Gas-condensate

@misc{vasilyev1968gas7,
    author = "Vasil'yev, V. G",
    title = "Gas reservoirs of the USSR",
    year = "1968",
    howpublished = "Moscow, Nedra Publishing House, 382 p",
    note = "talkorigins\_source = {true}; raw\_reference = {Vasil'yev, V. G., 1968, Gas reservoirs of the USSR: Moscow, Nedra Publishing House, 382 p.}"
}

@misc{zolotov1968structure10,
    author = "Zolotov, A. N. et al",
    title = "Structure of the gas condensate deposit of Parfenovskii horizon of Markovskii oil field",
    year = "1968",
    howpublished = "Geology of Oil and Gas, v. 6, p. 26-30",
    note = "talkorigins\_source = {true}; raw\_reference = {Zolotov, A. N. et al., 1968, Structure of the gas condensate deposit of Parfenovskii horizon of Markovskii oil field: Geology of Oil and Gas, v. 6, p. 26-30.}"
}

@misc{bakirov1969oil2,
    author = "Bakirov, A. A. and Ryabuknin, G. Y",
    title = "Oil and Gas Bearing Areas and Regions of the USSR",
    year = "1969",
    howpublished = "Moscow, Nedra Publishing House, 477 p",
    note = "talkorigins\_source = {true}; raw\_reference = {Bakirov, A. A., and Ryabuknin, G. Y., 1969, Oil and Gas Bearing Areas and Regions of the USSR: Moscow, Nedra Publishing House, 477 p.}"
}

@misc{samsonov1970about6,
    author = "Samsonov, V. V. and Tyshchenko, L. F",
    title = "About genetic connections between gasses from the closed pores and gasses from the productive seams",
    year = "1970",
    howpublished = "Geology of Oil and Gas, v. 8, p. 33-36",
    note = "talkorigins\_source = {true}; raw\_reference = {Samsonov, V. V., and Tyshchenko, L. F., 1970, About genetic connections between gasses from the closed pores and gasses from the productive seams: Geology of Oil and Gas, v. 8, p. 33-36.}"
}

@article{vassoyevich1970more9,
    author = "Vassoyevich, N. B. et al",
    title = "More about the question of oil and gas prospects in late Cambrian deposits",
    year = "1970",
    journal = "Soviet Geology, v. 4, p. 66-79; English translation by American Geological Institute, 1971, International Geology Review, v.13, No.3, p. 407-418",
    note = "talkorigins\_source = {true}; raw\_reference = {Vassoyevich, N. B. et al., 1970, More about the question of oil and gas prospects in late Cambrian deposits: Soviet Geology, v. 4, p. 66-79; English translation by American Geological Institute, 1971, International Geology Review, v.13, No.3, p. 407-418.}"
}

@misc{vasilyev1975gas8,
    author = "Vasil'yev, V. G. and Zhabrev, I. P",
    title = "Gas and gas condensate reservoirs, a reference book",
    year = "1975",
    howpublished = "Moscow, Nedra Publishing House, 527 p",
    note = "talkorigins\_source = {true}; raw\_reference = {Vasil'yev, V. G., and Zhabrev, I. P., 1975, Gas and gas condensate reservoirs, a reference book: Moscow, Nedra Publishing House, 527 p.}"
}

@misc{balitov1977about3,
    author = "Balitov, N. V",
    title = "About genesis of sulphurous oils and hydrogen sulphide in gasses from Osinskii horizon of Irkutskii cirque",
    year = "1977",
    howpublished = "Geologiya i Geofizica, v. 9, p. 47-55",
    note = "talkorigins\_source = {true}; raw\_reference = {Balitov, N. V., 1977, About genesis of sulphurous oils and hydrogen sulphide in gasses from Osinskii horizon of Irkutskii cirque: Geologiya i Geofizica, v. 9, p. 47-55.}"
}

@misc{bakirov1979oil1,
    author = "Bakirov, A. A",
    title = "Oil and Gas Bearing Areas and Regions of the USSR",
    year = "1979",
    howpublished = "Moscow, Nedra Publishing House, 456 p",
    note = "talkorigins\_source = {true}; raw\_reference = {Bakirov, A. A., 1979, Oil and Gas Bearing Areas and Regions of the USSR: Moscow, Nedra Publishing House, 456 p.}"
}

