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SAGD is an effective technology that was devised for the development of oil sand. However, nowadays, most research is focused on the two-dimensional (2D) vertical profile, which ignores the non-uniformity of steam along the horizontal well occurring in an oilfield. In this paper, based on the properties in MacKay River oil sands, an experimental device for SAGD is well-designed to investigate steam-chamber expansion along the horizontal well. Then, based on experimental results, a new 3D mathematical model considering steam non-uniformity was established to predict production performance and steam-chamber expansion. Next, the calculated production performance and steam-chamber evolution were compared with numerical data to verify the accuracy of the model. Finally, the model was compared with previous models to assess its quality. Results show the following. (a) The steam distribution along the horizontal direction is non-uniform; even the preheating of SAGD is uniform using the modified pre-heating method, which, when switched to formal SAGD production, also presents the same non-uniform steam distribution. (b) The comparisons reveal that the proposed 3D model is reasonably more accurate than previous models in predicting cumulative oil prediction and steam-chamber expansion. (c) Factors influencing steam distribution along the horizontal well are also discussed, and it is believed that steam quality is the deciding factor that determines the degree of steam non-uniformity.

In recent years, analysis of flowback data has provided an early opportunity to evaluate key fracture parameters (e.g. fracture permeability and fracture volume) in unconventional reservoirs. A combination of diagnostic plots, straight-line methods and simulation model history-matching techniques have been used for this purpose. For many shale gas wells, immediate gas and water production occurs on flowback. In this paper, a novel method is developed and demonstrated for analysis of water data during two-phase (gas + water) flowback and early-time production of shale gas wells. In previous studies, it has been demonstrated that, during the late-time water flow period, the water phase exhibits boundary-dominated flow (BDF) characteristics due to the limited volume of water in fractures or surrounding matrix. The gas phase exhibits transient linear flow (TLF) characteristics within matrix, which is one of the first flow-regimes typically observed after flowback during online production. By introducing a new pseudotime with a modified total compressibility, the water flow equation during two-phase (gas + water) flow period is linearized. Accordingly, a modified flowing material balance (FMB) equation is developed for analyzing water boundary-dominated flow which considers water relativity permeability and the saturation- and pressure-dependent total compressibility. Thus, a novel method is developed by combination of the water FMB equation and an iteration technique, to estimate the facture half-length and fracture permeability during flowback of shale gas wells. The approach is validated using several numerically-simulated cases. Results show that the accuracy of the new method is influenced by the pressure and saturation gradient in the fracture. With an increase in fracture permeability, the calculated fracture parameters become very close to the expected values. The calculated fracture half-length starts to deviate from the expected values with an increase in fracture half-length. However, the derived fracture permeability values are in excellent agreement for all cases studied. The matrix permeability has little effect on the calculated fracture parameters (half-length and permeability). Although there are some deviations between the interpreted and excepted values, both the values generally agree within 5%. Finally, practical application of the method is demonstrated using a Marcellus Shale well in northeast US north-east and a Changning Shale well in southwest China. The new techniques demonstrate the importance of accounting for phase relative permeability and correcting total compressibility, even when the gas phase dominates the flowback period.

In this paper, a novel model is proposed to study the variable mass flow process in a long horizontal well and to predict the distribution of thermophysical properties along the horizontal wellbore. First, a physical simulation device is designed to carry out a steam-injection experiment. Second, considering both the uneven distribution of steam and the effect of wellbore stock liquid, a steam-absorption model and a pressure drop model are proposed to predict the distribution of steam and pressure along the horizontal wellbore. Third, the effects of different parameters on steam distribution are analyzed in detail. The results indicate that: (1) an uneven employment phenomenon exists along the wellbore; (2) the pressure distribution along the wellbore is higher when wellbore stock liquid is taken into consideration; (3) the length of the unemployed section along the wellbore increases with an increase in the wellbore stock liquid viscosity; (4) the length of the unemployed section along the wellbore decreases with an increase in the steam injection rate; and (5) the reasonable wellbore length can prevent an unemployed section along the wellbore. This paper presents a basic reference for engineering for parameter optimization as well as for the prediction of steam distribution along the horizontal wellbore.

Deeply-buried and high-bitumen-content crude oil is one of the most important energy resources. Currently, Steam- and Solvent-Assisted Gravity Drainage (SSAGD) is an attractive, but a high-cost and high-carbon-emitting method for exploiting this type of resource. In order to evaluate the greenhouse gas (GHG) emission and economic performance of SSAGD, it is critical to predict the energy efficiency and solvent retention in the steam chamber. However, the fluid property profiles inside the steam chamber, which are directly related to energy efficiency and solvent retention, have been rarely investigated. In this work, a semi-analytical model is developed for examining the property distributions within the steam chamber, considering the complex interaction of energy and mass transfer along with the effects of phase behavior. Subsequently, the solvent retention and energy-utilization/-saving efficiency are carefully analyzed on the basis of the calculated property profiles inside the steam chamber. The proposed method is mostly based on analytical relationships and is free from certain simplifications that may affect the calculations of energy efficiency and solvent retention in the SSAGD process. Furthermore, the optimal solvent type and injection pressure obtained with the model can reduce the GHG emission and improve the economic benefits of future SSAGD projects.

As a major technique for enhancing heavy-oil recovery, steam flooding has been used successfully at large scales around the world. Long-term indoor experiments and field trials, however, have revealed problems, such as heat loss to the overburden and a limited steam zone for steam flooding in thin heavy-oil reservoirs, which severely limit the thermal efficiency of the steam and the economic benefits of the reservoirs. Therefore, we established a set of two-dimensional sandpack models to study the steam chamber expansion characteristics of the horizontal-well solvent-enhanced steam flooding (HW-SESF) of different solvents and its influence on production performance. We established a numerical model based on the experimental parameters to simulate the solvent migration in the steam chamber and its effect on temperature, viscosity, and oil saturation profile. The results demonstrate that, compared with steam flooding, the HW-SESF strategy can effectively reduce the oil viscosity both at the front and inside the steam chamber and improve the steam-injection capability (the stronger the steam-injection capability is, the easier the steam can be injected into the model) of the horizontal injection well, which enhances displacement efficiency and enlarges the swept area of the steam chamber. For HW-SESF of light solvents, the displacement efficiency at the low water-cut production was high, and water cut increased rapidly as the steam front reached the production well. For HW-SESF of medium solvents, the period of stabilized production was long, and the recovery ratio was the highest compared with other solvents. For HW-SESF of heavy solvents, the peak oil production rate was high, and the oil production rate dropped quickly. Therefore, the HW-SESF strategy reduced the heavy-oil viscosity more effectively than conventional steam flooding, and thus the zone of the steam chamber was enlarged and the recovery ratio enhanced. Compared with light and heavy solvents, medium solvents can achieve the best results for steam chamber optimization and the highest recovery ratio; thus, it is considered the most effective method to exploit thin heavy-oil reservoirs.

The addition of hydrocarbon solvents to the steam injection, known as Solvent-Assisted Thermal Gravity Drainage (SA-SAGD), has recently been proven to be a more energy saving and environmentally friendly method for heavy oil recovery. Nevertheless, the relationship between injection parameters and heavy oil production in conventional SAGD were always introduced to analysis the performance of SA-SAGD, which makes many confusing in the interpretation. In this paper, the heat lost to the cap rock of the reservoir is determined by taking into account not only the chamber-edge velocity, but also the temperature and mass distributions inside the chamber. Besides, by implicitly characterizing the chamber-edge shape and considering heat and solvent diffusion beyond the chamber edge, the oil rate is calculated. Then, the model couples heat and mass balance equations in the whole oil sand dynamically by considering the effect of liquid pool. This comprehensive method enables us to clearly examine the relationship between the Production-Injection Ratio (PIR) and the height of liquid pool. Lastly, the new model is verified by comparing predicted results with that of numerical simulation. The results show that, the oil rate of SA-SAGD is improved by both of the diluting effect of solvent on bitumen viscosity and a more reasonable chamber shape formed by co-injection solvent with steam. In addition, although heat-loss rate of SA-SAGD is generally smaller than that of conventional SAGD, the Steam-Oil Ratio (SOR) of SA-SAGD may even higher than that of SAGD in the late period of the process if the liquid level is extremely high. Moreover, the liquid-pool height for SA-SAGD is more sensitive to the PIR than for SAGD. Accordingly, when the effect of liquid pool on the production is considered, the PIR of SA-SAGD must be selected carefully.

