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The understanding of proppant flow through fractures is critical in evaluating the performance of hydraulic fracturing operations. As a continuation of our experimental efforts devoted to understanding how proppant flows in rough vertical fractures, in this paper, we examine the effect of injection parameters on the proppant transport in rough vertical fractures. The effects of polymer concentration, injection rate, proppant concentration, and type of proppant were investigated in detail. Experimental results show that, in general, two types of settling patterns can be observed in the proppant transport in a rough fracture: sand-dune settling pattern and tree-like settling pattern. The following conditions tend to suppress the tree-like settling behavior of proppants in the rough fracture: a higher density of the proppants, a lower viscosity of the polymer solution, and a lower injection rate. This is attributed to a higher settling velocity of the proppants in the fracture under these conditions. A sufficiently high polymer concentration is needed to enable effective proppant flow in rough fractures. In general, the relative coverage of proppants increased dramatically as the polymer concentration increased, implying that the higher viscosity of fracturing fluid could enhance the slurry's ability to place more proppant vertically into the fracture and help to maintain a better conductivity after fracturing treatment. A sufficiently high injection rate of the slurry is also needed to enable effective proppant flow in rough fractures. At certain low injection rates, the proppants carried by a low polymer solution might not exhibit a tree-like settling pattern, diminishing the effect of roughness on the proppant transport. This means that even in rough fractures, the tree-like settling pattern of the proppants did not necessarily occur for sure; the injection rate should be properly selected to enable such phenomenon. With other conditions being kept constant, a higher proppant loading led to a higher final relative coverage of the proppants in the rough fractures. But if the injection rate used for delivering the proppants is not sufficiently high, we may encounter injectivity issues; in our lab experiments, this caused the choking of the pump. The heavier proppant (ceramic proppants) in the rough fracture models tended to suppress the tree-like settling pattern that was experienced by the lighter proppant (silica sands). This is attributed to the larger density of the ceramic proppants, leading to a larger settling velocity. In order to maximize the spreading of a given proppant over a rough fracture model, we should determine the proper values of all the essential injection parameters (including polymer solution, injection rate, proppant concentration) by striking a good balance among them. The conclusions obtained in this study shed light on how to optimize slurry injection parameters to achieve an optimal proppant-filling ratio during hydraulic fracturing.

In order to improve the field productivity, the industries can create new fractured wells to reduce the interval between the initial fractures (initial fracture indicates a fracture that is induced during the initial fracturing treatment). Production from the initial fractured wells can induce stress reorientation in the vicinity of the fractures. As such, a refracturing treatment in the stress reorientation region can lead to a reoriented refracture which has a certain azimuth with respect to the initial fractures. This azimuth can even be 90° if the stress reorientation is sufficiently large. In addition to the conventional parameters (including refracture's length, refracture's conductivity, and the in-situ conditions), there are two more factors, the reorientation azimuth and the interference from the initial fracture, which can exert significant influence on the transient flow behavior of the reoriented refractures. In such case, the conventional analytical/semi-analytical models neglecting these two factors are no longer applicable to characterize the transient flow behavior from such a refracture. In this work, we develop a novel semi-analytical model to characterize the transient flow behavior of a reoriented refracture considering the interference from the initial fractures. In this model, the fractures are explicitly represented with discretized segments. We apply finite difference approximation to the initial fractures and refractures, respectively, to simulate the transient flow in the fracture system. In addition, the fluid flow in the matrix system can be characterized by Green function and Newman product method. Based on the continuity of flux and pressure, we couple the fracture flow equations with the matrix flow equations to construct a semi-analytical model. With the aid of the proposed model, we conduct a thorough investigation of the transient flow behavior of reoriented refractures. It is observed that, at the early production period, two fracture pseudo-steady-state flows can appear due to the interference from the initial fractures. The formation linear flow and bilinear flow can also be observed during the production period of a refractured well. In an anisotropic-permeability reservoir, the refracture's azimuth and position can exert a significant impact on the productivity of the fractures. There is a region in the vicinity of the initial fractures, within which an orthogonal refracture can lead to the highest field productivity.