@misc{goldberg1981razdelnyi4,
    author = "Gol'dberg, I. S. and Lebedev, B. A. and Frolov, B. M",
    title = "Razdel'nyi prognoz razmeshchenila gaza, nefti i bitumov na Sibirskoi platforme [Separate prediction of the distribution of gas, oil and bitumens on the Siberian Platform] [in Russian]",
    year = "1981",
    howpublished = "Geologiya Nefti i Gaza, v. 2, p. 22-26",
    note = "talkorigins\_source = {true}; raw\_reference = {Gol'dberg, I. S., Lebedev, B. A., and Frolov, B. M., 1981, Razdel'nyi prognoz razmeshchenila gaza, nefti i bitumov na Sibirskoi platforme [Separate prediction of the distribution of gas, oil and bitumens on the Siberian Platform] [in Russian]: Geologiya Nefti i Gaza, v. 2, p. 22-26.}"
}

@misc{kalinko1982geologic5,
    author = "Kalinko, M. K",
    title = "Geologic conditions for formation of gas-condensate pools of various genetic types [in Russian]",
    year = "1982",
    howpublished = "Trudy VNIGNI, v. 240, p. 5-17; English Summary in Petroleum Geology, v. 20, no.9, 1984, p.395-397",
    note = "talkorigins\_source = {true}; raw\_reference = {Kalinko, M. K., 1982, Geologic conditions for formation of gas-condensate pools of various genetic types [in Russian]: Trudy VNIGNI, v. 240, p. 5-17; English Summary in Petroleum Geology, v. 20, no.9, 1984, p.395-397.}"
}

Summary This paper presents a generalized equation of state (EOS) that represents several widely used cubic EOS'S. The generalized form is obtained by manipulation of Martin's EOS and is applied in this study. A component pseudoization procedure that preserves densities and viscosities of the pseudocomponents and the original mixture as functions of pressure and temperature is described. This procedure is applied with material balance requirements in generation of two-component, black-oil properties for gas condensates. Agreement between resulting black-oil and fully compositional simulations of gas condensate reservoir depletion is demonstrated for a very rich, near-critical condensate. Also, agreement between EOS compositional results and laboratory expansion data is shown. The fully compositional simulation necessary for below-dewpoint cycling is performed for the near-critical condensate with a wide range of component pseudoizations. Results show the well-known necessity of splitting the C7+ fraction and indicate a minimal set of about six total components necessary for acceptable accuracy. Introduction Gas condensate reservoirs are simulated frequently with fully compositional models. This paper presents a pseudoization procedure that reduces the multicomponent pseudoization procedure that reduces the multicomponent condensate fluid to a pseudo two-component mixture of surface gas and oil. This allows the use of a simpler, less expensive, modified black-oil model that accounts for both gas dissolved in oil and oil vapor in the gas. A major question in the use of the black-oil model is whether the two-component description can represent adequately the compositional phenomena active during the depletion or the cycling of gas condensate reservoirs. This question is especially pertinent to near-critical or very rich gas condensates. This paper, therefore, includes a comparison of black-oil and compositional simulations for depletion and below-dewpoint cycling of a naturally occurring, rich condensate only 15 deg. F [8.3 deg. C] above its critical temperature. Like a number of unreported cases for leaner condensates, the two models give very similar results for depletion. In addition, the two models give identical results for cycling above dewpoint provided that certain conditions are satisfied. However, the black-oil model is not applicable to cycling below dewpoint, so results of the compositional model are compared for different multi-component descriptions to estimate the minimal number and identity of components necessary for acceptable accuracy. The compositional calculations reported here use variants of the Redlich-Kwong and Peng-Robinson EOS's. This paper discusses a general cubic EOS form based on work by Martin that encompasses all these EOS's. A general-component pseudoization procedure is presented, followed by its application to gas condensates. presented, followed by its application to gas condensates. The black-oil PVT properties obtained and the agreement between laboratory test data and EOS calculated results are given for the rich condensate. Black-oil and compositional simulation results are then compared for depletion and below-dewpoint cycling of the condensate. Finally, the compositional-model cycling results are compared for different degrees of pseudoization (lumping) of components. A General Form for Cubic EOS's Use of an EOS in compositional simulation of reservoir performance and laboratory tests requires two basic performance and laboratory tests requires two basic equations that give the compressibility factor z and the fugacity of each component for a homogeneous mixture (phase). The two equations, (1a)(1b) give these quantities as functions of pressure, temperature, and phase composition × = {xi}. A number of EOS's have been developed and are in wide use. These are the Redlich and Kwong (RK), modifications by Zudkevitch and Joffee and Joffee et al. (ZJRK) and by Soave (SRK), and the Peng and Robinson (PR) EOS. Martin shows that all cubic EOS's can be represented by a single general form. Use of Martin's work and basic thermodynamic relationships yields generalized forms for Eqs. 1a and 1b as follows: (2a) JPT P. 1870