The multi-thermal fluid process is a new technology that was generated for the development of offshore heavy oil. It has achieved remarkable results in the development of Bohai Oilfield. However, the mechanism of enhanced oil recovery still requires further discussion. Based on the physical similarity criterion, a physical simulation experimental device was independently designed to execute laboratory experiments on different thermal recovery methods (hot water, steam, and multi-thermal fluid), after which the contents of the four components of developed heavy oil were measured and analyzed. The results of the physical simulation experiments indicated that: (1) Thermal viscosity reduction and thermal expansion are the principle mechanisms of hot water flooding; (2) Thermal viscosity reduction and steam distillation are the principle mechanisms of steam flooding, which are accompanied by a certain degree of aquathermal cracking reaction between heavy oil and steam; and (3) thermal viscosity reduction and aquathermal cracking reaction are the principle mechanisms of multi-thermal fluid flooding. Due to the synergistic effect of nitrogen and carbon dioxide, the effect of viscosity reduction by the dissolution effect and gas-water hybrid drive must also be considered. The analysis results of the four components of developed heavy oil by the different thermal recovery methods indicated that the multi-thermal fluid changed the balance of the aromatics-asphaltene-resin regime and strengthened the development degree of the asphaltene component in heavy oil, thereby improving oil recovery through the thermal/physical/chemical mechanism.

In this paper, the authors presented a novel model for estimating thermophysical properties of solvent in perforated horizontal wellbores (PHWs) considering the complex heat and mass transfer characteristics in the PHWs, so that the phase state of the fluid in hybrid solvent-steam process can be predicted. Firstly, governing equations for mass flow and pressure drop were established based on mass and momentum balance principles and the Equation of State. More importantly, implicit equations for phase changes from superheated steam and solvent to wet steam and superheated solvent, and to wet steam and solvent, were derived based on heat and mass transfer in the wellbore. Next, the mathematical model was solved using Levenberg-Marquardt Algorithm (LMA). Finally, validation and sensitivity analysis of the model were conducted sequentially. The validated results showed that, when injecting heavier solvent in the hybrid process, the temperature along the PHWs tends to stay at a high level and the solvent condenses at position far away from the toe position of the wellbore, but that of lighter solvent injection shows an opposite trend. Furthermore, to increase the temperature at toe position of the PHWs when injecting lighter solvent in the hybrid process, a higher superheat degree at the heel of PHWs is preferred, while the increased superheat degree may not help to ease condensing of heavier solvent in the PHWs. Besides, increasing the injection rate is more beneficial to reducing the solvent loss along the horizontal wellbore for both heavy and light solvent injection, than that of increasing the superheat degree at the wellbore head.

Currently, Steam-Assisted Gravity Drainage (SAGD) is the most successful commercialized method used to produce bitumen from oil sands and heavy oil reservoirs. Precise description of the steam chamber evolution is important for evaluating the economic effectiveness and Greenhouse Gas (GHG) emission of the SAGD process. In this study, the properties of MacKay River Oil Sands were used in laboratory experiments to compare the chamber evolution and production performance of SAGD under different permeability distributions. Then, a mathematical model was established to predict the steam chamber evolution and the closely related oil production and heat consumption in a heterogeneous formation. Next, the calculated production performance and steam chamber evolution were compared with measured experimental data to verify the accuracy of the model. Finally, the chamber evolution characteristics and their impacts on SAGD oil production and heat consumption are discussed in this paper for formations with different permeability distributions. The results indicate that horizontal permeability controls the evolution of steam chamber such that higher horizontal permeability may cause an obvious convex shape of the chamber edge, whereas vertical permeability has little effect on the chamber shape despite significant influence on the oil production in the early stage of SAGD. Moreover, a convex-shaped chamber interface indicates a higher production rate in the spreading stage and a lower rate in the depleting stage. In addition, this study shows that to minimize the heat consumption of the SAGD process, so that GHG emission can be curbed, a concave-like chamber shape is favorable in the early spreading stage, whereas a convex shape is better in the late spreading stage and depleting stage.

Aquathermolysis is an important approach to in situ conversion, a form of heavy oil thermal recovery technology. The aquathermolysis reaction models for high-sulfur heavy oil previously proposed by scholars are not suitable for low-sulfur heavy oil. Additionally, the essence of an aquathermolysis reaction is the change in the heavy oil composition, which cannot be characterized by existing models. To address these two problems, we established an aquathermolysis model for low-sulfur heavy oil, which can characterize the composition change. This model is based on material balance, reaction kinetics, and the Arrhenius equation and includes the aquathermolysis equation, the reaction kinetics model, and the Gaussian reaction rate model. We compared results of the modified model with an experimental model and found the following: (1) The characteristics of aquathermolysis of low-sulfur heavy oil were in accordance with its Gaussian type, (2) the model could predict the composition change of heavy oil more accurately and could more precisely predict the gas reaction rate of low-sulfur heavy oil, and (3) the model has a common applicability for low-sulfur heavy oil of different viscosities.

In this work, a large number of experiments have been carried out to study the aquathermolysis of heavy oil of different viscosities with superheated steam. First, a high-temperature and high-pressure autoclave was independently designed to carry out an aquathermolysis reaction with superheated steam. Second, the viscosities of the heavy oil samples were measured before and after the aquathermolysis reaction by an MCR 302 rheometer. Finally, both the saturates, aromatics, resins, and asphaltenes (SARA) content and the carbon number distribution of heavy oil samples before and after the aquathermolysis reaction were determined by chromatography. The experimental results show the following: (1) The higher the content of resins and asphaltenes, the longer is the reaction time for aquathermolysis equilibrium. (2) As for different viscosity oil samples, the starting temperature for aquathermolysis is different; however, the reaction temperature for aquathermolysis equilibrium is the same. (3) The cracking of r...

The effects of supercritical CO2 (scCO2) on polymer chains’ mobility and graphene nanoplatelets (GNPs) exfoliation and distribution in a microcellular foaming process are investigated by the molecular dynamics (MD) simulations and experiments. The results of MD simulations and visualization analysis confirm that the synergistic effect of scCO2 molecules and polystyrene (PS) chains is beneficial for them to penetrate into the interlayer of GNPs during the scCO2 treatment at high saturation pressure. The scanning electron microscope images show that some cells exist in the interlayer of GNPs in the foam fabricated in the highest saturation pressure and shortest depressurization time. With foaming in different depressurization time, the growing cells facilitate the movement of GNPs after their exfoliation, leading to alignment around the cells. As compared to large diameter GNPs, the GNPs with small diameter rearrange easily and distribute more homogeneously due to lower resistance of GNPs’ movement.