SummaryProduction from a fractured vertical well will lead to a redistribution of the stress field in formations. If the induced stress changes are sufficiently large to overcome the effect of the initial horizontal-stress deviator, the direction of the minimum horizontal stress can be turned into the direction of the maximum horizontal stress within an elliptical region around the initial fracture, resulting in a stress-reversal region near the wellbore. In such cases, a refracturing treatment can create a refracture that propagates orthogonally to the initial fracture because of the stress reversal. As such, the high-pressure area of the formation can be stimulated by the refracture, and the productivity of the refractured well can be improved. In this work, we develop a semianalytical model to evaluate the performance of a refractured vertical well with an orthogonal refracture. To simulate the well performance throughout the entire production period, we divide the well production into three stages: the first stage, when the well is producing oil with the initial fracture; the second stage, when the well is shut down for the refracturing treatment; and the third stage, when the well is producing oil with both the initial fracture and the refracture. In addition, by discretizing the initial fracture and the refracture into small segments, the conductivity of the fractures can be taken into account, and the geometry of the fracture system can be captured. We use the Green-function method to analytically simulate the reservoir flow and use the finite-difference method to numerically simulate the fracture flow; therefore, a semianalytical model can be constructed by coupling the reservoir-flow equations with the fracture-flow equations. This proposed model is applied to different wellbore and reservoir conditions. The calculated results show that this proposed model is versatile because it can simulate various wellbore constraints, including the conditions of constant bottomhole pressure (BHP), varying BHP, constant production rate, and varying production rate. The permeability anisotropy of the reservoir system, as well as the nonuniform conductivity distribution along the fracture, can also be incorporated into this proposed model. In addition, we demonstrate that this proposed model can be used to simulate other types of refractured vertical wells with minor modifications.

Summary Field studies have shown that, if an inclined fracture has a significant inclination angle from the vertical direction or the fracture has a poor growth along the inclined direction, this fracture probably cannot fully penetrate the formation, resulting in a partially penetrating inclined fracture (PPIF) in these formations. It is necessary for the petroleum industry to conduct a pressure-transient analysis on such fractures to properly understand the major mechanisms governing the oil production from them. In this work, we develop a semianalytical model to characterize the pressure-transient behavior of a finite-conductivity PPIF. We discretize the fracture into small panels, and each of these panels is treated as a plane source. The fluid flow in the fracture system is numerically characterized with a finite-difference method, whereas the fluid flow in the matrix system is analytically characterized on the basis of the Green's-function method. As such, a semianalytical model for characterizing the transient-flow behavior of a PPIF can be readily constructed by coupling the transient flow in the fracture and that in the matrix. With the aid of the proposed model, we conduct a detailed study on the transient-flow behavior of the PPIFs. Our calculation results show that a PPIF with a finite conductivity in a bounded reservoir can exhibit the following flow regimes: wellbore afterflow, fracture radial flow, bilinear flow, inclined-formation linear flow, vertical elliptical flow, vertical pseudoradial flow, inclined pseudoradial flow, horizontal-formation linear flow, horizontal elliptical flow, horizontal pseudoradial flow, and boundary-dominated flow. A negative-slope period can appear on the pressure-derivative curve, which is attributed to a converging flow near the wellbore. Even with a small dimensionless fracture conductivity, a PPIF can exhibit a horizontal-formation linear flow. In addition to PPIFs, the proposed model also can be used to simulate the pressure-transient behavior of fully penetrating vertical fractures (FPVFs), partially penetrating vertical fractures (PPVFs), fully penetrating inclined fractures (FPIFs), and horizontal fractures (HFs).