@article{doi10211810512pa,
    author = "Coats, K.H.",
    title = "Simulation of Gas Condensate Reservoir Performance",
    year = "1985",
    journal = "Journal of Petroleum Technology",
    abstract = "Summary This paper presents a generalized equation of state (EOS) that represents several widely used cubic EOS'S. The generalized form is obtained by manipulation of Martin's EOS and is applied in this study. A component pseudoization procedure that preserves densities and viscosities of the pseudocomponents and the original mixture as functions of pressure and temperature is described. This procedure is applied with material balance requirements in generation of two-component, black-oil properties for gas condensates. Agreement between resulting black-oil and fully compositional simulations of gas condensate reservoir depletion is demonstrated for a very rich, near-critical condensate. Also, agreement between EOS compositional results and laboratory expansion data is shown. The fully compositional simulation necessary for below-dewpoint cycling is performed for the near-critical condensate with a wide range of component pseudoizations. Results show the well-known necessity of splitting the C7+ fraction and indicate a minimal set of about six total components necessary for acceptable accuracy. Introduction Gas condensate reservoirs are simulated frequently with fully compositional models. This paper presents a pseudoization procedure that reduces the multicomponent pseudoization procedure that reduces the multicomponent condensate fluid to a pseudo two-component mixture of surface gas and oil. This allows the use of a simpler, less expensive, modified black-oil model that accounts for both gas dissolved in oil and oil vapor in the gas. A major question in the use of the black-oil model is whether the two-component description can represent adequately the compositional phenomena active during the depletion or the cycling of gas condensate reservoirs. This question is especially pertinent to near-critical or very rich gas condensates. This paper, therefore, includes a comparison of black-oil and compositional simulations for depletion and below-dewpoint cycling of a naturally occurring, rich condensate only 15 deg. F [8.3 deg. C] above its critical temperature. Like a number of unreported cases for leaner condensates, the two models give very similar results for depletion. In addition, the two models give identical results for cycling above dewpoint provided that certain conditions are satisfied. However, the black-oil model is not applicable to cycling below dewpoint, so results of the compositional model are compared for different multi-component descriptions to estimate the minimal number and identity of components necessary for acceptable accuracy. The compositional calculations reported here use variants of the Redlich-Kwong and Peng-Robinson EOS's. This paper discusses a general cubic EOS form based on work by Martin that encompasses all these EOS's. A general-component pseudoization procedure is presented, followed by its application to gas condensates. presented, followed by its application to gas condensates. The black-oil PVT properties obtained and the agreement between laboratory test data and EOS calculated results are given for the rich condensate. Black-oil and compositional simulation results are then compared for depletion and below-dewpoint cycling of the condensate. Finally, the compositional-model cycling results are compared for different degrees of pseudoization (lumping) of components. A General Form for Cubic EOS's Use of an EOS in compositional simulation of reservoir performance and laboratory tests requires two basic performance and laboratory tests requires two basic equations that give the compressibility factor z and the fugacity of each component for a homogeneous mixture (phase). The two equations, (1a)(1b) give these quantities as functions of pressure, temperature, and phase composition × = {xi}. A number of EOS's have been developed and are in wide use. These are the Redlich and Kwong (RK), modifications by Zudkevitch and Joffee and Joffee et al. (ZJRK) and by Soave (SRK), and the Peng and Robinson (PR) EOS. Martin shows that all cubic EOS's can be represented by a single general form. Use of Martin's work and basic thermodynamic relationships yields generalized forms for Eqs. 1a and 1b as follows: (2a) JPT P. 1870",
    url = "https://doi.org/10.2118/10512-pa",
    doi = "10.2118/10512-pa",
    openalex = "W1981646315"
}

