to obtain a relationship between water cut and dimensionless time. By history matching field water-cut data, two model parameters, the Koval factor and the producer-drainage volume, are estimated. Nevertheless, it is challenging to use the Koval approach as a predictive model directly because the injection contribution into each producer in a future-time horizon must be evaluated first. To address this issue, we combine the Koval approach with the capacitance/resistance model (CRM), which characterizes the injector/producer connectivities and response time. The material balance of fluids is established in a producer-based drainage volume to consider the contributions from nearby injectors and the time lag in production caused by reservoir/fluids compressibility. A regression approach is simultaneously advanced to minimize the model error. Because of robustly integrating the reservoir physical behavior and the data-driven approach, the combination of the Koval theory and the CRM can result in a synergy that leads to accurate oil-rate predictions. We validated this integrated method in synthetic homogeneous and heterogeneous reservoirs to test its reliability, and further applied it to a field case in western Venezuela. Case studies demonstrate that one can use this integrated model as a real-time tool to characterize interwell connection and to predict future oil production accurately.

This paper presents an adaptive mesh refinement (AMR) algorithm to solve the non-isothermal multiphase flows in heterogeneous porous media comprising different rock types. To address the discontinuity coming from different rock types, we found that the ratios of relative permeability and oil-gas capillary pressure are continuous; hence they are chosen as the judging values for the regridding purpose. Moreover, because of the tensorial permeability and the complex topology of the AMR grid, a coupling flux solution based on the multipoint flux approximation was carefully designed. Numerical examples revealed the accuracy and efficiency of the proposed AMR algorithm.

General strain theory (GST) has been one of the most frequently tested criminological theories. According to GST, strain tends to generate negative emotions, which create pressures for corrective action, such as crime and delinquency. Although GST has received strong empirical support, one under-addressed issue is the lack of diversity in sampling population in assessing the generalizability of the theory. Using survey data collected from 335 incarcerated women in four Chinese prisons, this study examined the impact of strain and negative emotions on the level of female criminality. The strain variable, physical abuse, and discrimination, exerted a positive effect on female inmates’ levels of criminality, whereas negative emotions were not significantly related to female criminality. Two control variables, age of current offense and educational attainment, were predictive of female criminality, with younger and less-educated women having more serious criminality. Implications for future research and policy are discussed.

This paper presents a new three-phase relative permeability model for use in chemical flooding simulators. Numerical simulation test cases are presented to illustrate the continuity of the new relative permeability model. Comparisons are made with a three-phase relative permeability model that has been widely used in chemical flooding simulators for decades. These comparisons show the old model has numerical discontinuities that are not physical in nature and that can lead to oscillations in the numerical simulations. The proposed model is simpler, has fewer parameters and requires less experimental data to determine the relative permeability parameters compared to the original model. Simulations using the new model showed excellent agreement with ASP coreflood data.

Unstable floods and resulting viscous fingers remain a big challenge for reservoir simulation as the gridblock size is usually many orders larger than the viscous finger wavelength. This problem becomes especially pronounced with increasing applications of polymer and other chemical floods in the development of heavy oil reservoirs. Traditional reservoir simulators do not consider sub-grid viscous fingering effects and tend to overestimate the waterflood oil recovery. Using extremely fine grid models with centimeters size is unrealistic for field-scale simulations. While some researchers disregard viscous fingering by claiming that channeling dominates at the large scale for heterogeneous reservoirs, they miss the existence of viscous fingering at the small scale, which affects the displacement efficiency. To overcome this limitation, an effective-fingering model was developed to upscale fingering effects. The model divides each gridblock into three dynamic regions: two-phase flow, single phase oil flow, and bypassed-oil regions. Model parameters represent the maximum fraction of viscous fingering and the growth rates of different regions, which are used to modify flow functions. Model parameters from history match of a set of laboratory experiments show clear power-law correlations with a dimensionless viscous finger number, a function of viscosity ratio, velocity, permeability, interfacial tension, and core cross-sectional area. The correlation was achieved in the lab scale by considering homogeneous cores, and we extended it further to the field scale by performing high-order spatial accuracy numerical simulations at the intermediate scale using fine gridblock sizes roughly the same as that of the core. Geostatistical realizations of the permeability field were generated with various variances and correlation lengths. In a statistical way, we were able to quantify the viscous finger number valid for a gridblock at the field scale affected by various heterogeneities using the effective-fingering model. We also observed that channelized permeability distributions increase the viscous finger number drastically, showing the important role of channeling in such cases. This new model was applied to a field case with high heterogeneity undergoing water/polymer floods. We observed that the oil recovery was improved by the polymer slug because of the enhancement in both local displacement efficiency and sweep efficiency. In summary, we developed an upscaling model that provides a fresh-new insight on how to simulate unstable water/polymer floods at the field scale, which effectively accounts for the interplay of viscous fingering and channeling.