Compared with the marine shale payzones, lacustrine shale payzones generally contain more interbed layers (e.g., sandstone interbeds and carbonate interbeds), bringing about a higher complexity to the identification of effective lacustrine shale payzones. In this work, a pragmatic but systematic approach is developed to identify the effective lacustrine shale payzones with commercial hydrocarbon-production potentials. Such identification approach is developed based on three easily accessible data sources that are obtained from multiple wells drilled in a given region: 1) well logging data; 2) measured properties of the core samples; and 3) production test data. In this approach, the first step is to identify shale-containing formations based on the lithology profile along a well that has been interpreted using the well logging data. Secondly, a shale-dominated formation is extracted from a given shale-containing formation if the ratio of total shale thickness to the total formation thickness exceeds 60%; this cut-off value is selected based on the consideration that such formation has a higher possibility of industrial production potential. Lastly, a shale-dominated formation can be classified as an effective shale payzone if the total organic carbon (TOC) content, porosity, and effective thickness are all greater than the given threshold values. By using this proposed method, one can obtain the total effective thickness and the regional distribution of effective lacustrine shale payzones, which could help to locate the sweet spot of the shale payzones as well as subsequently design proper methods for recovering the shale resources. The Lower Jurassic formations possess abundant lacustrine shale layers that are widely considered to be the potential lacustrine shale gas payzones in the northwest of Sichuan Basin in China. A case study in this formation is presented to demonstrate the efficacy of the newly developed approach in identifying the effective lacustrine shale payzones. Validation results prove that this new method can be used to effectively identify the effective lacustrine shale payzones with commercial production potentials.

The effectiveness of the near-wellbore fracture network greatly affects the production potential of naturally fractured gas reservoirs. In this work, we develop an index to characterize the near-wellbore fracture network in naturally fractured gas reservoirs, which is defined as the fracture-network effectiveness index. To build such an index, multiple factors are considered, i.e., the fracture aperture distribution, the fracture porosity distribution, the fracture permeability distribution, and the fracture coverage ratio in the pay-zone. The new index has been calculated based on a variety of relevant field data which include well test analysis results, production test data, imaging logs, conventional logs, and three-dimensional (3D) whole-core computerized tomography (CT) scans. To validate this newly proposed index, the calculated index is applied to correlate with the absolute open flow capacity in a target formation located in the Xinchang gas field of China. Test results show that the natural fracture-network effectiveness index strongly correlates with the absolute open flow capacity in the selected wells. It indicates that the proposed index should be a useful tool for evaluating the production potential of the payzones in such naturally fractured gas reservoirs. This index can be also applied to guide the effective exploitation of naturally fractured gas reservoirs with multiple payzones.

Summary The Peng-Robinson equation of state (PR-EOS) (Robinson and Peng 1978) with capillary effect has been used extensively to describe the phase behavior of hydrocarbons under nanoconfinement in shale reservoirs. In nanopores, surface adsorption may be significant, and molecular distribution is heterogeneous. Although the PR-EOS cannot consider these effects, statistical thermodynamic approaches such as density-functional theory (DFT) can explicitly consider the intermolecular and fluid/surface interactions. In this work, we compare the phase behavior of pure hydrocarbons and mixtures in nanopores from the PR-EOS with capillary effect and engineering DFT. We apply the Young-Laplace (YL) equation, assuming zero contact angle to calculate the capillary pressure in the PR-EOS with capillary effect. On the other hand, we extend the PR-EOS to inhomogeneous conditions with weighted-density approximation (WDA) in engineering DFT. For pure components, both approaches predict that the dewpoint temperature increases in hydrocarbon-wet nanopores. Although engineering DFT predicts that the confined dewpoint temperature approaches bulk saturation point when pore size approaches 30 nm, the saturation point obtained from the PR-EOS with capillary effect approaches bulk only when the pore size is as large as 1000 nm. With engineering DFT, the critical points in nanopores deviate from those in bulk, but no change is observed from the PR-EOS with capillary-effect model. The difference on the dewpoint temperature between the PR-EOS with capillary effect and engineering DFT decreases as the system pressure approaches the critical pressure. At low-pressure conditions, the PR-EOS with capillary-effect model becomes unreliable. For binary mixtures, both approaches predict that the lower dewpoint decreases and the upper dewpoint increases. More interestingly, phase transition can still occur when the system temperature is higher than the bulk cricondentherm point. Engineering DFT predicts that the confined lower dewpoint approaches bulk when pore size approaches 20 nm, whereas the dewpoint obtained from the PR-EOS with capillary effect approaches bulk only when the pore size is as large as 100 nm. This work illustrates that assuming homogeneous distributions in nanopores may not be appropriate to predict the phase behavior of hydrocarbons under nanoconfinement.

