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Steam-assisted gravity drainage (SAGD) is an efficient technology that has been used to develop oil sand resources, and it has been successfully and maturely applied in Canada. However, oilfield production has demonstrated that reservoir heterogeneity has a serious impact on SAGD development, among which the most drastic impact is caused by multiple barrier layers in the reservoir. These barrier layers can severely impede the development of a steam chamber and the drainage of oil. Hence, it is important to investigate their influence mechanism. In this study, oil samples from the Long Lake oil field were used in laboratory experiments to study the development of the steam chamber and the residual oil distribution under the effect of multiple barrier layers. Then, a theoretical numerical simulation model was established to describe the fluid flow more precisely. In addition, the production characteristics of SAGD under the influence of different numbers of barrier layers were analyzed by comparing the development of the steam chamber. Finally, the impacts of multiple barrier layers with different modes of combinations were studied for their effects on SAGD production. The results indicated that for impermeable barrier layers of the same length, the steam primarily developed upward after flowing around the first barrier layer. After the steam chamber reached the top of the reservoir, the steam began to enter into the interbedded zone. Based on an unchanged first barrier layer, the number of barrier layers had little influence on the overall shape of the steam chamber and SAGD production, which confirmed that the first barrier layer played a dominant role in the influence of multiple barrier layers. In addition, characteristic points (P1, P2, P3), which corresponded to changes in the stage of steam chamber development, were established and used to evaluate the effect of the barrier layers. Different combinations of barrier layers were realized by changing the relative properties of the first barrier layer. The results showed that the longer the length of the first barrier layer, the closer it was to the steam injection well and the lower the permeability; hence, the more obvious its hysteresis effect on the SAGD process.

An enormous amount of fracturing fluid is irreducible in the tight formation after hydraulic fracturing stimulation. This will cause serious damage to the fracture face as well as the matrix close to the hydraulic fractures by invading into the matrix. Modeling the effect of water blockage on rate transient behavior is significant in reservoir engineering. This paper presents a modified trilinear model to analyze the rate transient behavior after flowback period. Single-phase flow is assumed in this stage because most injected water is hard to be reduced. For damage to the matrix caused by rock-fluid interaction, clay swelling, and polymer adsorption, a fracturing fluid invasion layer is added to the model between hydraulic fractures and the inner stimulated reservoir volume to capture this kind of damage. A skin factor is used to capture the damage to the matrix-fracture face caused by gel filter cake formation and polymer adsorption. The analytical model is benchmarked using the commercial numerical simulator Eclipse. Several synthetic cases and a field case are studied, the results show that water blockage has a great impact on the productivity of the well and decline curves. The effect of choking effect, convergence flow, and gel filter cake could be incorporated using a skin factor in the model. In addition, two more flow regimes could be observed on the theoretical type curve if the well is affected by water blockage, and the two flow regimes would happen before linear flow dominated by the inner stimulated zone. Besides, the duration of the inner zone linear flow regime could be shortened if the permeability of the fracturing fluid invasion layer is lower and invasion depth is larger. These phenomena can be used in matching the field production data from water blockage affected wells, which exhibit a transition flow regime before the formation linear flow regime. This transition flow regime could be matched quite better using the proposed model than the classical trilinear flow model. The reason is that the linear flow regime could be much longer if the water blockage effect is not considered in the model. On the other hand, the skin factor has a different impact on the flow regimes, so the water blockage effect could be characterized properly only by adding a skin factor to the model. The main contribution of this paper is the provision of an analytical model for evaluating the formation damage caused by irreducible fracturing fluid, analyzing production data and making forecasts.