Third SPE Comparative Solution Project: Gas Cycling of Retrograde Project: Gas Cycling of Retrograde Condensate Reservoirs Summary Nine companies participated in this artificial modeling study of gas cycling in a rich retrograde-gas-condensate reservoir. Surface oil rate predictions differ in the early years of cycling but agree better late in cycling. The amount of condensate precipitated near the production well and its rate of evaporation varied widely among participants. The explanation appears to be in K-value techniques used. Precomputed tables for K values produced rapid and thorough removal of condensate during later years of cycling. Equation-of-state (EOS) methods produced a stabilized condensate saturation sufficient to flow liquid during the greater part of cycling, and the condensate never completely revaporized. We do not know which prediction is more nearly correct because our PVT data did not cover the range of compositions that exists in this area of the reservoir model Introduction SPE conducted two earlier solution projects, both designed to measure the state-of-the-art simulation capability for challenging and timely modeling problems. The first project involved a three-layer black-oil simulation with project involved a three-layer black-oil simulation with gas injection into the top layer. Both constant and variable bubblepoint pressure assumptions were used. Model predictions were in fair agreement. No simulator predictions were in fair agreement. No simulator performance data (run times, timestep size, etc.) were given. performance data (run times, timestep size, etc.) were given. Seven companies participated in the project. The second project was a study of water and gas coning with a radial project was a study of water and gas coning with a radial grid and 15 layers. Authors of the project felt that unusual well rate variations and a high assumed solution GOR contributed to the difficulty of the problem. Some significant discrepancies in oil rate and pressure were obtained. Eleven companies joined in the project. For the third comparative solution project, the Committee for the Numerical Simulation Symposium sought a compositional modeling problem. Numerical comparisons of the PVT data match were considered important. Speed of the simulators was not to be of major interest. The problem we designed is the outcome of this fairly general request. Some features of interest in current production practice of pressure maintenance by gas injection production practice of pressure maintenance by gas injection are included. The results confirm the well-known trade-off between the timing of gas sales and the amount of condensate recovered. Several features of interest in a more complete examination of production from gas-condensate reservoirs are ignored. These include the effects of nearwell liquid saturation buildup on well productivity and of water encroachment and water production on hydrocarbon productivity. We did not address the role of numerical dispersion. In addition, the surface process is simplified and not representative of economical liquid recovery in typical offshore operations. We simplified the surface process to attract a larger number of participants because not all companies had facilities for simulating gas plant processing with gas recycling in their plant processing with gas recycling in their compositional simulators. Nine companies responded to the invitation for participation. Table 1 is a list of the participants in this project. participation. Table 1 is a list of the participants in this project. Participant responses were well prepared and required a Participant responses were well prepared and required a minimum of discussion. We invited all the companies to use as many components as necessary for the accurate match of the PVT data and for the simulation of gas cycling. Companies were asked to give components actually used in the reservoir model, how these components were characterized, and the match to the PVT data obtained with the components. We first outline the problem specifications, including sufficient data for others who may wish to try the problem. The pertinent PVT data are given. We show each problem. The pertinent PVT data are given. We show each participant's components, the properties of these participant's components, the properties of these components, and the basic PVT match obtained. In many cases, EOS methods were used exclusively, but in others, a combination of methods was applied. The results of the reservoir simulation are given and comparisons are shown between companies for both cycling-strategy cases. Finally, some facts regarding simulator performance are given, although this information was voluntary. Problem Statement Problem Statement The two major parts to a compositional model study are the PVT data and the reservoir grid. For the PVT data, participants were supplied with a companion set of fluid participants were supplied with a companion set of fluid analysis reports. The specification of the reservoir model is given in Tables 2 and 3 and the grid is shown in Fig. Note that the grid is 9 × 9 × 4 and symmetrical, indicating that it would be possible to simulate half the indicated grid. Most participants chose to model the full grid. Note also that the layers are homogeneous and of constant porosity, but that permeability and thickness vary among porosity, but that permeability and thickness vary among layers. JPT p. 981

