Gas Condensate Production Research Articles

Increasing the production of gas condensate by using ammonium carbonate salts

The work is devoted to the problem of increasing gas condensate production in gas condensate fields. It was found that ammonium carbonate salts, in the absence of calcium chloride type waters, interact with carbonate rocks, increase the permeability of reservoirs. Solutions of ammonium carbonate salts when interacting with formation water of the calcium chloride type form chemically precipitated chalk in the pore space, while the permeability of carbonate rocks decreases. A set of experimental studies was carried out to study the displacing and washing properties of ammonium carbonate salts. It was found that ammonium carbonate salts have high displacing properties, the displacement ratio of kerosene by NH4HCO3 solution is 0.75-0.80, while reservoir water – 0.55-0.58. According to the results of laboratory studies of the displacing and washing characteristics of ammonium carbonate salts, conclusions were made about the effect of bicarbonate solution (ammonium carbonate salts) on the production characteristics of a well in reservoir conditions at temperatures of 80-100 °C and above. Industrial tests of ammonium carbonate salts showed an increase in gas flow by 30-50% at wells № 23 of Opishnia, № 115 of Mashivka, № 3 of Tymofiivka gas condensate fields. The effect of formation treatment with ammonium carbonate salts is achieved due to clearing of well bottom zone and increasing the formation permeability. At wells № 56, 108 of Yablunivka and № 58 of Tymofiivka gas condensate fields, an increase in the condensate ratio was observed by 22-35%. The effectiveness of this treatment is associated with the simultaneous bottomhole zone cleaning from asphalt-resinous contaminants and permeability increase, as well as with the hydrophilization of the pore space and mobility increase of condensate precipitated as a result of carbon dioxide effect, which was rejected as a result of decomposition of ammonium carbonate. Thus, experimental and industrial tests in Opishnia, Mashivka, Tymofiivka, Yablunivka gas condensate fields of Poltava region confirmed the effectiveness of using ammonium carbonate to increase hydrocarbon production. The prospect of further research is aimed at developing a technology for increasing the production of liquid hydrocarbons by using ammonium carbonate salts.

ПРИНЦИПЫ ГОСУДАРСТВЕННОЙ ИННОВАЦИОННОЙ ПОЛИТИКИ В ОТНОШЕНИИ ГАЗОВОЙ ОТРАСЛИ АЗЕРБАЙДЖАНА

The purpose of the article is to analyze the principles of state innovation policy in the gas industry of Azerbaijan and to identify possible additional reserves that allow the formation and implementation of the national innovation policy in the course of economic reform on an innovative basis.
 Research methods - general scientific (synthesis, deduction, induction, generalization, observation, forecasting, scientific abstraction, statistical analysis, logical) methods for grouping and classification, as well as expert assessment.
 The work applied a systematic approach to the totality of business entities operating within the framework of the gas industry in Azerbaijan. The research is based on theoretical concepts of macroeconomic regulation of natural resource management in market conditions, as well as the principles of management of such national structures that have been worked out in world practice.
 The article discusses the main tasks of determining the priorities for the development of scientific, technical and innovative areas that affect the increase in production efficiency and competitiveness of products in gas industry. The organizational, legal, financial and economic foundations for the development and creation of favorable conditions for the activation of priority tasks and innovation in the gas industry of Azerbaijan have been determined.
 The results of the analysis of other states experience in using the resource base for attracting foreign investors to the country, creating for them comfortable working conditions in the field of innovations in the oil and gas industry, are presented. The issues of the development and use of innovative technologies in the gas industry, which make it possible to increase efficiency and bring significant socio-economic effects associated with an increase in gas and gas condensate production, tax revenues, as well as the development of human capital and related sectors of the economy, are considered.
 In conclusion, it is noted that the success of the scientific and innovative reform in the gas industry largely depends on how strong the traditions of the country's scientific and technological potential are and on how the state regulates the production strategy of innovative development. For this, a significant scientific and technical potential has been preserved in the republic, which makes it possible to form and implement a national innovation policy in the course of economic reform on an innovative basis.