Polymer flooding has been commercially applied to a number of viscous oil fields in the past decade and gradually gained more popularity. Due to limited injectivity in viscous-oil reservoirs, a relatively low polymer viscosity is usually used to avoid excessive injection pressure. In such a case, mobility ratio of polymer solution to oil is much greater than one, which implies unstable flow and strong viscous fingering. Existing reservoir simulators lack the capability of modeling such a physical phenomenon. Since many viscous-oil reservoirs have high permeability contrast between layers, we are motivated to study, for the first time, the impact of crossflow between different layers considering the presence of viscous fingering.Numerical modeling polymer floods with crossflow in a layered viscous-oil reservoir is difficult due to two major challenges: first is how to correctly allocate flow rates from the wellbore to multiple layers; and second is how to capture the viscous fingering effect without using excessively fine grids. To address the first issue, we developed an implicit well-rate-allocation model based on the potential method, which fully couples all the wellbore segments of each well with reservoir gridblocks to ensure a physical wellbore pressure. To deal with the second challenge, we implemented the effective fingering model, which is an upscaling model that lumps all the viscous fingers in a coarse grid block into one fictitious finger to allow for accurate estimation of fingering strength and growth during unstable flows. Both models were validated individually against the analytical solution or experimental data.The integrative module including the two new capabilities was used to simulate a polymer flood following a waterflood in a layer-cake reservoir in North America with moderate oil viscosity. We observed the fast propagation of water fronts and small fingering fraction in high permeability layers during the waterflooding phase, indicating active channeling and viscous fingering. The subsequent polymer flooding minimized both factors of oil bypassing and led to stable flow and high sweep efficiency. Without the implicit well-rate-allocation model, crossflow was overestimated and wellbore pressures of different well blocks were not consistent. Without the effective-fingering model, oil recovery was overestimated due to the lack of accounting for viscous fingering. The simulation results indicated that polymer flooding improved both displacement and sweep efficiencies.The model has shown comprehensive capabilities in reservoir simulations of polymer floods including unstable floods and crossflows between layers. This is a major significance to optimization of non-thermal viscous-oil EOR projects and also making more informed operational decisions for field developments.

Conventional fractional flow theories such as the Buckley-Leverett analysis have benefited reservoir engineers greatly for many decades. Although being simple, these analyses provide prompt and decent estimations of water breakthrough and oil bank height/duration in the experiments and the fields. However, their intrinsic inaccuracy in estimating unstable immiscible floods due to the existence of viscous fingering has long been ignored. With increasing non-thermal immiscible floods developed for heavy oil reservoirs, an essential improvement for such a theory is desirable. The intrinsic residual oil saturation can never be achieved for strong unstable immiscible floods within a finite time. The fraction of the bypassed oil at a time is highly dependent on the viscosity ratio, flow velocity, interfacial tension, wettability, permeability and the geometry of the rock. Extensive experimental data and numerical studies have indicated that the strength and growth rate of viscous fingering are correlated to a dimensionless number, i.e., the viscous finger number, which is an integration of those factors aforementioned. Such a discovery enables a quantitative establishment of two-phase pseudo relative permeabilities, which are functions of fluid saturations and the viscous finger number. The fractional flow for unstable floods can hence be obtained by use of such pseudo relative permeabilities. The new fractional flow theory extended from the Buckley-Leverett analysis was applied to several groups of heavy-oil water coreflood experiments under various conditions. The new fractional flow analysis was able to predict very well the breakthrough time and oil recovery of these experiments. We further applied the new fractional flow analysis to a slab experiment of viscous oil with a waterflood followed by a polymer flood, and achieved a very good agreement with the oil recovery data. The analysis reproduced that the water cut increased very rapidly and the remaining oil saturation was much larger than the intrinsic residual oil saturation after several pore volumes of waterflood. The subsequent polymer flood altered the pseudo relative permeability curves due to the change of viscosity ratio and brought in a considerable amount of mobile oil to be displaced. This process happens to be similar to the fractional flow of low-tension immiscible flow. Such a scenario is different from what the conventional fractional flow analysis suggests, which neglects the fact that the subsequent polymer flood is able to greatly improve the oil cut by mitigating the viscous fingers originally created by waterflood. The new theory has extended the original fractional flow theories to unstable immiscible floods, a major progress. It can also serve as a critical guideline to estimate and predict the water/polymer breakthrough and the oil production in viscous-oil benchscale experiments and field projects.