With the increasing of clean energy demands and the maturing of shale gas extraction technology, multiple fractured horizontal well (MFHW) has become the most key technology for shale gas development. After hydraulic fracturing, fracture networks, which consist of natural fractures, hydraulic fractures and secondary fractures, are formed around the wellbore. Compared to conventional gas reservoirs, shale gas reservoirs are characterized by the complex fracture networks and gas adsorptions in shale matrix. Therefore, it is essential to propose a new productivity evaluation method for shale gas wells to handle these characteristics. In this paper, to account for special characteristics of MFHW, a complex fracture model for shale gas reservoirs is established. With the new method, shale reservoirs are depicted by De Swaan dual porosity model, where the secondary fractures and hydraulic fractures are characterized by discrete units. Therefore, together with micro-seismic data, fracture networks can be exactly described using this new model. With a well-depicted facture network, Green function and superposition method are then adopted to model the flow in the reservoir, and finite difference method is used to solve the equations of one-dimensional flow in fracture system. Besides, to deal with the complex flow in the fracture intersection, star-delta transformation is applied Finally, the equations of reservoir and fracture system, the solution in Laplace domain is obtained, which can then be transferred to real domain using the Stehfest algorithm. Comparisons were made between the results of the proposed model and that of a numerical model accomplished by commercial simulator Eclipse for a specific case to verify the accuracy of the model. Results show that the semi-analytical method is more efficient than numerical method by reducing the computing time without losing accuracy. Moreover, the semi-analytical productivity evaluation method can describe fracture networks more exactly. Then, a field case from Sichuan Basin of China is applied in the analysis. The results shows that desorption gas takes up 10%-30% of the total production in this case. Besides, the effects of storage capacity ratio and inter-porosity flow coefficient on type curves were analyzed based on the production decline curves. In addition, pressure profiles of different production times are obtained by the superposition of pressure potential.

A thin layer of polydopamine (PDA) was coated on the surface of cellulose nanocrystals (CNCs) by the self-polymerization of dopamine (DA) in water to improve the hydrophilicity and lipophilicity of CNCs. Then, the CNCs coated with PDA (PDA@CNCs) were blended with pore forming agent and cellulose acetate (CA), and the CA composite membrane reinforced by PDA@CNCs (PDA@CNCs/CA) was prepared by solution phase transformation method. The effects of PDA@CNCs content on the filtration performance, antifouling ability and mechanical properties of the composite membrane were studied. The results show that adding a small amount of PDA@CNCs can significantly improve the filtration capacity, antifouling performance and tensile strength of CA membrane. When the content of PDA@CNCs was 4 wt%, the hydraulic permeability, flux recovery ratio and tensile strength of PDA@CNCs/CA composite membrane increased by 33%, 15% and 76%, respectively. Simple DA modification improves the lipophilicity and dispersion of CNCs, enhances the binding force between CNCs filler and CA matrix, and improves the performance of CA composite membrane, thus widen the industrial application of CA materials, and shows a broad application prospect in the field of biological separation membrane and water treatment membrane.

The large uncertainty in fracture characterization for shale gas reservoirs seriously affects the confidence in making forecasts, fracturing design, and taking recovery enhancement measures. It is of significance to make the most of multiple data in fracture characterization, including the measurements of hydraulic fracturing treatment, core, microseismic, production data, etc. Besides, handling the complex fracture networks (CFNs) explicitly is demanded in large-scale field case studies. This paper presents an efficient method to characterize the complex fracture networks (CFNs) and reduce the uncertainties by integrating stochastic CFNs modeling, reservoir simulation, and assisted history matching. In CFNs modeling, the geometry of CFNs is generated stochastically constrained by the measurements of hydraulic fracturing treatment, core, and microseismic data, and a stochastic parameterization model is used to generate an ensemble of initial realizations of the stress-dependent fracture conductivities. To efficiently simulate the discrete fractures in field cases, the edge-based Green Element Method (eGEM) is modified by applying a steady-state fundamental solution and the technique of local grid refinement (LGR). Assisted-history-matching based on EnKF is implemented to calibrate the CFNs models and further quantify the uncertainties. The proposed method is applied to a field case from a multi-fractured horizontal shale gas well. The results show that the computation of the modified eGEM is much cheaper than the original eGEM when the steady-state fundamental solution and the technique of LGR are applied. Besides, acceptable precision can be obtained with relative coarse grids, for example, 50 m primary grids and 25 m refined grids near the fractures can be used in the test case. These advantages make the modified eGEM quite efficient in assisted history matching of large-scale field applications. The history matching results and EUR distributions show that the uncertainties are significantly reduced after 5 steps assimilation, and good results can be obtained after 10 steps assimilation. The distribution ranges of the matrix permeability and porosity are significantly narrowed down after history matching, while the matrix compressibility is hard to be determined because the rock compressibility is so small comparing to gas compressibility that gas production is not sensitive to it. The results also show that only part of the fractures are well-propped because only the fractures in a certain range of the wellbore are with good properties, that is high initial fracture conductivities and low conductivity moduli.

Steam injection can significantly reduce the viscosity of heavy oil. In addition to physical effects, chemical reactions such as aquathermolysis also make a difference. However, the current numerical simulators do not include the characterization for the aquathermolysis reactions, making it unable to analyze directly the effect of the aquathermolysis reactions using numerical simulation. To solve this problem, a basic model of aquathermolysis reactions for numerical simulation is established in this paper. After dividing the oil components reasonably, a modified chemical equation is well defined. And the pre-exponential factors and activation energies are also calculated. Afterwards, this model is implemented into the numerical simulator CMG-STARS, and the results with and without the model are compared, to analyze the mechanisms of aquathermolysis reaction for increasing production. The results indicate: (1) the numerical simulation results with the aquathermolysis reaction model are more consistent with field results (2) aquathermolysis reactions can further reduce the viscosity of heavy oil, increase oil production, and reduce the water saturation near the well bore area.

This paper provides a comprehensive model for the flow behavior of a two-zone system with discrete fracture network. The discrete fracture network within the inner zone is represented explicitly by fracture segments. The Laplace-transform finite-difference method is used to numerically model discrete fracture network flow, with sufficient flexibility to consider arbitrary fracture geometries and conductivity distributions. Boundary-element method and line-source functions in the Laplace domain are employed to derive a semi-analytical flow solution for the two-zone system. By imposing the continuity of flux and pressure on discrete fracture surfaces, the semi-analytical two-zone system flow model and the numerical fracture flow model are coupled dynamically. The main advantage of the approach occurring in the Laplace domain is that simulation can be done with nodes only for discrete fractures and elements for boundaries and at predetermined, discrete times. Thus, stability and convergence problems caused by time discretization are avoided and the burden of gridding and computation is decreased without loss of important fracture characteristics. The model is validated by comparison with the results from an analytical solution and a fully numerical solution. Flow regime analysis shows that a two-zone system with discrete fracture network may develop six flow regimes: fracture linear flow, bilinear flow, inner zone linear flow, inner zone pseudosteady-state flow, outer zone pseudoradial flow and outer zone boundary-dominated flow. Especially, local solutions for the inner-zone linear flow have the same form with that of a finite conductivity planar fracture and can be correlated with the total length of discrete fractures and an intercept term. In the inner zone pseudosteady-state flow period, the discrete fractures, along with the boundary of the inner zone, will act as virtual closed boundaries, due to the pressure interference caused by fracture network and the mobility contrast of the two zones. The dimensionless fracture conductivity of the fracture network determines the characteristics of the bilinear flow and the inner zone linear flow. The mobility ratio, M, and storability ratio, Fs, primarily influence the flow behavior of the middle to later time. For a larger M, the ending time of the inner zone pseudosteady-state flow will be advanced and the beginning time of the outer-zone pseudoradial flow will be delayed. And the larger M also results in increasing of the values of the transient responses in these two periods. Duration of the outer-zone pseudoradial flow becomes longer, as Fs increases; the development of the outer-zone boundary-dominated flow is therefore postponed. Finally, idealization of dual-porosity model for the two zones will introduce two dips on the pressure derivatives on the log/log plot. Depending on the interporosity flow parameter, the time of the two dips varies. However, the dips are not very appreciable for the transient dual-porosity model, when the permeability of matrix system or fracture density is relatively high.