Summary Solvent/thermal hybrid methods have been proposed recently to enhance heavy-oil recovery and to overcome the shortcomings that are encountered when either method is solely applied. One of the methods for this hybridization is to combine electromagnetic (EM) heating and solvent injection to facilitate heavy-oil production by gravity drainage. This approach has several advantages including reduced CO2 emissions, decreased water consumption, and appropriateness for water-hostile reservoirs. We are currently lacking any mathematical model for better understanding, designing, and optimizing this hybrid technique, which is partly attributed to this technique still being in its infancy. We propose a semianalytical model to predict the oil-flow rate resulting from the combined EM heating and solvent-assisted gravity drainage. The model first calculates the temperature distribution within the EM-excited zone caused by the radiation-dominated EM heating. Using different attenuation coefficients within and beyond the vapor chamber, the model can properly describe the corresponding temperature responses in these regions. Next, an average temperature of the chamber edge contributed by EM heating is used to estimate the temperature-dependent properties, such as vapor/liquid equilibrium ratios (K-values), heavy-oil/solvent-mixture viscosity, and solvent diffusivity. Subsequently, a 1D diffusion equation is used to calculate the solvent-concentration distribution ahead of the chamber edge. Eventually, the oil-flow rate is evaluated with the calculated temperature and solvent distributions ahead of the chamber edge. The proposed model is validated against the experimental results obtained in our previous study, and the predicted oil-flow rate agrees reasonably well with the experimental data. The proposed model can efficiently predict the oil-flow rate of this hybrid process. We conduct sensitivity analyses to examine the effect of major influential factors on the performance of this hybrid technique, including EM heating powers, solvent types, solvent-injection pressures, and initial reservoir temperatures. The modeling results demonstrate that a higher EM heating power, a heavier solvent, and a higher solvent-injection pressure could accelerate the oil-recovery rate, but tend to lower the net present value (NPV) and increase the energy consumption. In summary, the newly proposed model provides an efficient tool to understand, design, and optimize the combined technique of EM heating and solvent-assisted gravity drainage.

Phase behavior of shale fluids in small pores is not well understood. One complexity comes from the fact that sorption of components by organic-rich shale can be significant and selective. In an attempt to elucidate the effect of sorption on phase behavior of shale fluids, we present a new experimental method that can be used to measure the bubble-point pressures of N2/n-C4H10 mixtures in the presence of an actual shale sample. Pressure/volume (P/V) isotherms for a given mixture were firstly measured in a PVT cell. Then, the measurements of the P/V isotherms for the same mixture were repeated in a partially confined space by opening a valve between the PVT cell and a shale container. The so-called partially confined space consists of the pore space inside the shale sample, the bulk space in the PVT cell and in the connecting tubing, and the non-cementing pore spaces among the shale particles. Results show that, the measured bubble-point pressure of the N2/n-C4H10 mixture in the partially confined space was higher than the corresponding bubble-point pressure in the bulk space. A detailed analysis indicates that, when loaded in the partially confined space, n-C4H10 exhibits a higher level of sorption capacity on the shale sample than N2, resulting in a higher concentration of N2 left in the free fluid than that in the initial mixture, which is the so-called selective sorption. The higher concentration of N2 led to the higher bubble-point pressure as observed in the measurements. The increase of the bubble-point pressure due to the selective sorption was observed to be greater at a lower temperature. This is because the sorption of n-C4H10 relative to that of N2 is more significant at a lower temperature. A higher temperature did not lead to a higher increment in the bubble-point pressure likely because bubble-point is more sensitive to composition than to temperature for these mixtures at the conditions tested. This emphasizes the importance of considering sorption in phase behavior for small pores.