Solvent-Assisted Steam-Assisted Gravity Drainage (SA-SAGD) is invented by adding solvent into the injection stream. However, the high cost of the solvent makes it necessary to ensure a high efficiency of solvent transportation from the long-horizontal wellbore to the chamber edge. In this study, a novel model considering the wellbore/chamber coupling effects is established, which can accurately evaluate the performance of SA-SAGD. First, governing equations for mass flow in the wellbore are built on the basis of the mass and momentum balance determined by coupling the wellbore and steam chamber. Besides, implicit equations for phase changes were derived according to the heat-mass transfer between wellbore and chamber. Second, the model for oil flow rate in the chamber rising stage is derived by the chamber height identified by the variation in thermo-physical properties of solvent and steam in the chamber along the wellbore. Third, by applying Levenberg-Marquardt Algorithm (LMA), the mathematical model is solved The results show that: the oil rate of classic SAGD is significantly improved by the solvent of C5, while the improvement effect of C7 is quite small. As for C3-SAGD, the oil rate is even lower than that of traditional SAGD. This is mainly because C3 decreases the chamber temperature and the solubility of C3 in heavy oil is low, which results in a relatively higher oil viscosity at the chamber edge compared to other solvents. The differentials between the cases, which consider the wellbore or not, is different for different solvent injection. Specifically, oil rate differential for C3-SAGD is the highest and it is twice that for conventional SAGD which has the least differential. C5-SAGD has the second-largest differential which is followed by C7-SAGD. Currently, applying SA-SAGD in a field encounters many challenges, especially in understanding its mechanisms and improving economic efficiencies such as a conflict between the production increase and solvent cost. The newly proposed model not only sheds light on the key mechanism of wellbore/chamber coupling effects, which is usually neglected in the literature but also brings greater benefits by better designing the future SA-SAGD heavy oil recovery projects.

Excessive water production is a common matter that seriously affects production efficiency during the development of edge-water fault-block reservoirs. Gas huff-n-puff is an effective water shutoff technology that has the characteristics of small injection volume, no interwell connectivity impact, and minor gas channeling. However, gas injection can destroy the stability of the asphaltene to induce asphaltene deposition. In this article, the laboratory experiment had been conducted to investigate the effect of injection ratio and injection sequence on oil increment and water cut control for gas mixture huff-n-puff. Experimental results indicated that the effect of N2 huff-n-puff on water cut control was the most obvious, while CO2 huff-n-puff had the best performance on oil increment. Oil increment and water cut control of gas mixture huff-n-puff with CO2 injected in advance were obviously better than that of N2 injection preferentially. Subsequently, PVTsim Nova was utilized to investigate whether reducing CO2 injection volume can inhibit asphaltene deposition and predict the possibility of asphaltene deposition at reservoir conditions. Simulation results demonstrated that the asphaltenes were easily deposited with CO2 injection while N2 injection will be unlikely to induce asphaltene deposition. Asphaltene deposition pressure envelope can qualitatively analyze the possibility of asphaltene deposition and provide a reference for screening the appropriate gas injection ratio based on giving full play to the synergistic effect of CO2 and N2. In this study, 7:3 is selected as the optimum injection ratio considering the synergistic effect and the possibility of asphaltene deposition.

Heavy oil reservoirs with edge-bottom water represent a huge portion of the world&rsquo, s reserves, and the effective development of such reservoirs with cyclic steam stimulation (CSS) is significant for the petroleum supply. However, the water cut of some CSS wells increases, and production decreases, with the increase of circulation turns. Discerning the source of the produced water is the basis of targeted treatment measures. In this paper, a new model is established for discriminating the source of produced water from CSS wells in edge-bottom water reservoirs. The model combines traditional hydrochemical characteristics analysis and factor analysis, and considers the quality change in injected water. The coefficient of formation water and injected water in produced water can thus be obtained. In addition, the normal distribution method is used to further divide interlayer water and edge-bottom water. The model was applied to a field case, and the results showed that one well was severely invaded by edge-bottom water. The results are consistent with field production performance, which further verifies the accuracy of the model. This model is of great significance for not only discriminating the source of produced water in an edge-bottom water reservoir, but also providing a basis for further the provision of further treatment measures.