Summary In a multiwell pad, the chance of interwell communication increases because of the creation of primary and secondary fractures during hydraulic-fracture stimulation. The flow behavior associated with communicating wells is significantly different from that of a single isolated well, because of interplay of flow caused by the interconnected fractures, complex connections, and multiple production conditions. The main purpose of this paper is to develop a rigorous and efficient flow model and quantify flow characteristics of multiple pad wells communicating through primary and secondary fractures. In the model, matrix and primary- and secondary-fracture flows are captured. Fractures are explicitly represented by discrete segments. The Laplace-transform finite-difference (LTFD) method is used to numerically model fracture flow, with sufficient flexibility to consider arbitrary fracture geometries and fracture-conductivity distributions. The analytical matrix-flow model, derived with the line-source function in the Laplace domain, is dynamically coupled with the fracture-flow model, by imposing the continuity of pressure and flux on the fracture surface. Thus, a hybrid model in the Laplace domain is constructed. The main advantage of the solution occurring in Laplace domain is that computations can be performed at predetermined, discrete times, and with grids only for fractures. Thus, stability and convergence problems caused by time discretization are avoided, and the burden of gridding and computation is decreased without loss of important fracture characteristics. The model is validated through comparison with a fully numerical simulator and a semi-analytical model. Detailed flow-regime analysis reveals that pressure interference caused by communication significantly alters the flow signature compared with single (isolated) wells. Before interference, the communicating wells behave as single isolated wells, and will exhibit a fracture linear-flow period and possibly even a matrix linear-flow period. After interference, the flow behavior of the system will vary largely with different production strategies. When the communicating wells all operate under the constant-rate condition, the transient responses of the wells will gradually merge to develop another matrix linear-flow period. If the wells are operated under the constant-bottomhole-pressure (BHP) conditions, the response deviation caused by interference will increase with production; therefore, one of the wells will undergo a rate loss. The results of a sensitivity analysis for a two-well system demonstrate that the time to well interference is primarily determined by secondary-fracture conductivity, number of connections, and communicating-well operating conditions. With larger contrasts in these properties, interference time is accelerated. However, for different production strategies, the effects on the flow behavior after interference are variable.

Recently, steam assisted gravity drainage (SAGD) has been widely adopted in thermal recovery for heavy oil. However, challenges remain in SAGD development: the close distance between injector and producer makes it easy to cause steam breakthrough, which means lower thermal efficiency as well as higher investment. It is generally acknowledged that there is a liquid level existing between the injector and producer, a reasonable liquid level could prevent steam from being produced directly. The existence of liquid level generates a temperature difference between two wells, i.e., subcool. Subcool has generally been used to describe liquid level in practice and in many researches, yet it is inaccurate. In order to characterize the liquid level precisely, it is necessary to fully clarify the relationship among subcool, liquid level and pressure difference between injector and producer. By analyzing the features of subcool and pressure difference shown in SAGD experiments, it is found that the value of subcool may be not directly relevant with the distance between injector and producer, considering the huge difference between experiments and the measured data from actual oilfield. Correspondingly, liquid level is supposed to be treated as a dimensionless variable, to be specific, named as dimensionless liquid level, defined as liquid level divided by the distance between two wells. Afterwards, over 40 cases of CMG numerical simulations are run to investigate the liquid levels with different injector-producer distances and different subcools. Based on the analysis of simulation results, the dimensionless liquid level increases with subcool, while for a given subcool, dimensionless liquid level is inversely proportional to pressure difference between injector and producer. Accordingly, liquid level could be accurately controlled under a given subcool and pressure gradient, which is applicable and be of great significance for the SAGD operation on the field.

This paper provides a semi-analytical model to analyze the transient responses of multifractured systems with discrete secondary fractures in unconventional reservoirs. The model idealizes the stimulated reservoir volume as two regions: a primary hydraulic-fracture and discrete secondary fractures. Transient pressure and derivative responses are obtained by coupling an analytical model for matrix flow and a numerical model for fracture flow. This approach can consider the fracture characteristics in detail. For example, the discrete secondary fractures may interconnect the primary hydraulic-fracture with different inclination, nonuniform fracture spacing and varying conductivity. The semi-analytical model was verified in comparison with the results of a fully numerical simulation model. Transient flow behavior of the system was analyzed in detail. The study has shown that a multifractured system with discrete secondary fractures may exhibit four flow regimes: bilinear flow, fluid feed flow, matrix linear flow and pseudosteady-state flow. In the fluid feed flow period, the secondary fractures act as supply sources to feed the primary hydraulic-fracture to generate a dip on the type curves. Local solutions for the matrix linear flow are similar to that for a finite conductivity vertical fracture and can be correlated with the ratio of the total length of the secondary fractures to that of the primary hydraulic-fracture and an intercept term. With the increasing of number of secondary fracture, the ending time of the bilinear flow will be advanced and the fluid feed flow period will come earlier. The dimensionless secondary fracture length determines the slope of the straight line of the matrix linear flow on square-root-dimensionless-time plot. As the secondary fracture inclination decreases, the duration of the matrix linear flow period is shortened and the beginning time of the pseudosteady-state flow period is delayed. In addition, the secondary fracture conductivity affects the depth of the dip and the beginning time of the matrix linear flow period. However, the influence is not appreciable on the log/log graph.

Polypropylene (PP) nanocomposites reinforced with different types of graphene nanoplatelets (GNPs) and their hybrid systems are prepared via melt extrusion. On the basis of experimental analysis and simulation, the factors of thermal property of the PP/GNPs nanocomposites, including GNPs size, weight fraction and proportion of various sizes, are systematically investigated. At high GNPs content (9,12 wt %), GNPs are widely distributed in PP matrix and the thermal paths are basically formed. The thermal conductivity of composites is determined by the size and thermal properties of GNPs. At low GNPs content (6 wt %), for single system, the larger diameter with moderate distribution would be more conducive to achieve the higher thermal conductivity, indicating the formation of thermal paths dramatically affects the thermal conductivity. For hybrid system, the PP filled with medium and small diameter GNPs obtains the highest thermal conductivity when the ratio of medium diameter GNPs to small diameter GNPs is 8:2, and is 23.8% higher than the single system of PP filled with small diameter GNPs. More precisely, the small diameter GNPs play a role in connecting the scattered medium diameter GNPs, as mass thermal paths are formed. This shows that the distribution state by combining the synergistic effect of various GNPs significantly affects the thermal conductivity of PP/GNPs nanocomposites. Moreover, a numerical simulation dealing with the synergistic effect of different GNPs, is developed on the thermal conductivity of GNPs-reinforced PP matrix. The heat flux images demonstrate the existence of synergistic effect between different sizes of GNPs.

When the heterogeneous bottom water reservoirs are developed by horizontal wells, the fingering of the bottom water always results in water breakthrough too early. With ICD water control completion, the bottom water can rise uniformly. The key of this approach is to select suitable ICD equipment. Therefore, aiming for inflowing uniformly from horizontal well to wellbore, optimization model of horizontal wells with ICD water control completion in bottom water reservoirs was established according to the law of equivalent percolation resistance and with the consideration of the coupling of seepage in near-wellbore area, ICD equipment and flow within the wellbore. Then, suppose the well is produced at a constant fluid rate, a flowchart of ICD optimization design is presented taking nozzle type of ICD for example and makes some experimental calculations. The results show that the model is reliable and practical, and the optimized ICD water control completion can make the horizontal well produce fluid uniformly and bottom water rise uniformly and therefore increased cumulative oil production and enhanced oil recovery. The model provides the theory base and design flowchart for horizontal wells with ICD water control completion in bottom water reservoirs. It also can guild for the actual production of oilfield.

Background Surface-enhanced Raman scattering (SERS) has been deployed in the analysis of food at solid and aqueous states. However, its capability has not been fully explored in headspace profiling. Objective To develop an innovative SERS method for analyzing headspace volatile compounds in foods. Methods A volatile-capture device was developed by depositing a film of silver nanoparticles in a vial cap to capture the volatiles released from a model flavor compound (garlic). Results SERS peaks at 1632, 1400, 1291, 1191, 731, and 577 cm−1 were identified in the headspace of the garlic sample, which was representative of an organosulfur compound (diallyl disulfide), and its concentration was determined at 135 ppm, which was comparable to the value determined using GC. Preparation and analysis could be carried out in Conclusions The SERS method was able to quantify the concentration of diallyl disulfide in the headspace of a raw garlic ethanolic extract. Compared to GC, the SERS method had a much shorter analysis time and simpler sample preparation procedure than GC when analyzing large numbers of samples. Highlights The innovative “mirror-in-a-cap” substrate was simpler and faster than other reported SERS substrates used for this purpose. Additionally, SERS has much better portability and the potential for real-time monitoring of changes in the garlic headspace concentration during manufacturing and processing.