Late cycles of cyclic steam stimulation (CSS) are characterized with a decreasing heavy-oil recovery and an increasing water cut. Nickel nanoparticles can be used to promote aquathermolysis reactions between water and heavy oil in steam injection processes, thereby increasing the recovery factor. In this paper, detailed investigations were performed to determine the optimum operational parameters and answers to the following questions: (1) What is the optimum concentration of nickel nanoparticles for promoting aquathermolysis under high steam temperature?; (2) Can we improve oil recovery at lower steam temperatures with the presence of nickel nanoparticles?; (3) What effect does the penetration depth of nickel nanoparticles have on the final oil recovery? CSS experiments were conducted between temperatures 150°C and 220°C. Steam generated under these temperatures was injected into sand packs saturated with Mexican heavy oil. Powder-form nickel nanoparticle was introduced into this process to boost the oil production. In an attempt to obtain the optimum concentration, different concentrations were tested. Next, oil sands without any nanoparticle additives were first added into the cylinder. Then, only one third of the sand pack was mixed with nickel nanoparticle near the injection port. Experiments were executed to study the effects of temperature, nickel concentrations, and nanoparticle penetration depth on the ultimate oil recovery and produced oil-water ratios after each cycle. Produced oil quality and emulsion formation were evaluated with gas-chromatography (GC) analysis, viscosity measurements, saturates-asphaltenes-resins-aromatics (SARA) test, and microscopic analysis of the effluents. Experimental results show that the best concentration of nickel nanoparticles, which gives the highest ultimate oil recovery factor, is 0.20 wt% of initial oil in place (IOIP) under 220°C, while the nickel concentration of 0.05 wt% provides the highest recovery factors at the early stages. A lower temperature of 150°C provides a much lower recovery factor than 220°C, which is mainly due to a lower level of aquathermolysis reactions at 150°C. By analyzing the compositions of produced oil and gas samples with GC and SARA, we confirm that (1) the major reaction mechanism during the aquathermolysis reaction is the breakage of C-S bond, (2) the nickel nanoparticles can act as catalyst for the aquathermolysis reaction, and (3) the catalytic effect becomes less remarkable from cycle to cycle. One run of experiment to test the effect of particle penetration depth revealed that nickel nanoparticle distributed near the injection port greatly contributed to the ultimate recovery factor.

Summary Steam/solvent coinjection has been studied as a potential method to improve the efficiency of conventional steam-assisted gravity drainage (SAGD) for bitumen recovery. This research is part of an experimental program for phase behavior of Athabasca-bitumen/solvent mixtures. This paper presents a new set of experimental data for phase equilibrium, viscosity, density, and asphaltene precipitation for 11 mixtures of Athabasca bitumen with n-hexane and 10 mixtures of the same bitumen with n-octane. Phase-boundary measurements were conducted at temperatures up to 160°C and pressures up to 10 MPa. The bitumen sample used in this research was studied in our previous research, in which the same bitumen was not effectively diluted by n-butane because of the coexistence of a butane-rich liquid with a bitumen-rich liquid phase. In this research, the liquid/liquid separation of hydrocarbons was not observed for n-hexane/bitumen (HB) and n-octane/bitumen (OB) mixtures for the range of temperatures and pressures tested, even at solvent concentrations higher than 90 mol%. This observation indicates that the amount of solvent available near the edge of a steam chamber is expected to be entirely used for bitumen dilution beyond the chamber edge in coinjection of steam with heavier hydrocarbon solvents, such as n-hexane and n-octane. Experiments for asphaltene precipitation at atmospheric pressure showed a larger amount of precipitates with n-hexane than with n-octane at a given solvent concentration higher than 50 wt%. For solvent concentrations less than 50 wt%, no asphaltene precipitation was observed for both solvents with the bitumen sample tested in this research.