Сопряжение ФГОС ВО 21.03.01 «Нефтегазовое дело» и профессионального стандарта «Специалист по добыче нефти, газа и газового конденсата» на примере реализации дисциплин технологическое оборудование нефтегазовой отрасли и обслуживание и ремонт нефтепромыслового оборудования

The article makes an attempt to analyze the situation in the labor market in modern Russian society in connection with new conditions, rapidly changing technologies, digitalization of all production and management processes, and what awaits a university graduate in a new labor reality. The article deals with the issue of conjugation of federal educational standards of higher education of generation 3++ and professional standards in the implementation of bachelor’s programs. The study is based on the example of interfacing FSES HE 21.03.01 “Oil and Gas Business” and the professional standard “Specialist in oil, gas and gas condensate production” in the context of the implementation of disciplines Technological equipment of the oil and gas industry and Maintenance and repair of oilfield equipment and the formation of professional competence: able to carry out work for diagnostics, maintenance, repair and operation of technological equipment in accordance with the chosen field of professional activity at the Yugra State University. The positive aspects of the interface between PS and FSES of HE in the implementation of educational programs of higher education, the difficulties arising on the way of this process and possible solutions are noted.

Application of multi-stage hydraulic fracturing in the development of Achimov sediments at the Urengoy oil and gas condensate field

The development of deep-lying Achimov deposits makes it possible to extract additional volumes of gas and gas condensate in the fields with decreasing production, as well as implement strategies to introduce new methods to increase oil, gas and condensate production. The decrease in well productivity during the development of gas condensate fields requires the use of new methods of intensification of production. The main method for increasing the productivity of Achimov wells is hydraulic fracturing. The choice of hydraulic fracturing technology for low-permeability Achimov deposits is especially important for creating large hydraulic fractures and high permeability, as well as maintaining the filtration characteristics of reservoir rocks. Multi-stage hydraulic fracturing is the most effective method of intensifying gas and gas condensate production in the development of the Achimov deposits.

Ways of helium development in Eastern Siberia

The Baikal natural gas deposits are ten times higher than the Orenburg oil and gas condensate field in terms of helium content. The Orenburg field is the raw material base of the Orenburg helium plant, which is part of Gazprom Dobycha Orenburg. Helium is characterized by increased ability to leak out. It is no coincidence that two deposits of Eastern Siberia geographically gravitate towards the deep Baikal fault. Hydrocarbon deposits in the north of the Krasnoyarsk Territory characterized by an increased fracturing system may have interconnections with deep faults. The study of such geological conditions in the development process is promising for increasing the raw material base of helium mining. Helium production technology is based on low-temperature gas condensation. The application of membrane gas separation technology is promising. Separation blocks can be incorporated into the infrastructure of compressor stations. This approach to the deployment of helium production capacities will increase the efficiency of capital investments. Relatively small volumes of productive helium can be transported without reference to pipeline systems. The proximity to the Yenisei and the Northern Sea Route makes the issue of the development of gas condensate production relevant. Placing production wells near the intersection of several fracturing faults is also effective in terms of high inflows. Of particular interest are wells drilled near discontinuous faults. Under these conditions, one can rely on helium inflows through microcrack systems from deep horizons.

Использование моды H111 в СВЧ-плотномерах продуктов добычи газоконденсатных и нефтегазоконденсатных скважин при дисперсно-кольцевом режиме газожидкостного потока

Использование моды H111 в СВЧ-плотномерах продуктов добычи газоконденсатных и нефтегазоконденсатных скважин при дисперсно-кольцевом режиме газожидкостного потока

Approaches to increasing well productivity in the development of the Bovanenkovo oil and gas condensate field

A large number of gas and gas condensate fields are located in the West Siberian mega-province and, to increase gas and gas condensate production levels, deposits located on the Yamal Peninsula should be introduced into development. Deposits of the Yamal Peninsula are complex-built deposits, Neocomian and Jurassic deposits have abnormally high reservoir pressure with a reservoir temperature of more than 100 ° C. The Bovanenkovo oil and gas condensate field is the largest in terms of gas reserves in the Yamal Peninsula; on this example, in this article we will study the issues of restoring the reservoir properties of reservoir rocks and increasing the flow of hydrocarbons. To select the optimal technology and composition for conducting water shutoff treatment, it is necessary to take into account the following factors: which reservoirs represent the reservoir, the percentage of water cut in the recoverable reserves, the tightness of the production string, the current flow rate of the well during operation at constant reservoir pressure, because each field needs an individual approach with a choice suitable water shuto-ff treatment technology.