@article{doi10211812278pa,
    author = "Kenyon, D. E.",
    title = "Third SPE Comparative Solution Project: Gas Cycling of Retrograde Condensate Reservoirs",
    year = "1987",
    journal = "Journal of Petroleum Technology",
    abstract = "Third SPE Comparative Solution Project: Gas Cycling of Retrograde Project: Gas Cycling of Retrograde Condensate Reservoirs Summary Nine companies participated in this artificial modeling study of gas cycling in a rich retrograde-gas-condensate reservoir. Surface oil rate predictions differ in the early years of cycling but agree better late in cycling. The amount of condensate precipitated near the production well and its rate of evaporation varied widely among participants. The explanation appears to be in K-value techniques used. Precomputed tables for K values produced rapid and thorough removal of condensate during later years of cycling. Equation-of-state (EOS) methods produced a stabilized condensate saturation sufficient to flow liquid during the greater part of cycling, and the condensate never completely revaporized. We do not know which prediction is more nearly correct because our PVT data did not cover the range of compositions that exists in this area of the reservoir model Introduction SPE conducted two earlier solution projects, both designed to measure the state-of-the-art simulation capability for challenging and timely modeling problems. The first project involved a three-layer black-oil simulation with project involved a three-layer black-oil simulation with gas injection into the top layer. Both constant and variable bubblepoint pressure assumptions were used. Model predictions were in fair agreement. No simulator predictions were in fair agreement. No simulator performance data (run times, timestep size, etc.) were given. performance data (run times, timestep size, etc.) were given. Seven companies participated in the project. The second project was a study of water and gas coning with a radial project was a study of water and gas coning with a radial grid and 15 layers. Authors of the project felt that unusual well rate variations and a high assumed solution GOR contributed to the difficulty of the problem. Some significant discrepancies in oil rate and pressure were obtained. Eleven companies joined in the project. For the third comparative solution project, the Committee for the Numerical Simulation Symposium sought a compositional modeling problem. Numerical comparisons of the PVT data match were considered important. Speed of the simulators was not to be of major interest. The problem we designed is the outcome of this fairly general request. Some features of interest in current production practice of pressure maintenance by gas injection production practice of pressure maintenance by gas injection are included. The results confirm the well-known trade-off between the timing of gas sales and the amount of condensate recovered. Several features of interest in a more complete examination of production from gas-condensate reservoirs are ignored. These include the effects of nearwell liquid saturation buildup on well productivity and of water encroachment and water production on hydrocarbon productivity. We did not address the role of numerical dispersion. In addition, the surface process is simplified and not representative of economical liquid recovery in typical offshore operations. We simplified the surface process to attract a larger number of participants because not all companies had facilities for simulating gas plant processing with gas recycling in their plant processing with gas recycling in their compositional simulators. Nine companies responded to the invitation for participation. Table 1 is a list of the participants in this project. participation. Table 1 is a list of the participants in this project. Participant responses were well prepared and required a Participant responses were well prepared and required a minimum of discussion. We invited all the companies to use as many components as necessary for the accurate match of the PVT data and for the simulation of gas cycling. Companies were asked to give components actually used in the reservoir model, how these components were characterized, and the match to the PVT data obtained with the components. We first outline the problem specifications, including sufficient data for others who may wish to try the problem. The pertinent PVT data are given. We show each problem. The pertinent PVT data are given. We show each participant's components, the properties of these participant's components, the properties of these components, and the basic PVT match obtained. In many cases, EOS methods were used exclusively, but in others, a combination of methods was applied. The results of the reservoir simulation are given and comparisons are shown between companies for both cycling-strategy cases. Finally, some facts regarding simulator performance are given, although this information was voluntary. Problem Statement Problem Statement The two major parts to a compositional model study are the PVT data and the reservoir grid. For the PVT data, participants were supplied with a companion set of fluid participants were supplied with a companion set of fluid analysis reports. The specification of the reservoir model is given in Tables 2 and 3 and the grid is shown in Fig. Note that the grid is 9 × 9 × 4 and symmetrical, indicating that it would be possible to simulate half the indicated grid. Most participants chose to model the full grid. Note also that the layers are homogeneous and of constant porosity, but that permeability and thickness vary among porosity, but that permeability and thickness vary among layers. JPT p. 981",
    url = "https://doi.org/10.2118/12278-pa",
    doi = "10.2118/12278-pa",
    openalex = "W2057596542"
}