Natural evaporite dissolution in the subsurface can lead to cavities having critical dimensions in the sense of mechanical stability. Geomechanical effects may be significant for people and infrastructures because the underground dissolution may lead to subsidence or collapse (sinkholes). The knowledge of the cavity evolution in space and time is thus crucial in many cases. In this paper, we describe the use of a local nonequilibrium diffuse interface model for solving dissolution problems involving multimoving interfaces within three phases, that is, solid–liquid–gas as found in superficial aquifers and karsts. This paper generalizes developments achieved in the fluid–solid case, that is, the saturated case [1]. On one hand, a local nonequilibrium dissolution porous medium theory allows to describe the solid–liquid interface as a diffuse layer characterized by the evolution of a phase indicator (e.g., porosity). On the other hand, the liquid–gas interface evolution is computed using a classical porous medium two-phase flow model involving a phase saturation, that is, generalized Darcy’s laws. Such a diffuse interface model formulation is suitable for the implementation of a finite element or finite volume numerical model on a fixed grid without an explicit treatment of the interface movement. A numerical model has been implemented using a finite volume formulation with adaptive meshing (e.g., adaptive mesh refinement), which improves significantly the computational efficiency and accuracy because fine gridding may be attached to the dissolution front. Finally, some examples of three-phase dissolution problems including density effects are also provided to illustrate the interest of the proposed theoretical and numerical framework.

Chemical flood reservoir simulators developed based on component partitioning model or empirical phase behavior model lack the effects of physical properties such as surfactant structure and oil properties i.e. equivalent alkane carbon number (EACN) on microemulsion phase behavior. Hence, these simulators have limited function in helping formulation design. A typical empirical microemulsion phase behavior model is the Hand's model that is used in UTCHEM, a benchmark chemical flood compositional simulator. However, it needs several matching parameters to fit phase behavior experiments and requires iterative calculations to solve phase compositions. Therefore, it is desirable to develop a chemical flood simulator with a more efficient and physics-based phase behavior model. This work incorporates a physics based HLD-NAC equation of state (EOS) into UTCHEM. A non-iterative flash calculation algorithm based on HLD-NAC microemulsion EOS is developed, which uses simple equations to represent plait point, binodal curve, and tie-lines. Input model parameters include quantitatively characterized physical properties, such as oil EACN, reservoir temperature, surfactant structure properties (head area and tail length), and optimum solubilization ratio. Therefore, the effects of these parameters on oil recovery can be systemically studied. Coreflood simulation results are validated against the Hand's model. Compared to the Hand's model which requires at least 5 matching parameters and with limited predictability, the HLD-NAC EOS can reproduce microemulsion phase behavior with surfactant tail length as the only fitting parameter. Comparing coreflood simulations using the HLD-NAC model and the Hand's model shows that the same oil recovery curves are obtained when slug at optimum salinity is injected. However, for corefloods using a salinity gradient design, HLD-NAC model predicts higher oil recovery than the Hand's model. The reasons for the differences are analyzed by examining the simulated solubilization ratios and ternary phase diagrams at different salinities. Moreover, numerical experiments show that the HLD-NAC model improves the phase behavior computational efficiency by approximately 65%. The effect of live oil at reservoir pressure is also investigated. Results indicate shifted optimal salinity and solubilization ratio due to solution gas and pressure lead to larger microemulsion bank. Owing to the physical significance, simplicity, and computational efficiency of the HLD-NAC EOS, this novel chemical flooding simulator proves to be a fast and promising tool to speed up surfactant screening process and helping chemical formulation development and injection designs.