The large uncertainty in fracture characterization for shale gas reservoirs seriously affects the confidence in making forecasts, fracturing design, and taking recovery enhancement measures. This paper presents a workflow to characterize the complex fracture networks (CFNs) and reduce the uncertainty by integrating stochastic CFNs modeling constrained by core and microseismic data, reservoir simulation using a novel edge-based Green element method (eGEM), and assisted history matching based on Ensemble Kalman Filter (EnKF). In this paper, the geometry of CFNs is generated stochastically constrained by the measurements of hydraulic fracturing treatment, core, and microseismic data. A stochastic parameterization model is used to generate an ensemble of initial realizations of the stress-dependent fracture conductivities of CFNs. To make the eGEM practicable for reservoir simulation, a steady-state fundamental solution is applied to the integral equation, and the technique of local grid refinement (LGR) is applied to refine the domain grids near the fractures. Finally, assisted-history-matching based on EnKF is implemented to calibrate the DFN models and further quantify the uncertainties in the fracture characterization. The proposed technique is tested using a multi-stage fractured horizontal well from a shale gas field. After analyzing the history matching results, the proposed integrated workflow is shown to be efficient in characterizing fracture networks and reducing the uncertainties. The advantages are exhibited in several aspects. First, the eGEM-based Discrete-Fracture Model (DFM) is shown to be quite efficient in assisted history matching of large field applications because of eGEM’s high precision with coarse grids. This enables simulations of CFNs without upscaling the fractures using continuum approaches. In addition, CFNs geometry can be generated with the constraints of core and microseismic data, and a primary conductivity of CFNs can be generated using the hydraulic fracturing treatment data. Moreover, the uncertainties for CFNs characterization and EUR predictions can be further reduced with the application of EnKF in assimilating the production data. This paper provides an efficient integrated workflow to characterize the fracture networks in fractured unconventional reservoirs. This workflow, which incorporated several efficient techniques including fracture network modeling, simulation and calibration, can be readily used in field applications. In addition, various data sources could be assimilated in this workflow to reduce the uncertainty in fracture characterization, including hydraulic fracturing treatment, core, microseismic and production data.

Rh-catalyzed reactions of N-alkyl anilines with internal alkynes at room temperature have been developed using an in situ generated N-nitroso group as a transient oxidizing directing group. Due to mild reaction conditions, this method enabled synthesis of a broad range of N-alkyl indoles, including even two indole-based medicinal compounds. Our work disclosed the feasibility of the transient oxidizing directing group strategy in C–H functionalization reactions, which possesses the potential to enhance overall step-economy and impart new reactivity patterns to substrates.

Abstract Problems like small sweeping volume, short stimulating period and poor producing performance challenge the effectiveness of single horizontal well CO2 huff ‘n’ puff in the fault-block reservoirs with edge water. The effect of CO2 volume on multiple horizontal wells CO2 huff ‘n’ puff has been studied in this paper to investigates the feasibility of CO2 huff ‘n’ puff by horizontal well group. Studies on both isothermal property of CO2 and the CO2-crude oil properties under reservoir conditions offer the possible basis for this work. A 3D edge water model with three horizontal wells, which was designed and produced according to geological data, was used to simulate the process of CO2 huff ‘n’ puff by horizontal well group. Subsequently, experiments were carried to investigate the impact of CO2 volume on water control and oil stimulation. Results show the CO2 isothermal compressibility under certain pressure make it possible to inject gas with relatively low energy loss and to enlarge sweeping volume. Meanwhile, with more CO2 mole composition in the crude oil, the mixture intends to be more flowable. Consequently, as the gas volume increases from 0.07PV to 0.13PV, the comprehensive water cut rate drop from 0.72% to 5.93%, and both oil and gas production increase accordingly. However, the gas use ratio dwindles as the volume exceeds 0.13PV.

A major concern with hydraulic fracturing in tight formation is the fracturing fluid-induced formation damage (FFIFD) for the high capillary pressure and the presence of water-sensitive clays. Analytical and semi-analytical models are good choices for formation damage evaluation comparing to computationally expensive numerical simulations, particularly in early times when there is limited information about the formation properties. However, the effects of FFIFD and two-phase flow are not addressed in many analytical models. This paper presents a semi-analytical model for this problem with the consideration of both FFIFD and two-phase flow. First, the physical model and mathematical fundamentals of the model are presented. The triple-porosity model is modified to capture the formation damage caused by fracturing fluid. A low permeability fracturing fluid invasion layer (FFIL) is used to characterize leakoff caused clay swelling and polymer adsorption in the matrix pores, and two-phase flow is assumed in the fractures to capture the choking effects. The analytical solution is obtained in the Laplace domain, and a successive iteration is used to update the dynamic parameters by coupling the flowing material balance equations. Then, the commercial numerical simulator Eclipse is used to validate the precision of the semi-analytical model, and several synthetical cases are presented to study the effects of two-phase flow, and the permeability and width of FFIL on gas production rate. Finally, a field case is provided to test the application of the proposed model. The main contribution of this paper is the provision of a simple yet versatile semi-analytical model for production prediction and analysis with the consideration of fracture networks, FFIFD, and two-phase flow. It serves as a good tool for making production prediction and production data analysis for hydraulically fractured tight gas wells.

In this paper, a novel model is proposed for heated radius calculation and production performance analysis of cyclic superheated steam stimulation (CSHSS) wells. Firstly, the heated area after superheated steam (SHS) injection is distributed into three sub-areas whose heated radius are derived respectively. Next, a semi-analytical model for production performance analysis is proposed by using time discretization technique. After validation of the proposed model, production performance of CSHSS wells is analyzed in detail. The results indicate that the positive effect of residual heat on cyclic productivity improvement is offset by pressure drop and oil saturation drop. The constant pressure production (CPP) is found to be only a special case of the constant oil production (COP). Both of the cumulative oil production and thermal efficiency increase with the increase of constant oil production rate (COPR). The higher the COPR, the steeper the average pressure curve at its early stage. This paper presents basic reference for engineers in heated radius evaluations after SHS injection as well as performance estimations of CSHSS wells.

Shale gas reservoirs are characterized by gas adsorption in matrix and complex fracture networks after hydraulic fracturing stimulation, and the properties of which cannot be measured through existing methods. Many linear flow models have been proposed to interpret these properties, however the nonlinearity of desorption and gas compressibility is often neglected when analyzing production data. Moreover, the production rate and bottom hole pressure (BHP) are usually variable, while the control mode in analytical models is either at constant production rate or BHP. Therefore, the nonlinearity should be considered when interpreting production data, and the problem of variable rate and BHP remains to be solved. In this paper, a comprehensive method for analysis of production data with variable rate for multistage fractured horizontal wells in shale gas reservoirs has been put forward, in which the nonlinearity of desorption and compressibility is considered. The classical tri-linear flow model is modified by incorporating desorption in the matrix. New type curves are developed incorporating normalized rate, integration of the rate and derivative of the integration against pseudo-time. To analyze production data with nonlinear desorption and compressibility, modified material balance equation and material balance time are applied to process production data. If the production data of a real shale reservoir is given, the half-length and the permeability of the hydraulic fractures, the permeability of the stimulated reservoir volume can be determined with this method. Finally, a field case is used to demonstrate this method for production data analysis.