Non-equilibrium phase behavior in gas condensate depletion experiments

Full diameter core depletion tests are performed in this study to investigate the influence of depletion rate on the production of gas and condensate. Experimental results confirm that the gas recovery of the fast-depletion test is lower than that of the slow-depletion test. On the contrary, without the consideration of the fluid flow in porous media, the condensate recovery of the fast-depletion test is higher than that of the slow-depletion test.Non-equilibrium phase behavior is claimed to explain this abnormal behavior. The non-equilibrium model is adopted in this paper based on the components’ transfer rates between oil and gas phases. In addition, with the consideration of the compositional change in gas-condensate production, a numerical model is built to simulate the depletion process. Based on the comparison between the simulation and experimental results, the influence of non-equilibrium phase behavior on gas-condensate production is analyzed. If the depletion rate is relatively high, the heavy components of the gas-condensate system tend to be produced within the gas phase instead of condensing inside the core due to incomplete vapor-liquid separation. As a result, more condensate is acquired from the fast-depletion test.

Modelling viscosity of liquid dropout near wellbore region in gas condensate reservoirs using modern numerical approaches

Liquid dropout occurs in gas condensate reservoirs below the dew point pressure around near wellbore region as a result of depletion from production of such reservoirs. Forecasting production as well as optimizing future recoveries of gas condensate reservoirs are highly desirable. This is not possible to achieve without accurate determination of liquid dropout viscosity (μc) below the dew point. The focus of research in past decades has been on the development of accurate viscosity prediction models below the dew point pressure to ensure accurate condensate production forecast. Gas condensate production forecast and optimization around wellbore region and condition are complicated due to unique gas condensate behaviour that violates thermodynamic laws.Current methods are based on correlation estimation, however the accuracy of these correlations are less than satisfactory, and root cause is due to the miscapturing of complex behaviour of gas condensate reservoir near the wellbore region. These motivated the consideration of modern numerical approaches such as the Least Square Support Vector Machine (LSSVM) and Artificial Neural Network (ANN) used in this paper. These methods are considered as more data behaviour oriented, with the capability of capturing the fluid complexity of gas condensate in such conditions.In this study viscosity of condensate phase near the wellbore region was modelled using machine learning techniques including ANN and LSSVM. For this purpose, over 300 viscosity data sets were collected from published literature and experimental studies worldwide. This databank includes API gravity, reservoir temperature, solution gas to oil ratio (Rs), specific gas gravity, fluid compositions and reservoir pressure.Six well known previously published viscosity correlations refined using least-square approach to match the experimental data. Qualitative and quantitative error analysis of developed LSSVM and ANN showed their performance superiority over refined literature correlations. The new proposed models can be embedded as an extra feature of commercial reservoir simulation packages for optimization and future recoveries of gas condensate reservoirs.

Impact of energy production in the Barnett Shale gas region on the measured ambient hydrocarbon concentrations in Denton, Texas

The Barnett Shale play in North Texas is one of the largest active onshore shale gas regions in the United States. Over the past two decades, unconventional energy production from shale gas in North Texas has grown rapidly. The energy production peaked in 2012 and has declined since. The city of Denton is located at the edge of the Barnett Shale play and is within the Dallas-Fort Worth metropolitan area. In this paper, we describe a long-term trend study of 84 total non-methane organic carbon (TNMOC) species measured at the Denton Airport South monitoring station, an exurban site. The annual mean TNMOC concentrations measured during 2000–2017 increased by +8.03 ± 12.92 ppb-C/year (+12.75%/year). The year-to-year increase in the mean TNMOC concentrations mirrored the energy production volume changes from natural gas wells and liquid condensate facilities within 2-km from the ambient air quality monitoring station. Concentrations of alkanes increased significantly, especially the natural gas species of ethane, propane, n-butane, and isobutane. The annual variations in the ethane concentrations were similar to changes observed in the natural gas and liquid condensate production from nearby wells. High levels of ethane, a dominant natural gas species, were originating from regions with a higher density of gas wells within close proximity of the monitoring site. In contrast, the concentrations of alkene and aromatic species have declined during the study period as a result of decreases from traditional urban emission sources. However, the trend in benzene, a carcinogenic aromatic species found in vehicular and natural gas emissions, and xylene concentrations were similar to the n-alkane trend, suggesting the influence of energy production activities on key ambient aromatic compounds.