Numerical simulation is important to understand and predict the development of oil and gas reservoirs. Existing commercial simulators, such as CMG, ECLIPSE and VIP, have been widely used in the past several decades for their robust performance in computing and scaling. In these reservoir simulators, the fluid flow models are based on Darcy's law or its extended form; the volume of the adsorbed phase or component is overlooked as well. While this is acceptable for conventional oil/gas reservoirs or chemical flooding reservoirs, the gas flow regimes such as slippage flow, transition flow, and molecular-free flow significantly is deviated from Darcy flow for shale gas reservoirs. Besides, a large portion of the gas is stored in the pore in the form of adsorbed gas. If the volume of the adsorbed gas is still overlooked, the volume of free gas and original gas in place (OGIP) will be seriously overestimated. For the above reasons, it is commonly thought that existing commercial simulators could not be ideally used to simulate the development of shale gas reservoirs. Hence, it is desirable to attain a feasible approach to correct the petro-physical properties of shale gas effectively within the commercial simulators, in order that one can use them to accurately simulate the development of shale gas reservoirs. In this paper, we first derived the correction formulas for the bulk porosity, free gas saturation, and connate water saturation used for correcting the disregarded volume of adsorbed gas in commercial simulators. Then, we derived the models of permeability and porosity multipliers in matrix considering gas adsorption/desorption, geomechanics, non-Darcy flow regimes, and diffusion of adsorbed layer. Finally, the above models were used to attain the corrected petro-physical properties for simulating gas production based on the practical properties of shale gas reservoirs using commercial simulators. The validation was performed by comparing the simulation results of commercial simulator with the published mechanism simulator using gas field data. The results show that the simulation results using commercial simulator achieve good agreement with the published mechanism simulator with the corrected petro-physical properties. The corrections of bulk porosity, connate water saturation, and free gas saturation are very essential. The correction formulas for these properties can largely decreases the error of OGIP and the calculated gas production. Both permeability and porosity multipliers are the functions of gas pressure, but they are not a monotone decreasing/increasing function. The gas production may be significantly overestimated or underestimated without consideration of these characteristics of shale gas in different fields. The contributions of different mechanisms are also demonstrated using the commercial simulator. This work can evently solve the issue that existing commercial simulators cannot accurately simulate shale gas production. The researchers can easily use these commercial simulators with these corrected formulas, which is a great progress for modeling the development of shale gas reservoir.

The surfactant screening process to develop an optimum formulation under reservoir conditions is typically time consuming and expensive. Theories and correlations like HLB, R-ratio and packing parameters have been developed. But none of them can quantitatively consider both the effect of oil type, salinity, hardness and temperature, and model microemulsion phase behavior. This paper uses the physics based Hydrophilic Lipophilic Difference (HLD) Net Average Curvature (NAC) model, and comprehensively demonstrated its capabilities in predicting the optimum formulation and microemulsion phase behavior based on the ambient conditions and surfactant structures. By using HLD equation and quantitatively characterized parameters, four optimum surfactant formulations are designed for target reservoir with high accuracy compared to experimental results. The microemulsion phase behavior is further predicted, and well matched the measured equilibrium interfacial tension. Its predictability is then reinforced by comparing to the empirical Hand's rule phase behavior model. Surfactant flooding sandpack laboratory tests are also interpreted by UTCHEM chemical flooding simulator coupled with the HLD-NAC phase behavior model. The results indicate the significance of HLD-NAC equation of state in not only shorten the surfactant screening processes for formulators, but also predicting microemulsion phase behavior based on surfactant structure. A compositional reservoir simulator with such an equation of state will increase its predictability and hence help with the design of surfactant formulation.