The aim of this work is to present a comprehensive mathematical model for estimating oil drainage rate in Steam-assisted gravity drainage (SAGD) process, more importantly, wellbore/formation coupling effect is considered. Firstly, mass and heat transfer in vertical and horizontal wellbores are described briefly. Then, a function of steam chamber height is introduced and the expressions for oil drainage rate in rising and expanding steam chamber stages are derived in detail. Next, a calculation flowchart is provided and an example is given to introduce how to use the proposed method. Finally, after the mathematical model is validated, the effects of wellhead steam injection rate on simulated results are further analyzed. The results indicate that heat injection power per meter reduces gradually along the horizontal wellbore, which affects both steam chamber height and oil drainage rate in the SAGD process. In addition, when production time is the same, the calculated oil drainage rate from the new method is lower than that from Butler’s method. Moreover, the paper shows that when wellhead steam injection rate is low enough, the steam chamber is not formed at the horizontal well’s toe position and enhancing the wellhead steam injection rate can increase the oil drainage rate.

Summary The technology of steam-assisted gravity drainage (SAGD) with a dual horizontal well pair has been widely adopted in thermal recovery for heavy oil in recent years. However, the close distance between injector and producer makes it easy to cause steam breakthrough, which means lower thermal efficiency as well as higher investment. It is generally acknowledged that there is a vapor-liquid interface between the injector and producer. A suitable liquid level is desired to prevent steam from being produced directly; otherwise, an overly high liquid level would influence oil productivity or even submerge the injector. The existence of a liquid level generates a temperature difference (i.e., subcool) between two wells. Subcool has widely been used to characterize the liquid level in research, yet it is inaccurate. Further studies are still needed on how to maintain a suitable and stable liquid level in SAGD development. In addition to the heat-loss model and geometric features of the steam chamber (SC), mass conservation, energy conservation, and gravity-drainage theory are used to develop a multistage mathematical model for liquid-level characterization during the SAGD process. The new model is validated against both field data and simulation results. On the basis of this model, an optimal production/injection ratio (PIR) at different times could be calculated to maintain a stable liquid level above the producer, avoiding steam channeling accordingly. Besides, the model can also be used to predict optimal steam-injection rate under constant-pressure injection. Other SAGD dynamic performance predictions, such as SC expansion speed, could also be derived from this model. In addition, recommendations for liquid-level adjustment are offered on the basis of field conditions.

Summary This paper presents a semi-analytical model for the flow behavior of naturally fractured formations with multi-scale fracture networks. The model dynamically couples an analytical dual-porosity model with a numerical discrete fracture model. The small-scale fractures with the matrix are idealized as a dual-porosity continuum and an analytical flow solution is derived based on source functions in Laplace domain. The large-scale fractures are represented explicitly as the major fluid conduits and the flow is numerically modeled, also in Laplace domain. This approach allows us to include finer details of the fracture network characteristics while keeping the computational work manageable. For example, the large-scale fracture network may have complex geometry and varying conductivity, and the computations can be done at predetermined, discrete times, without any grids in the dual-porosity continuum. The validation of the semi-analytical model is demonstrated in comparison to the solution of ECLIPSE reservoir simulator. The simulation is fast, gridless and enables rapid model setup. On the basis of the model, we provide detailed analysis of the flow behavior of a horizontal production well in fractured reservoir with multi-scale fracture networks. The study has shown that the system may exhibit six flow regimes: large-scale fracture network linear flow, bilinear flow, small-scale fracture network linear flow, pseudosteady-state flow, interporosity flow and pseudoradial flow. During the first four flow periods, the large-scale fracture network behaves as if it only drains in the small-scale fracture network; that is, the effect of the matrix is negligibly small. The characteristics of the bilinear flow and the small-scale fracture network linear flow are predominantly determined by the dimensionless large-scale fracture conductivity. And low dimensionless fracture conductivity will generate large pressure drops in the large-scale fractures surrounding the wellbore. With the increasing of the interporosity flow parameter, flow exchange between the matrix and the small-scale fracture network will be advanced and may mask the pseudosteady-state flow period. The duration of flow exchange increases and the dip caused by the interporosity flow gets deeper with the decreasing of the storability ratio. Finally, an appropriate choice of the pseudosteady or transient dual-porosity model to idealize the small-scale fracture networks with the matrix depends entirely on a better understanding of the geological evidence supporting either model.

Summary The principal focus of this work is on pressure-transient analysis of a finite-conductivity inclined fracture connected to a slanted wellbore, on the basis of a semianalytical model. Detailed analysis of unsteady-state pressure behavior of a fully penetrating inclined fracture in an infinite-slab reservoir was provided. The study has shown that a finite-conductivity inclined fracture may exhibit five flow regimes: bilinear flow, formation linear flow, early radial flow, compound linear flow, and pseudoradial flow. The characteristics of bilinear flow and formation linear flow are predominantly determined by fracture conductivity. In the case of a low formation-thickness/fracture-half-length ratio and small inclination angle, both early radial flow and compound linear flow may be absent. Analytical solutions for transient responses during different flow regimes are similar to that for a fully penetrating vertical fracture and can be correlated with the cosine of fracture-inclination angle with consideration of permeability anisotropy. Effect of inclination angle and reservoir-permeability anisotropy on transient responses is strong, which extends to pseudoradial-flow period. Formation thickness mainly influences the middle to late flow periods. In addition, the pseudoskin factor is also investigated in detail.

In most super-heavy oil reservoirs, depletion recovery is one of the important cold recovery methods accompanied by foamy oil production. However, the inflow profiles of horizontal wells in super-heavy foamy oil reservoirs cannot be obtained by conventional methods at present. In this study, a semi-analytical model which couples the wellbore and reservoir was established to predict the inflow profile of horizontal wells in super-heavy foamy oil reservoirs with cold production method. The coupled wellbore/reservoir model is based on the prediction of the dynamic physical property parameters of foamy oil, and employs reservoir engineering methods, such as the microelement, mirror reflection, and potential function methods. The numerical solution was obtained by applying iteration method in MATLAB. Meanwhile, the model accounts for formation heterogeneity along the horizontal well that has never been considered before and pressure drop loss along the horizontal wellbore. The model was applied to a field case, and the calculation results were compared with those predicted by using the Joshi and Furui productivity formulas. It showed that the developed model led to the smallest errors from field production data, which further verifies the accuracy of the model. Moreover, sensitivity analysis is conducted by changing the permeability distribution along the horizontal well and the length of the horizontal section based on the established model. And the results are instructive for horizontal well optimization design. In short, this model is of great significance for productivity calculations, horizontal well design optimization, and production predictions of cold production with horizontal wells in super-heavy oil reservoirs.

CO2 flooding is an effective enhancing oil recovery (EOR) method that is suitable for ultra-low permeability reservoirs. Generally, high heterogeneity and natural fracture development are the major characteristic of ultra-low permeability reservoirs, which can induce serious gas channeling issues. In this study, a systematic and comprehensive gas channeling control system has been formed to enhance the mobility control and sweep efficiency of CO2 flooding in ultra-low permeability reservoirs with different degrees of heterogeneity and fracture scales. Physical models are designed and fabricated to perform the laboratory experiments for investigating the performance and applicable limits of multi-stage gas channeling control system. Experimental results indicate that continuous CO2 flooding is more suitable for applying in ultra-low permeability reservoirs compared with water flooding. CO2 flooding is a preferred EOR method applied in the homogeneous model with the permeability from 10 × 10−3 μm2 to 0.1 × 10−3 μm2 or heterogeneous model with the permeability ratio (the ratio between the permeability values of each half layer) of less than or equal to 5, whose elevated oil recovery is all more than 20%. As the permeability ratio is from 5 to 30, the primary-stage gas channeling control system is a much suitable method which depends on CO2 mobility control to improve sweep efficiency and oil production, and the oil recovery can be improved from 16.88% to 22.46%. Besides, CO2-thickener flooding can mitigate the gas channeling to some extent by controlling CO2 mobility in weakly heterogeneous models. To the permeability ratio of more than 30 or even to small-scale fracture, secondary-stage gas channeling control system can effectively reduce the flowing capacity of CO2 in the microcosmic or macroscopic small-scale gas channeling path and play a role in profile control, which improves oil recovery for more than 12%. To high permeability path and intermediate-scale or large-scale fractures, tertiary-stage gas channeling control system is selected as a blocking agent which can availably block off both macroscopic and microcosmic gas channeling path, and its elevated oil recovery is all more than 34%.