Electromagnetic (EM) heating holds a significant potential for recovering heavy oil and bitumen since it can reduce carbon emission and avoid excessive water usage, and is applicable for water hostile reservoirs. Combining solvent injection with EM heating might further reduce the energy intensity of the process. The merits of using solvent in EM heating include diluting heavy oil and thereby increasing its mobility, serving as a heat carrier by reinforcing heat convection in porous media and facilitating gravity drainage by forming a vapor chamber. In this study, we design a new experimental setup that can be used to examine the performance of combined EM heating and solvent-assisted gravity drainage for heavy oil recovery. With such experimental setup, we conduct a series of laboratory experiments to investigate the performances and mechanisms of combined EM heating and solvent-assisted gravity drainage for heavy oil recovery. During experiments, sand pack samples contained in Buchner filter funnel are placed in a microwave oven. Solvent injection can be initiated together with EM heating to simulate this hybrid process. Temperatures of the sand pack and oil recoveries are simultaneously recorded. We investigate the effects of influential factors on the process performances, including EM heating power, initial water saturation, solvent types (n-hexane and n-octane), and combination strategies of EM heating and solvent injection (simultaneous or alternate means). Experimental results show that combined EM heating and solvent-assisted gravity drainage could effectively enhance heavy oil recovery; the recovery factors of EM heating only, alternate EM heating and n-hexane injection, and alternate EM heating and n-octane injection are 12.37%, 61.18%, and, 83.59%, respectively. Moderate initial water saturation increases the heating speed and provides a higher oil recovery. The effect of solvent addition, affected by the solvent concentration in heavy oil, varies at different EM heating powers. Alternate EM heating and solvent injection is more cost effective due to the lower energy consumption and higher oil recovery compared to the simultaneous EM heating and solvent injection. A lowered asphaltene fraction in recovered oil has also been found in this hybrid process.

Summary Several interwell connectivity models such as multiple linear regression (MLR) and the capacitance model (CM) have been proposed to model waterflooding performance in high-permeability reservoirs on the basis of observed production data. However, the existing methods are not effective at characterizing the behavior of transient flows that are prevalent in low-permeability reservoirs. This paper presents a novel dynamic waterflooding model that is based on linear dynamical systems (LDSs) to characterize the injection/production relationships in an oil field during both stationary and nonstationary production phases. We leverage a state-space model (SSM), in which the changing rates of control volumes between injector/producer pairs in the reservoir of interest serve as time-varying hidden states, depending on the reservoir condition. Thus, the model can better characterize the transient dynamics in low-permeability reservoirs. We propose a self-learning procedure for the model to train its parameters as well as the evolution of the hidden states only on the basis of past observations of injection and production rates. We tested the LDS method in comparison with the state-of-the-art CM method in a wide range of synthetic reservoir models including both high-permeability and low-permeability reservoirs, as well as various dynamic scenarios involving varying bottomhole pressure (BHP) of producers, injector shut-ins, and reservoirs of larger scales. We also tested LDS on the real production data collected from Changqing oil field containing low-permeability formations. Testing results demonstrate that an LDS significantly outperforms CM in terms of modeling and predicting waterflooding performance in low-permeability reservoirs and various dynamic scenarios.

Steam-solvent coinjection has been studied and pilot-tested as a potential method to improve steam-assisted gravity drainage (SAGD) for bitumen recovery. Reliable design of coinjection requires reliable PVT data for bitumen/solvent/water mixtures, which are scarce and fragmentary in the literature. The main objective of this research was to present a new set of PVT and multiphase data for n-butane/Athabasca-bitumen/water mixtures at pressures up to 10 MPa and temperatures up to 160°C. Experiments were conducted by use of a conventional PVT apparatus. The data presented include multiphase equilibria up to four coexisting phases and liquid densities for 100% bitumen, two mixtures of n-butane/bitumen, and one mixture of n-butane/bitumen/water. A single equation-of-state model was developed to correlate all experimental data obtained, and used to interpret complex multiphase behavior observed for the highly size-asymmetric polar mixtures. Liquid-liquid separation of hydrocarbons was experimentally observed at the n-butane concentration of 97 mol% in the n-butane/bitumen system with/without water, for a wide range of temperatures at operating pressures for expanding-solvent-SAGD (ES-SAGD). This may indicate the limited solubility of n-butane in bitumen even when a high level of accumulation of n-butane takes place near a chamber edge in ES-SAGD for Athabasca bitumen. The multiphase transition that involves appearance/disappearance of the vapor phase was observed to occur near the vapor pressure of n-butane or its extension. Such phase transition occurs at a higher pressure in the presence of water, due to its vapor pressure, than in the absence of water at a given temperature. This is the first time four coexisting phases are reported for n-butane/Athabasca-bitumen/water mixtures at temperature-pressure conditions relevant to ES-SAGD.