Pressure and rate transient modeling of multi fractured horizontal wells in shale gas condensate reservoirs

Gas condensate production using technology of multi-stage hydraulically fracturing in shale gas condensate reservoirs' horizontal wells is a new topic of unconventional resources studies. Thus, shale gas condensate as a new source of energy can be considered as an important issue for development and further studies. In this work, a semi-analytical solution of gas and oil two-phase flow is presented for pressure transient analysis (PTA) and rate transient analysis (RTA) of a shale gas condensate reservoir's production data. Fluid flow assumption here is flow in a pseudo triple-porosity porous media, which are matrix, natural fractures and adsorbed gas. Adsorbed gas is a form of gas in porous rock pores like free gas, but unlike that, it is not free to flow initially and requires pressure drop to desorb from micro- (or even nano-) pores of rock to flow in matrix and then in fracture. In this study, desorption of the adsorbed gas is modeled with Langmuir isotherm theory. Based on the results, type curves of two-phase pseudo-pressure and also two-phase rate decline are plotted. These type curves are analyzed with different sensitivities to Langmuir volume, interporosity flow parameters, horizontal well length, number of multiple-fractures and Corey model relative permeability exponents. Τhe strength of this work is to plot type curves of pressure and rate transient analysis of multi-stage hydraulically fractured well (MHFW) in shale gas condensate reservoir in terms of rich gas production of the well.

Thermodynamic analysis of the NGL plant in a sample gas refinery and problem solving by designing an absorption chiller

The power for chiller in dew point setting unit in the sample gas refinery is already being produced by a compression refrigeration cycle and a gas turbine. In case of gas turbine maintenance or failure, the unit would work without compression refrigeration cycle. Presence and absence of compression refrigeration cycle and its impacts on gas condensate production in the plant have been modeled in this study. Absence of compression refrigeration cycle would cause hourly reduction of 7.5 and 2.6 tons of propane and butane, respectively. Detailed modeling of the gas turbine has also been implemented in the next step and, then, compression refrigeration cycle has been coded for calculation of important parameter of the cycle. Finally, for improving the efficiency of the aforementioned unit, the water-ammonia absorption chiller has been introduced and designed for replacing the compression refrigeration cycle as a stand-by option. With the modeling of water-ammonia absorption chiller, the calculated fuel consumption of generator was found to be less than the available gas turbine, and the capital cost of this chiller is about $5,850,000. Consequently, it was discovered that in absence of compression refrigeration cycle for about 45 days, the cost of the absorption chiller would be completely returned.

Soft Sensing for Gas-Condensate Field Production Using Parallel-Genetic-Algorithm-Based Data Reconciliation

During present offshore gas-condensate production, multiphase flow-meters, due to its exceedingly high cost, are being substituted by a soft sensing (SS) technique for estimating total and single-well flowrates through sensor measurements and physical models. In this work, the inverse problem is solved by data reconciliation (DR), minimizing weighted sum of errors with constraints integrating multiple two-phase flow models. The DR problem is solved by parallel genetic algorithm (PGA) without complex calculations required by conventional optimization. The newly developed SS method is tested by data from a realistic gas-condensate production system. The method is proved of good accuracy and robustness with invalid individual pressure sensor or unavailable total flowrate measurements. Meanwhile, the proposed method shows good parallel performance and the time cost of each DR process can meet the demand of engineering application.

KEY ISSUES OF ACCOUNTING FIXED ASSETS MANAGEMENT OF OIL AND GAS ENTERPRISES: ANALYSIS OF FEATURES, COMPOSITION AND VALUATION