It is quite common for oil/gas two-phase flow in developing fractured carbonate oil reservoirs. Many analytical models proposed for black oil wells in fractured carbonate reservoirs are limited to single-phase flow cases and conventional methods have been the use of numerical simulations for this problem. In this approach, a novel semi-analytical method is proposed to integrate the complexities of phase change, pressure-dependent pressure-volume-temperature (PVT) properties, two-phase flow behavior, and stress-dependent fracture permeability characteristics. A dual-porosity, black oil model considering the phase change and two-phase flow is applied to model the fractured carbonate reservoirs. To linearize the model, only flow equations of oil phase are used to develop the mathematical model. Nonlinear parameters and producing gas–oil ratio (GOR) are updated with coupled flowing material balance equations, followed by a novel proposed procedure for history matching of field production data and making forecasts. The semi-analytical method is validated with a commercial simulator Eclipse. The results show that both of the production rate curves of oil and gas phase using the proposed model coincide with the numerical simulator. The results also show that the effects of pressure-dependent fracture permeability, fracture porosity, and exterior boundary on production rate are significant. Stress sensitivity influences production rate during the whole process, reducing the cumulative production. Fracture porosity influences production rate during the intermediate flow periods. The exterior boundary affects production rate mainly in the early and intermediate production periods. Finally, a field example from the eastern Pre-Caspian basin is used to demonstrate the practicability of the method. Acceptable history match is achieved and the interpreted parameters are all reasonable.

Shale gas reservoirs are characterized by gas adsorption and multiple flow mechanisms in shale matrix and complex fracture networks after hydraulic fracturing stimulation. It is of significance to capture the dynamic pressure-dependent properties, including gas PVT properties, gas desorption, flow mechanisms, and stress-dependent fracture permeability. In this paper, this problem is handled by proposing a novel Green element method, which is a good extension of the traditional boundary element method. The domain is discretized into many Cartesian grids, and boundary element method is applied to each element. Discrete fractures are flexibly handled by embedding the fractures into the background grids for the domain, and finite difference method is applied to model flow within the fracture system. The flow between the fracture system and matrix system is coupled to obtain the eventual matrix equation, and Picard successive approximation method is applied to obtain the solution of the nonlinear system. The solution of the novel Green element method is validated by the commercial simulator Eclipse for a fractured tight gas well model. A field case from Longmaxi formation in Southwestern China is used to verify the utility of the model. Moreover, the effects of nonlinear parameters on the performance of the well are analyzed. The results show that the nonlinear factors in shale gas flow model have a great impact on the eventual results of gas production forecasts, especially gas PVT properties and stress-sensitive fracture conductivity.

Steam assisted gravity drainage (SAGD) is widely applied in the exploitation of oil sand reservoirs, however, the development process is affected by complex geological conditions, wherein the interlayer has a great impact. Specifically, it has a great influence on heat and mass transfer of steam and on the effective flow of crude oil. For this reason, the characteristics of steam chamber and the production performance were investigated in detail to clarify the influence mechanism of interlayer. In this paper, based on the reservoir parameters of Long Lake oil sands, a series of numerical simulations were conducted to study the characteristics of SAGD process with interlayers. First of all, the numerical simulation method was used to study the influence mechanism of interlayer on heat and mass transfer. Then, based on the above analysis, we reclassified the production stages. Finally, we completed a series of numerical simulations with different parameters of interlayer to determine the influence level of main factors. The results of temperature profile show that the upper zone of the interlayer is mainly heated by heat conduction, whereas the area far from the interlayer is heated by the coupling effect of heat conduction and heat convection, hence, the steam chamber above the interlayer develops slower and the steam chamber in the area without interlayer develops faster. At the same time, it can be seen from the oil saturation profile that a dead oil zone is formed near the formation just above the interlayer. In addition, the production stage is no longer the classic "three-stage", due to the interlayer, the oil production rate is fluctuating, appearing peak production. Finally, we summarized the regular of the influence of each parameters and determined the main parameters, we considered the location, size, porosity, permeability, and thermal conductivity of interlayer comprehensively, the results show that the influence of thermal conductivity is smaller than other parameters.

Steam channeling is an important factor affecting the steam flooding, for thin heavy oil reservoirs, the steam overriding in the vertical direction is not as severe as the thick heavy oil reservoir, and often can form a regular shape of the steam front which can directly reflect the extent of steam overriding. it also can determine the steam swept volume, steam breakthrough time. Therefore, the study of steam front is of great significance. In this paper, a series of works are conducted to study the characteristics of steam front of horizontal steam flooding. Firstly, the equation of steam front and the equation of motion are established. Then, coupled with energy conservation equation and mass conservation equation, a comprehensive model is established. The model is solved with method of characteristics and the predicted results are compared against field data and previous models. The results show that: (a). The new model is applicable to predict different shapes of the steam front according to the production conditions. (b). The comparison between experimental results and model results showed that this new model can predict the steam front well. (c). The comparison of steam front among different shapes indicated that linear-shape was the best, followed by the concave-shape, and the convex-shape was the worst, usually causing severe steam overriding and the severity will increase over time, the development effect can be improved by forming a proper shape of steam front.

Multi-stage fractured horizontal wells play an important role in developing shale gas reservoirs by significantly improving productivity. By considering fracture networks, gas desorption, stress-sensitive fracture permeability, and pressure-dependent gas PVT properties, an analytical model is developed for shale gas wells. Fracture networks are handled based on transient linear flow, gas desorption is handled by defining a new total compressibility, stress-dependent hydraulic fracture permeability is handled by variable substitution, and pseudo-pressure and pseudo-time are used to handle pressure-dependent PVT properties. After obtaining the solution of the linearized model, a material balance method and successive substitution iteration procedure are proposed to convert the pseudo-time into real time and calculate the production contribution from gas desorption. The results show that induced fractures also have a great impact on the production of the well. Production contribution from free gas and adsorbed gas could be quantified using the proposed material balance principle and iterative method. The rank of parameters that influence the ultimate recovery is the following: half-length of hydraulic fracture, induced fracture length/hydraulic fracture spacing, hydraulic fracture spacing, conductivity of induced fractures, conductivity of hydraulic fracture, and induced fracture spacing.

Carbonate reservoirs are characterized of fractures, vugs and cavities. These vugs have a large attribution to reserves of oil and gas. And the fractures provide effective paths for fluids flow in the reservoir. Triple porosity model is an effective conceptual method to capturing rock matrix, vugs and micro-fractures connecting them. However, these fractures and vugs are always non-homogeneous. Macro fractures and vugs cannot be handled with continuum for their low density and high conductivity.In this approach, the triple porosity conceptual model is implemented to characterize rock matrix, micro vugs and fractures. To capture the heterogeneity of fractures and vugs, macro fractures and vugs are represented explicitly with discontinuum model. The boundaries of macro vugs and macro fractures are discretized into several elements. Boundary element method is employed to handle flow into macro fractures and vugs. Finite difference method is applied to handle flow within macro fractures. The flow within macro vugs are assumed to be in pseudo-steady state.With a simple discretization of the boundaries of macro vugs and macro fractures, the proposed model is shown to efficiently simulate the behavior of fractured carbonate reservoirs with heterogeneity. The computational accuracy is demonstrated using an analytical model. On the basis of the proposed model, the effect of heterogeneity of macro fractures and vugs on pressure transient behavior is analyzed. The results show that macro fractures and vugs cannot be handled with triple-continuum models analytically. There will be several "dips" on the derivative of pressure curve if macro vugs are discretely handled. And discretely handling the fractures and vugs will make the calculated dimensionless pressure and the derivative lower than calculated with tripe continuum models. Increasing the porosity of macro vugs, the pressure and the derivative will go down in the flow regimes dominated by macro vugs. The conductivity of macro fractures has a great impact on almost all the flow regimes except boundary dominated flow regimes.The novelty of the new model is in the ability to model the transient behavior carbonate reservoirs with non-homogeneous fractures and vugs. Furthermore, it provides an efficient method for characterizing the heterogeneity of multi-scaled fractures and vugs.