Field emission scanning electron microscope (FESEM) is a widely used technique to examine pore structures in shale reservoirs. Prior to a FESEM scan, one must decide upon the location of sample to be viewed as well as the magnification ratio to be used, which is, however, prone to human errors. One common practice in FESEM study is that one tends to use a fixed magnification ratio for observing the pore structure on a given location of a sample. Also, the pore structure observed based on a given magnification factor cannot entirely represent the true pore structure characteristics of the shale sample, primarily due to the multi-scale heterogeneity of the shale rocks. To improve the FESEM characterization of pore structure in shale samples, we propose a methodology to reveal the multi-scale characteristics of shale samples. In this work, we propose an improved method for taking multiple FESEM images for performing more accurate characterization of the pore structures in shale samples. With the improved method, we can determine the appropriate number of FESEM images to be taken as well as the appropriate magnification ratio to be used in FESEM scan. A given magnification ratio is used throughout all the FESEM scans. This method can be used to retrieve important multiscale pore-structure characteristics of shale samples. We demonstrate the efficacy of the improved FESEM characterization technique by applying it to a shale gas formation in Sichuan basin in China.

Surfactant-alternating-gas injection, where foam generation can be expected, is a feasible approach for improving the sweep efficiency of solvent flooding by increasing the apparent viscosity of gas solvent. The foam stability plays an important role in this process. In this study, the foam stability and mobility of solvent/surfactant/pseudo-heavy-oil system under reservoir condition has been examined experimentally. The following factors are considered in the static foam stability experiments: surfactant concentration, salinity, temperature, the presence of pure n-C16H34 as pseudo-heavy oil, and two types of gases (CO2 and C3H8). During the static experiments, foam is generated by sparging C3H8 or CO2 at a constant flow rate through the surfactant Triton X-100 solution, and then stirring the mixture with a magnetic stirrer. The foam stability is subsequently evaluated in terms of its height change as a function of time. It is found that the increasing surfactant concentration contributes to an increase in foam stability; foam stability is insensitive to surfactant concentration when the surfactant concentration is above the threshold CMC. As for the C3H8 foam, an elevated temperature is detrimental to foam stability. At a higher temperature, the effective critical micelle concentration (CMC) of surfactant also increases. In general, the stability of C3H8 foam is negatively affected by an increasing salinity. As n-C16H34 is added to the solution, foam stability deteriorates. In order to study the effect of solvent type on foam stability, CO2 is used to replace C3H8 for generating foam, with the consideration of different salinity and temperature conditions. In comparison, CO2 foam only exhibits several minutes of half-life at any conditions, which is much shorter than the C3H8 foam. Additional flow experiments are also conducted by alternately injecting C3H8 and Triton X-100 solution into a glass beadpack. The pressure difference during the experiments is recorded so as to obtain the mobility of the dynamic flow in the porous media. It is found that alternating C3H8 and Triton X-100 solution results in a larger pressure difference, hence leading to more mobility reduction than alternating C3H8 and water through the porous media.

In order to explore the optimal relationship between eccentricity and mud-cement density difference in cement displacement process, the flow characteristics for non-Newtonian fluids involved in the laminar displacement inside an eccentric annulus are analyzed with fluid mechanics theory. An optimal density difference criterion is established based on the Herschel–Bulkley fluid model, which can be used to theoretically determine the optimum density difference yielding an optimal cement displacement performance. Numerical simulations are performed with a CFD software to investigate the influence of mud-cement density difference on displacement performance under different eccentricities in highly deviated wells. The results indicate that there is an optimal density difference which can provide the best displacement efficiency at given inclination and eccentricity under laminar flow conditions. The good agreement, between the optimal density differences calculated by the optimal density difference formula and CFD numerical simulations, confirms the validity of the optimal density difference criterion for determining the optimal density difference in highly deviated wells. The research results can provide a practical guide on how to design the cement slurry density and how to install centralizers at highly deviated wells under laminar flow conditions.