Summary Preliminary results obtained from a program of experimental and theoretical studies examining the uncertainties of waterflooding gas-condensate reservoirs are reported. In spite of high trapped-gas saturations (35 to 39%), further aggravated by an unusual type of hysteresis, recoveries of gas and liquids can be increased over those obtained under natural depletion. Introduction Water injection has been suggested as a method of maintaining pressure in gas-condensate reservoirs. This method offers advantages over gas injection: gas can be sold from the start of reservoir production; the injection costs are much lower; the favorable mobility ratio ensures a high sweep efficiency; and the reservoir pressure is maintained without changing the composition, and hence the dewpoint pressure, of the gas. Water injection has not been generally accepted for gas-condensate reservoirs, however, because of the following concerns.The advancing water could trap a significant amount of gas.It may not be possible to remobilize the previously trapped gas during a subsequent depressurization.Three-phase relative permeabilities for conditions where retrograde condensation occurs are virtually unknown and may be unfavorable.Well lift could be a severe problem if there are high water cuts before and during blowdown. The first three of these factors are concerned with the flow behavior within the reservoir and are addressed in this paper. Well lift is not considered for reasons explained below. In a pioneer work, Geffen et al. showed that trapped-gas saturations following waterflood are in the same range as the residual oil saturations expected in waterflooded oil reservoirs: i.e., 15 to 50% of pore space, depending on the rock characteristics. They argued that these high values of trapped-gas saturation could substantially reduce the recovery of gas from such reservoirs as a result of their magnitude and permanence. A large number of gas reservoirs with strong underlying aquifers have been successfully developed, however, and have given moderately high gas recoveries, suggesting that at least some of the trapped gas could be remobilized during a final period of accelerated depressurization. Boyd et al. were able to depressurize the Double Bayou field after it had watered out and thus remobilize some of the residual gas. Four years after the start of the trial, they estimated that an increase in recovery of 10% of the gas initially in place (GIIP) could ultimately be recovered. Of this 10% increase, about 8% was a result of percolation of trapped gas from the watered-out zone. Brinkman found that accelerated depressurization in the Lovells Lake Frio 1 field increased the recovery from 58 to 70 % GIIP. Of the 12 % increase, nearly 10 % was caused by the trapped gas percolating from the watered-out zones. Lutes et al. obtained 8% GIIP from percolation during accelerated depressurization in the Katy field but had expected 20%. They concluded that recovery was restricted by the amount of gas that could percolate out of the waterflooded zones by high pressures arising from percolate out of the waterflooded zones by high pressures arising from unfavorable relative permeabilities.

@article{doi10211815875pa,
    author = "Matthews, John D. and Hawes, R.I. and Hawkyard, I.R. and Fishlock, T. P.",
    title = "Feasibility Studies of Waterflooding Gas-Condensate Reservoirs",
    year = "1988",
    journal = "Journal of Petroleum Technology",
    abstract = "Summary Preliminary results obtained from a program of experimental and theoretical studies examining the uncertainties of waterflooding gas-condensate reservoirs are reported. In spite of high trapped-gas saturations (35 to 39\%), further aggravated by an unusual type of hysteresis, recoveries of gas and liquids can be increased over those obtained under natural depletion. Introduction Water injection has been suggested as a method of maintaining pressure in gas-condensate reservoirs. This method offers advantages over gas injection: gas can be sold from the start of reservoir production; the injection costs are much lower; the favorable mobility ratio ensures a high sweep efficiency; and the reservoir pressure is maintained without changing the composition, and hence the dewpoint pressure, of the gas. Water injection has not been generally accepted for gas-condensate reservoirs, however, because of the following concerns.The advancing water could trap a significant amount of gas.It may not be possible to remobilize the previously trapped gas during a subsequent depressurization.Three-phase relative permeabilities for conditions where retrograde condensation occurs are virtually unknown and may be unfavorable.Well lift could be a severe problem if there are high water cuts before and during blowdown. The first three of these factors are concerned with the flow behavior within the reservoir and are addressed in this paper. Well lift is not considered for reasons explained below. In a pioneer work, Geffen et al. showed that trapped-gas saturations following waterflood are in the same range as the residual oil saturations expected in waterflooded oil reservoirs: i.e., 15 to 50\% of pore space, depending on the rock characteristics. They argued that these high values of trapped-gas saturation could substantially reduce the recovery of gas from such reservoirs as a result of their magnitude and permanence. A large number of gas reservoirs with strong underlying aquifers have been successfully developed, however, and have given moderately high gas recoveries, suggesting that at least some of the trapped gas could be remobilized during a final period of accelerated depressurization. Boyd et al. were able to depressurize the Double Bayou field after it had watered out and thus remobilize some of the residual gas. Four years after the start of the trial, they estimated that an increase in recovery of 10\% of the gas initially in place (GIIP) could ultimately be recovered. Of this 10\% increase, about 8\% was a result of percolation of trapped gas from the watered-out zone. Brinkman found that accelerated depressurization in the Lovells Lake Frio 1 field increased the recovery from 58 to 70 \% GIIP. Of the 12 \% increase, nearly 10 \% was caused by the trapped gas percolating from the watered-out zones. Lutes et al. obtained 8\% GIIP from percolation during accelerated depressurization in the Katy field but had expected 20\%. They concluded that recovery was restricted by the amount of gas that could percolate out of the waterflooded zones by high pressures arising from percolate out of the waterflooded zones by high pressures arising from unfavorable relative permeabilities.",
    url = "https://doi.org/10.2118/15875-pa",
    doi = "10.2118/15875-pa",
    openalex = "W1967047948"
}

Development options for gas condensate reservoirs are to depressurise the reservoir, maintain the pressure by water injection or to maintain the pressure by gas injection. The depressurisation option may itself allow water to flood the reservoir from any attached aquifer. Thus, evaluation of the options depends critically on the interaction between the condensate and water. This paper describes a series of low pressure core flooding experiments carried out to investigate these interactions.