The addition of solvent to steam injection, known as Solvent-Assisted Steam-Gravity Drainage (SA-SAGD), has recently been regarded as a more economically-efficient and environmentally-friendly alternative to Steam-Assisted Gravity Drainage (SAGD). In this paper, we present a mathematical model for estimating greenhouse gas (GHG) emissions and chamber evolution considering non-uniform property distribution along the horizontal well for SA-SAGD. In addition, oil price, carbon tax and liquid pool corresponding to the influences of the market, environmental needs and technology are incorporated into the model to analyze the economic benefits. The calculated results show that, when the liquid-pool level is 3 m, the reduction in GHG emissions is 30% by injecting C3/C5 solvents and 16.5% when the solvent is C7. If the liquid level is as high as 5 m, there will be no reduction in carbon emissions for the C5/C7 solvent injection. When both oil price and the carbon tax are at high levels, the C5/C7-assisted SAGD has the best economic performance. The C3-assisted SAGD is best when the oil price is low and the carbon tax is high. When the oil price and carbon tax are low, there is no economic advantage for the solvent-assisted SAGD.

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.

Shale formation is featured in nanopores and much gas adsorptions. Gas flow in the shale matrix is not a singular viscous flow, but a combination of multiple mechanisms. Much work has been carried out to analyze apparent permeability of shale, but little attention has been paid to the effect of unique gas behavior in nanopores at high pressure and adsorbed layer on apparent permeability. This work presents a new model considering multiple transport mechanisms including viscous flow (without slip), slip flow, Knudsen diffusion, and surface diffusion in the adsorption layer. Pore diameter and mean free path of gas molecules are corrected by considering the adsorption layer and dense gas effect, respectively. Then the effects of desorption layer, surface diffusion, and gas behavior on gas apparent permeability in nanopores of shale are analyzed. The results show that surface diffusion is the dominant flow mechanism in pores with small diameter at low pressure and that the effect of adsorbed layer and dense gas on apparent permeability is strongly affected by pressure and pore diameter. From the analysis results, the permeability value calculated with the new apparent permeability model is lower than in the other model under high pressure and higher than in the other model under high pressure, so the gas production calculated using the new permeability model will be lower than using the other model at early stage and higher than using the other model at late stage.

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.

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...

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.

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.

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.

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.

Recently, commingling production has been widely used for the development of offshore heavy oil reservoirs with multilayers. However, the differences between layers in terms of reservoir physical properties, oil properties and pressure have always resulted in interlayer interference, which makes it more difficult to evaluate the producing degree of commingled production. Based on the Buckley&ndash, Leverett theory, this paper presents two theoretical models, a one-dimensional linear flow model and a planar radial flow model, for water-flooded multilayer reservoirs. Through the models, this paper establishes a dynamic method to evaluate seepage resistance, sweep efficiency and recovery percent and then conducts an analysis with field data. The result indicates the following: (1) the dynamic difference in seepage resistance is an important form of interlayer interference during the commingled production of an offshore multilayer reservoir, (2) the difference between commingled production and separated production is small within a certain range of permeability ratio or viscosity ratio, but separated production should be adopted when the ratio exceeds a certain value.

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.

Compared with conventional steam flooding and Steam-Assisted Gravity Drainage (SAGD), Solvent-Enhanced Steam Flooding (SESF) is considered a more effective method for improving heavy oil recovery in thin reservoirs in terms of higher thermal efficiency and oil production rate. However, there remains a deficiency of accurate and efficient methods to evaluate and design an SESF project in the field. A semi-analytical model is proposed in this paper to predict the recovery performance of SESF and investigate the effects of solvent properties and injection strategies on the SESF process for thin heavy oil reservoirs. The proposed model provides a simple method to simulate not only single solvent injection but also multi-solvent injection by cooperating different values of solvent operating thickness and solvent solubility. To validate the model’s accuracy, comparisons are made between the proposed model results and the numerical simulation results for a specific heavy oil reservoir case. The results indicate that SESF can achieve a considerably higher oil production rate at the early recovery stage than steam flooding. Moreover, the paper also demonstrates that a higher injection rate results in a lower thermal efficiency increment when well spacing is constant. Nevertheless, a high injection rate may also be suitable for longer well spacing owing to the improvement of the viscosity profile beyond the edge of the steam zone caused by longer contact time between the solvent and crude oil.