The article deals with the key issues concerning the system of security of fixed assets at the enterprises of the oil and gas industry. The purpose of the article is to investigate the fixed assets features and composition at the the enterprises of oil and gas industry, to determine the approaches to their assessment at the stage of their receipt by the enterprise. The state, dynamics of value and the degree of depreciation of fixed assets in Ukraine for the year 2017 have been analyzed, their features have been distinguished at the enterprises of different branches of the economy. To ensure the effective operation of the enterprises of the oil and gas industry, significant assets are required, and the results of their activities to a large extent depend on the availability and condition of fixed assets that ensure economic sustainability of economic entities. Oil and gas companies include pipelines and related equipment in fixed assets, oil and gas assets, machinery and equipment, buildings, buffer gas, drilling and reconnaissance equipment and other fixed assets. Among the assets of NJSC "NAFTOGAZ OF UKRAINE" for the year 2017, non-current assets occupied 86% of the total assets of the company, of which 94% were fixed assets, what determines the reliability of their accounting as an important element of effective management of enterprises. The dynamics of value and composition of fixed assets of enterprises of the oil and gas industry of Ukraine for 2016-2017 have been determined according to separate economic segments. The cost of fixed assets of NJSC "NAFTOGAZ OF UKRAINE" as of December 31, 2017 amounted to UAH 491 482 million, respectively, according to economic segments, it is structured in such a way that their largest share is concentrated in the system of transportation and distribution of natural gas - almost 48%, for storage of natural gas - 34%, production and sale of natural gas - 12%, and the rest belongs to the economic activities related to oil: the production of crude oil and gas condensate, transportation of crude oil. The composition of fixed assets of extractive enterprises differs from their composition in refineries. Industrial features of mining industry with significant volumes of work related to the disclosure of layers of minerals are characteristic to chemical production with a significant cost of equipment. The main approaches to the evaluation of fixed assets objects at the stage of their entrance to the enterprise have been investigated. The reliability of the accounting information on fixed assets depends on their assessment. When they are received, they are valued at their original cost, that is, by the amount of cash paid or their equivalents or fair value, another form of indemnity granted to obtain the asset at the time of its acquisition or creation, or, if accepted, the amount that is distributed to that asset in the original recognized in accordance with the specific requirements of other IFRSs. After recognition, the entity should choose either a cost model or a revaluation model in its accounting policies and should apply this policy to the entire group of fixed assets. A cessation of recognition occurs after the release of an object or when it does not expect future economic benefits from its use or disposal. In this case, it is recognized as profit or loss.

Production performance analysis for horizontal wells in gas condensate reservoir using three-region model

Gas condensate reservoir is a special kind of oil and gas system that involves two-phase flow during production, because oil condensation occurs when reservoir pressure drops below the dew point pressure. It is of great importance to develop some well testing models for the gas condensate reservoir, yet there exists no analytical well-testing model for horizontal well in such formations. This paper proposes an analytical model for the production performance analysis of horizontal well in gas condensate reservoir. The three-region model is employed to characterize the flow and production of gas condensate, and the three regions are: region-1 in which oil and gas are both mobile, region-2 in which only gas is mobile whereas the oil cannot flow, and region-3 in which only the gas phase exists. To solve the proposed model, Laplace transformation and Cosine transformation are applied to change the partial differential equations to ordinary differential equations. Then, Stehfest numerical inversion technique is used to convert the solution of the proposed model into real space. Afterwards, the pressure response type curve is obtained and nine flow regimes are identified. Subsequently, sensitivity analysis is carried out to investigate the influence of several factors on production performance. Finally, field application is carried out to validate the accuracy of our model, and it is shown that the model prediction result is in accordance with the real production data. The proposed model provides some insights toward the production behavior of horizontal well in gas condensate reservoir, and can be used to evaluate the horizontal well productivity of the such reservoirs.

Utilization of nature-inspired algorithms for gas condensate reservoir optimization

Hydrocarbon production from a gas condensate reservoir has a major concern to the petroleum industry around the world. Due to pressure decline in a reservoir, liquid drops out of solution and cause a significant reduction of well productivity. As a result, huge amount of valuable oil stays underground. The proper production management for a gas condensate reservoir minimizes or eliminates the blocking problems. Optimization of condensate recovery can be achieved through appropriate selection of production and injection rates. However, determination of the optimal rates is a complex problem, involving many factors including geological uncertainty, rock petrophysical characteristics, fluid properties, economic costs, and technical ability. In this research, nature-inspired optimization algorithms are employed to evaluate the potential of production boost. Numerical testing and comparative study revealed that investigated natural-inspired algorithms outperform widely reported in the literature optimization methods and provide a higher quality solutions. The primary concern of this research is to develop an optimal gas condensate production strategy in terms of economic efficiency by utilization of nature-inspired optimization algorithm and providing their ability to generate better quality solution than engineering approach as well as gradient optimization.