@article{doi10399722144609201411214,
    author = "Naylor, Peter and Sargent, N. C.",
    title = "An experimental study of waterflooding and depressurisation relevant to gas condensate reservoirs",
    year = "1991",
    abstract = "Development options for gas condensate reservoirs are to depressurise the reservoir, maintain the pressure by water injection or to maintain the pressure by gas injection. The depressurisation option may itself allow water to flood the reservoir from any attached aquifer. Thus, evaluation of the options depends critically on the interaction between the condensate and water. This paper describes a series of low pressure core flooding experiments carried out to investigate these interactions.",
    url = "https://doi.org/10.3997/2214-4609.201411214",
    doi = "10.3997/2214-4609.201411214",
    openalex = "W1966361892"
}

The phase and flow behaviour of water, gas and condensate in pores at reservoir conditions have been visually investigated using glass micromodels with realistic pore pattems and geometry. The displacement of hydrocarbons, both above and below the dew point, by the advancing water was studied. The model at residual hydrocarbon saturation was depleted and the remobilisation behaviour of the trapped gascondensate phases was investigated. Preliminary core flooding results obtained at conditions similar to the micromodel tests confirm the observed phenomena.

@article{doi10399722144609201411269,
    author = "Henderson, Graeme D and Danesh, Ali and Peden, J. M.",
    title = "An experimental investigation of waterflooding of gas condensate reservoirs and their subsequent blowdown",
    year = "1991",
    abstract = "The phase and flow behaviour of water, gas and condensate in pores at reservoir conditions have been visually investigated using glass micromodels with realistic pore pattems and geometry. The displacement of hydrocarbons, both above and below the dew point, by the advancing water was studied. The model at residual hydrocarbon saturation was depleted and the remobilisation behaviour of the trapped gascondensate phases was investigated. Preliminary core flooding results obtained at conditions similar to the micromodel tests confirm the observed phenomena.",
    url = "https://doi.org/10.3997/2214-4609.201411269",
    doi = "10.3997/2214-4609.201411269",
    openalex = "W2173527758"
}

Abstract During the production of gas condensate reservoirs which have underlying aquifers present, large areas of the reservoir can be invaded by water during pressure reduction, resulting in the entrapment of large quantities of hydrocarbons. In order to simulate this process in the laboratory, experiments were conducted using gas and condensate saturated cores which were initially flooded with water to simulate the entrapment of hydrocarbons. Pressure reduction of the cores was then initiated in order to allow the hydrocarbons to expand and reach a critical hydrocarbon saturation at which hydrocarbons remobilised. It was found that the average critical hydrocarbon saturation required for remobilisation of hydrocarbons was approximately 0.56, which was about 0.12 higher than the initial hydrocarbon saturation. Pressure reduction was initiated at different stages in the phase behaviour of the gas condensate fluid in the cores. This appeared to have only a minor effect on the hydrocarbon expansion required for remobilisation when the initial hydrocarbon saturations were similar. The results highlighted significant differences between the hydrocarbon expansion required for remobilisation, the fluid production profiles after remobilisation, and the effect of pressure reduction rate on remobilisation, for the gas condensate compared to a single phase gas.

@article{doi10211825070ms,
    author = "Henderson, Graeme D and Danesh, Ali and Tehrani, D. H. and Peden, J. M.",
    title = "Remobilisation of Trapped Hydrocarbons in Water-Invaded Zones of Gas Condensate Reservoirs",
    year = "1992",
    journal = "All Days",
    abstract = "Abstract During the production of gas condensate reservoirs which have underlying aquifers present, large areas of the reservoir can be invaded by water during pressure reduction, resulting in the entrapment of large quantities of hydrocarbons. In order to simulate this process in the laboratory, experiments were conducted using gas and condensate saturated cores which were initially flooded with water to simulate the entrapment of hydrocarbons. Pressure reduction of the cores was then initiated in order to allow the hydrocarbons to expand and reach a critical hydrocarbon saturation at which hydrocarbons remobilised. It was found that the average critical hydrocarbon saturation required for remobilisation of hydrocarbons was approximately 0.56, which was about 0.12 higher than the initial hydrocarbon saturation. Pressure reduction was initiated at different stages in the phase behaviour of the gas condensate fluid in the cores. This appeared to have only a minor effect on the hydrocarbon expansion required for remobilisation when the initial hydrocarbon saturations were similar. The results highlighted significant differences between the hydrocarbon expansion required for remobilisation, the fluid production profiles after remobilisation, and the effect of pressure reduction rate on remobilisation, for the gas condensate compared to a single phase gas.",
    url = "https://doi.org/10.2118/25070-ms",
    doi = "10.2118/25070-ms",
    openalex = "W1998481961",
    references = "doi10211815455pa, doi10211819693pa, doi10211822636pa, doi10399722144609201411214, doi10399722144609201411269"
}