More than half of heavy oil reservoirs in Western Canada are less than 5m thick and SAGD is generally not thought to be economically viable for such kind of reservoirs due to lack of Potential Energy of Gravity and significant heat losses to the overburden. Solvent enhanced steam flooding (SESF), a kind of enhanced steam flooding by co-injecting solvent with steam, has shown to be promising in enhancing oil rates in thin reservoirs. In this paper, a semi-analytical model is established for predicting production performance of SESF. The model is mainly built based on Energy Conservation and Fick's Law to predict the steam front position as well as the solvent concentration profile in the reservoir. Besides, the blocking effects of steam condensate on solvent diffusion is modeled by introducing the oil-water two phase flow theory. Then, the model is divided into three parts corresponding to the three production stages of SESF, and they are semi-analytically solved successively. The proposed model is validated by comparing calculated oil production rate with the results of a numerical simulation method. The results indicate that the enhancement of oil production rate mainly happened in the early stage of the process which is achieved by the combining effects of heat and convection-enhanced mixing of solvent and heavy oil. On the basis of a sensitivity analysis for performance of SESF, it is realized that the operating thickness and solubility of a solvent are proportional to steam oil ratio reduction of SESF compared to conventional steam flooding. Besides, a relatively lower injection rate and a longer well spacing may result in higher thermal efficiency increment due to longer contacting time of solvent with crude oil. Piloting SESF in a field has many challenges, especially when considering its main economic factors: production increase and solvent cost. Therefore, it is anticipated that considering the dynamic mass transfer and blocking effect of accumulated condensate on solvent diffusion in SESF process, which are important mechanisms of SESF with inadequate understanding in literatures, the newly developed model will help to better predict and design the future SESF heavy oil recovery projects in thin pay zones.

Two-phase flow behavior in fractured carbonate reservoirs was investigated due to the importance for geothermal and petroleum resource recovery, such as in this study the phase change of volatile oil. This paper presents a semi-analytical method for accurately modeling two-phase flow behavior and quickly predicting the production performance. The fractured carbonate reservoir was modeled with a dual-porosity model, and the phase change and two-phase flow were modeled using the black oil model. The production of the oil phase was obtained through linearizing and solving the mathematical model. The gas phase production was forecast using the producing gas-oil ratio (GOR), calculated using flowing material balance equations. By comparing the semi-analytical solution to the solution of the commercial numerical simulator and applying it to a field case, the accuracy and practicability of the proposed semi-analytical method could be validated. Based on the semi-analytical model, the influences of several critical parameters on production performance were also analyzed. The proposed model was shown to be efficient in evaluating two-phase production performance of horizontal volatile oil wells. Furthermore, the new technique is able to serve as a useful tool for analyzing two-phase production data and making forecasts for volatile oil wells in fractured carbonate reservoirs.

Steam-assisted gravity drainage (SAGD) provides many advantages compared to alternate thermal recovery methods for bitumen recovery. Nowadays, most of researchers believe that the gravity mechanism is the main drive in SAGD recovery, ignoring the injector-producer pressure difference, which makes the field prediction deviate from reality. To tackle this problem, this paper makes further investigation on the injector-producer pressure difference. A series of 2D numerical simulations are conducted on the basis of Mackay River reservoir in Canada to investigateon influence of injector-producer pressure difference. Meanwhile, a new mathematical model considering injector-producer pressure difference is established. The results indicate that when the injector-producer pressure difference exists, SAGD usually has better recovery. Pressure difference can effectively improve SAGD operating performance to achieve a high economic efficiency. More pressure difference does not necessarily lead to better recovery, for when the pressure difference increases to some certain degrees, it will cause steam breakthrough. [Received: May 2, 2016; Accepted: November 11, 2016]