Production optimization of a water flooding project aims to determine the optimum production strategy for maintaining the reservoir under real-time optimal controls, and maximizing the oil production or net present value (NPV) of the project. Current production optimization method with a conventional grid-based simulator bears a high computational cost. Also, cumbersome history matching procedures are often required to build a reliable reservoir model for reducing the uncertainty of the optimized production strategies. To address the drawbacks of such conventional method, data-driven surrogate models, e.g., the correlation-based model, are developed to acquire interwell connectivity; such history-matched model can be then used for production optimization. It is noted that, however, the correlation-based models cannot handle the case where the conversion of duty occurs for some wells draining the reservoir, e.g., a production well is converted to a producer. Recently, we have developed a physics-based data-driven interwell numerical simulation model (INSIM) which can predict the production rates of individual phases and handle conversion-of-duty scenarios between any well pair. INSIM is derived by solving the material balance equation and augmenting the Buckley–Leverett theory. In this study, the INSIM is applied for the first time to optimize the production of water flooding projects. We derive and improve the INSIM by considering the active bottom or edge aquifers that are often encountered in real reservoirs. The improved INSIM can handle two types of aquifers: constant pressure aquifer and constant volume aquifer. By applying the inversion theory based on a finite-difference algorithm, we estimate the model parameters by history matching the historic production data. Subsequently, the history-matched INSIM is used for optimizing NPV of water flooding projects in both a synthetic reservoir and a real reservoir with an active aquifer. The injection rate of each injection well is treated as a tuning variable. As for the synthetic model, the simulation results show that the inversely derived model parameters are able to characterize the interwell formation properties, and the optimization result based on INSIM is in a good agreement with that obtained with the commercial simulator Eclipse 100. Similar history-matching results are also obtained when INSIM is applied to a real fracture-vuggy reservoir with an active aquifer. After production optimization of this real reservoir with INSIM, we achieve a 4% reduction in the water cut but a 20% increase in the oil production rate, which verifies the soundness of the proposed method.

This mini review provides an overview of the recent developments in the pore structure characterization of tight gas sandstones, permeability measurement techniques, and enhanced tight gas recovery techniques. Firstly, we review the various testing techniques used for characterizing pore structures of tight gas sandstones, namely, the characteristics of pore, throat and micro-cracks in tight sandstones. These techniques can be grouped into qualitative, semi-quantitative and quantitative methods. We review the capabilities of these methods as well as their resolutions in pore-throat diameter measurement. Then the descriptive theories of pore networks of tight sandstones are overviewed, with a special attention paid to the fractal theory. Secondly, the commonly used permeability measurement techniques for tight cores are discussed; these measurements techniques are unsteady-state methods that accommodate the nature of low permeability of tight sandstones. Their merits and drawbacks are provided in this review. We next elaborate on the effect of effective stress and water saturation on the gas relative permeability in tight sandstones; a consensus is found to exist that agrees on the pronounced reduction of gas relative permeability due to increasing water presence and higher effective stress. The permeability jail concept can be used to explain some field observations where there is little water or gas production. Lastly, we move on to review the enhanced gas recovery techniques including waterless fracturing and CO2-based enhanced gas recovery. Both lab experiments and field applications demonstrate that, due to the negative impact that water causes on gas-phase relative permeability, waterless hydraulic fracturing holds a large potential in effectively unlocking tight gas resources. It deserves further detailed experimental and numerical investigation as well as field studies. In addition, CO2 injection into tight gas formations is an important technology that is worth of consideration by both industry and governments due to its promising potential for enhancing CH4 recovery as well as sequestrating CO2 into depleted tight gas formations.

We investigate the natural gas flow behavior in the Dengying carbonate reservoir of Gaoshiti-Moxi Block in China. Outcrops observation, petrophysical properties measurement, and formation micro-resistivity image logging (FMI) all show that the vugs distribute in a stratified manner with characteristic length ranging from 0.2 to 4 cm. The horizontal permeability is significantly larger than the vertical permeability due to the stratified distribution of vugs and fractures. We build a representative conceptual reservoir model to describe this fracture-vuggy type carbonate reservoir. Both Darcy equation and Stokes-Brinkman equation are applied to simulate natural gas flow in this type of reservoir. Simulation results show that natural gas mainly flows along the free channel formed by low-dip fractures and flat ellipsoid vugs. Compared with the Darcy method, the Stokes-Brinkman method provides a more accurate prediction of gas flow behavior in the fracture-vug carbonate reservoir.