Co-injection of solvent and steam in Expanding Solvent-Steam Assisted Gravity Drainage (ES-SAGD) increases the mobility of highly viscous oil relative to conventional SAGD wherein only steam is injected. This consequently results in higher oil production rates and lower energy consumption relative to SAGD due to the combined benefits of heating and dilution. Current efforts have been made to study mass transfer from a single-component-solvent/steam mixture into the heavy oil at the steam front, while the low-cost multicomponent solvent is actually co-injected with steam on the field, which presents a much more complicated interfacial condition. In this paper, a generalized methodology has been developed to couple heat and mass transfer of this solvents–steam–heavy oil system at the interface. In the model, the equation of state and fugacity equation are integrated to calculate and analysis the equilibrium state of transition interface. Then, the transition interface model is established based on heat transfer formulations and gaseous phase convective equations. Finally, under the temperature and velocity boundaries, the model is solved by applying implicit Runge-Kutta method and the results are used to analysis the heat and mass transfer characteristics. The predicted results show that increasing the fraction of lighter solvent can enhance mass transfer, while the heat transferred is seriously deteriorated. Besides, the closer the bubble point temperature and dew point temperature of the stream is, the smaller the elevation of mass transfer will be, but the heat transfer is almost unaffected. Therefore, to realize the best effects of heat and mass transfer, solvents with larger saturation temperature difference should be applied, and the composition of the solvents should be carefully determined according to the formation properties and solvent components. Conducting an ES-SAGD project on a field has many challenges, especially considering its main economic factors: production increase and solvent cost. With the new methodology, an optimum multicomponent solvent can be screened from the ocean of solvent candidates for a best heat and mass transfer performance in an ES-SAGD process and hence the oil flux at the chamber edge can be maximized with a minimized solvent cost. Therefore, it is of fundamental and practical importance to study the coupled heat and mass transfer of multicomponent solvents–steam–heavy oil system at the interface.

The unprecedented carbodiimide-mediated condensation between pyridines and anthranilic acids via pyridine dearomatization at room temperature has been developed to provide a straightforward approach to pyridoquinazolones. The value of this approach has further been demonstrated by its application to one-step, gram-scale syntheses of a series of pyridoquinazolone-based natural products and their analogues from readily available starting materials.

Based on the physical experiment of visible multi-tube water flooding, in combination with field production data, the interlayer interference in multilayer commingled production of ordinary offshore heavy oil reservoirs is quantitatively characterized and an appropriate productivity prediction method of directional wells is established for multilayer commingled production of ordinary heavy oil reservoirs. The dynamic relationship of interference coefficients between fluid and oil production indexes is obtained for the multilayer commingled production of ordinary heavy oil reservoirs. The Vandervlis directional well productivity equation is revised by introducing interference coefficient with consideration of starting pressure gradient and a dynamic productivity prediction equation is finally established suitable for multilayer commingled production of ordinary heavy oil reservoirs. Interlayer interference is mainly controlled by vertical reservoir permeability difference, which can be comprehensively characterized by reservoir reference permeability, permeability contrast and permeability deviation. The productivity of wells with different water-cut stages is variously affected by interlayer interference. This influence will be intensified in high water-cut situation, which needs appropriate adjustment measures. The productivity can be more accurately predicted by considering interlayer interference, and the revised directional well deliverability equation can be well applied to field production. Key words: offshore oil field, ordinary heavy oil reservoir, multilayer commingled production, interlayer interference, interference coefficient, directional well, productivity prediction

Interacting with the pre-existing natural fractures, multi-stage hydraulic fracturing along horizontal wells creates complex fracture networks in the reservoirs. The flow behavior of these created networks is significantly different from that of traditional single or multiple planar fractures due to complex interplay of flow caused by the interconnected fractures. Therefore, modelling the flow behavior of such fracture networks is essential if one intends to evaluate well performance or characterize fracture properties. In this paper, we present a semi-analytical model for the transient behavior of complex fracture networks in which hydraulic and natural fractures can interconnect with arbitrary angles. To model the flow behavior more rigorously, the fractures within the network are represented explicitly rather than idealized as dual-porosity media with the matrix around them. This approach allows us to concentrate on the details of network properties, especially for the complex geometry and varying conductivity within the fracture. In the model, the transient responses are obtained from coupling a reservoir flow model and a fracture network flow model dynamically. Source functions in Laplace domain and superposition principle are adopted to model the flow behavior in reservoir analytically and the transient flow equation in the network is solved by finite difference method numerically. Furthermore, Star-Delta transformation commonly used in discrete fracture network simulation (DFN) is adopted to solve the interplay of flow between the interconnected fractures. The validation of the semi-analytical model is demonstrated in comparison to the solution of ECLIPSE reservoir simulator for orthogonal network. The parameter analysis indicates that the planar penetration coefficient of natural fractures and the varying fracture conductivity have a great effect on the transient responses and drainage pattern for orthogonal networks. Finally, a field example from the Barnett Shale shows the capacity and practical use of the semi-analytical model to evaluate well performance and stimulation effectiveness of complex fracture networks in unconventional reservoirs.

The objectives of this work are to establish a comprehensive mathematical model for estimating thermophysical properties and to analyze the performance of superheated-steam injection in horizontal wells. In this paper, governing equations for mass flow rate and pressure drop are firstly established according to mass and momentum balance principles. More importantly, phase change behavior of superheated steam is taken into account. Then, implicit equations for both the degree of superheat and steam quality are further derived based on energy balance in the wellbore. Next, the mathematical model is solved using an iterative technique and a calculation flowchart is provided. Finally, after the proposed model is validated by comparison with measured field data, the effects of some important factors on the profiles of thermophysical properties are analyzed in detail. The results indicate that for a given degree of superheat, the mass flow rate drops faster after superheated steam is cooled to wet steam. Secondly, to ensure that the toe section of horizontal well can also be heated effectively, the injection rate should not be too slow. Thirdly, the mass flow rate and the degree of superheat in the same position of horizontal wellbore decrease with injection pressure. Finally, it is found that when reservoir permeability is high or oil viscosity is low, the mass flow rate and the degree of superheat decline rapidly.

The aims of this work are to present a comprehensive mathematical model for estimating wellbore heat efficiency and to analyze performance of steam injection for heavy oil recovery. In this paper, we firstly introduce steam injection process briefly. Secondly, a simplified approach of predicting steam pressure in wellbores is presented and a complete expression for steam quality is derived. More importantly, both direct and indirect methods are adopted to determine the wellbore heat efficiency. Then, the mathematical model is solved using an iterative technique. After the model is validated with measured field data, we study the effects of wellhead injection rate and wellhead steam quality on steam injection performance reflected in wellbores. Next, taking cyclic steam stimulation as an example, we analyze steam injection performance reflected in reservoirs with numerical reservoir simulation method. Finally, the significant role of improving wellbore heat efficiency in saving water and fuels is discussed in detail. The results indicate that we can improve the wellbore heat efficiency by enhancing wellhead injection rate or steam quality. However, high wellbore heat efficiency does not necessarily mean satisfactory steam injection performance reflected in reservoirs or good performance of heavy oil recovery. Moreover, the paper shows that using excellent insulation materials is a good way to save water and fuels due to enhancement of wellbore heat efficiency.

Two general protocols have been developed for the photoinduced, metal-free direct arylation of unactivated arenes with aryl iodide. Both methods gave good to excellent yields for most substrates. Notably, the C-F bond in method A and the C-F, C-Cl, and C-Br bonds in method B could survive the arylation reaction. These methods offered excellent options for syntheses of biaryls.