The feasibility analysis of underground gas storage during an integration of improved condensate recovery processes

Due to the increasing demand for gas consumption during cold seasons, it is a sense of urgency to provide a reliable resource for gas supply during these periods. The objectives of this comprehensive research entail reservoir core analysis, reservoir fluid study, investigation and optimization of improved condensate recovery during gas storage processes in one of Iranian-depleted fractured gas condensate reservoir. We have attempted to make a balance among reservoir petrophysical and operational characteristics such as production rate, ultimate reservoir pressure after production, cumulative condensate production, number of wells and the required time periods for the reservoir depletion, to obtain an optimum condition for the gas storage process. It’s a foregone conclusion that the quality of management decision-making regarding reservoir depletion, maximum gas recovery and natural gas condensate production subsequently optimize at the minimum pressure drop. Furthermore, according to the simulation analysis, pipeline gas injection may lead to condensate recovery improvement.

Investigation of the Role of Droplet Transport in Mitigating Top of the Line Corrosion

The entrainment of liquid droplets, occurring in a limited range of gas and liquid flow conditions within the stratified flow region, could represent an effective way to transport a non-volatile liquid corrosion inhibitor through the gas phase and combat top of the line corrosion (TLC). However, such an approach is only viable if the inhibitor can reach the top of the pipe and deposit at a rate higher than the local rate of condensing water can dilute it. This work presents a combined modeling and experimental methodology to determine the onset of droplet entrainment from the bottom and deposition at the top of the line. A modeling approach predicting the droplet entrainment onset is proposed and validated against new multiphase flow data recorded in a large scale flow loop, at operating conditions similar to those encountered in gas-condensate production facilities. Additionally, TLC experiments were performed in the same flow loop under simulated water condensation conditions to measure the actual corrosion at different rates of inhibiting droplet deposition. The results confirm that the droplet entrainment/deposition can effectively mitigate TLC when operating parameters are accurately controlled.

Beyond the Limitations of API RP-14E Erosional Velocity -A Field Study for Gas Condensate Wells

Fluid velocity has the potential to cause severe erosion damage to oil & gas production infrastructure. In order to avoid or alleviate damage due to erosion, the American Petroleum Institute Recommended Practice (API RP) 14E recommends a threshold fluid velocity for production tubing and pipelines. However, field and laboratory data have proven that the applied empirical constants, known as C-factors, within the formula are not valid for all conditions. In many cases the calculated API RP 14E erosional velocity is significantly underestimated or overestimated due to insufficient consideration of fluid characteristics. In addition, accurate field data on erosional velocity can assist proper pipe sizing calculations for prospective oilfield projects. Oversizing of tubing unnecessarily increases construction costs whilst underestimating required size of tubulars can lead to catastrophic erosion/corrosion failures. In this study new values for erosional velocity constants, beyond those suggested by API RP 14E, are proposed based on experimental data achieved from sidestream pilot test units. The experimental pilot test units were installed on four different gas condensate production fields in the south of Iran. Electrical Resistance (ER) probes were employed to gather online erosion-corrosion data from the pilot units, each of which was in service for about nine months. The results showed that higher C-factors can be safely applied for these gas condensate fields in comparison with those recommended by API RP 14E. Furthermore, it was revealed that pilot test units exposed to a higher Condensate Gas Ratio (CGR) experienced a greater rate of erosion.

Wellbore modeling for hybrid steam-solvent processes

The addition of hydrocarbon solvents to the cyclic steam stimulation (CSS) or steam assisted gravity drainage (SAGD) processes has recently gained significant interest from the petroleum industry. In these processes, a proper selection of solvent is critical: injected solvent must be in the vapor phase at the injection point in order to propagate inside the steam chamber and condense at the steam/oil interface to effectively reduce oil viscosity. Therefore, the wellbore have to deliver vaporized solvent near its dew point at perforation intervals.This work provides a detailed numerical formulationto predict steam and solvent qualities, temperature, and pressure profiles along the wellbore. Four phases were considered: hydrocarbon liquid and vapor phases, and aqueous liquid and vapor phases. The mass, energy and momentum balance equations are integrated with drift-flux model and discretized over the wellbore domain.Unknowns and governing equations are divided into the sets of primary and secondary equation and unknowns are solved sequentially. The model was compared against previously published models and field data. The data from two steam injection wells and two gas condensate production wells were used for validation. Also, case studies are presented to investigate the temperature and condensation behavior of the solvent-steam mixture.The use of this model will assist the industry in proper wellbore design and the engineering of injection constraints in hybrid steam/solvent injection processes.