Abstract Laboratory experiments on gas condensate flow behavior were conducted under reservoir conditions. Two North Sea gas condensate reservoirs that have distinct rock and fluid properties were studied. The objectives of the corefloods were to investigate the effects of rock and fluid characteristics on critical condensate saturation (CCS), gas and condensate relative permeabilities during in-situ condensation, hydrocarbon recovery and trapping by water injection, and incremental hydrocarbon recovery by subsequent blowdown. It was found that both CCS and relative permeability were sensitive to flow rate and interfacial tension. The results on gas relative permeability rate sensitivity suggest that gas productivity curtailed by condensate drop out can be somewhat restored by increasing production rate. Phase behavior and interfacial tension influence the extents of gas relative permeability reduction and condensate mobility. High interfacial tension ultimately caused condensate relative permeability to decrease with increasing condensate saturation. Condensate immobile under gas injection could be recovered by water injection, but more immediate and efficient condensate recovery was observed when the condensate saturation prior to water injection exceeded the CCS. Approximately 27 %PV gas was trapped by water injection. Subsequent blowdown recovered additional gas, but incremental condensate recovery was insignificant.

@article{doi10211830769ms,
    author = "Chen, H. L. and Wilson, Sam and Monger-McClure, T. G.",
    title = "Determination of Relative Permeability and Recovery for North Sea Gas Condensate Reservoirs",
    year = "1995",
    journal = "SPE Annual Technical Conference and Exhibition",
    abstract = "Abstract Laboratory experiments on gas condensate flow behavior were conducted under reservoir conditions. Two North Sea gas condensate reservoirs that have distinct rock and fluid properties were studied. The objectives of the corefloods were to investigate the effects of rock and fluid characteristics on critical condensate saturation (CCS), gas and condensate relative permeabilities during in-situ condensation, hydrocarbon recovery and trapping by water injection, and incremental hydrocarbon recovery by subsequent blowdown. It was found that both CCS and relative permeability were sensitive to flow rate and interfacial tension. The results on gas relative permeability rate sensitivity suggest that gas productivity curtailed by condensate drop out can be somewhat restored by increasing production rate. Phase behavior and interfacial tension influence the extents of gas relative permeability reduction and condensate mobility. High interfacial tension ultimately caused condensate relative permeability to decrease with increasing condensate saturation. Condensate immobile under gas injection could be recovered by water injection, but more immediate and efficient condensate recovery was observed when the condensate saturation prior to water injection exceeded the CCS. Approximately 27 \%PV gas was trapped by water injection. Subsequent blowdown recovered additional gas, but incremental condensate recovery was insignificant.",
    url = "https://doi.org/10.2118/30769-ms",
    doi = "10.2118/30769-ms",
    openalex = "W2120235335",
    references = "doi10211822636pa"
}

In the last year the authors have fielded many questions from companies, both international and domestic, concerning gas condensate reservoirs. It appears that gas condensates are becoming more important throughout the world. Many international petroleum societies are beginning to have conferences specifically oriented to gas condensate reservoirs and discussing all parameters germane to such systems. In light of this increased interest, the authors have made a short list of questions which are most often asked. Indeed, these questions point to two specific areas which govern the production and future exploitation plans for gas condensate systems. These two areas are characterization and retrograde condensate influences on relative permeability. It has been found that the characterization of the gas condensate fluids can be strongly influenced by two main factors:Any degree of contamination by a free liquid phase insitu;Hold-up of the retrograde condensate in the formation resulting in excessive producing GOR's. Care must be taken when sampling gas condensate wells n order to produce representative recombined fluids. In order to gain an appropriate evaluation of the gas condensate reservoir one must be able to adequately characterize the fluids insitu. Experimental and theoretical work performed on evaluating retrograde condensate effects has pointed to the fact that the influence of retrograde condensate is much more deleterious in tighter formations and higher interfacial fluids. The ability to identify the influence of retrograde liquid on gas phase production rates is a difficult task and data are provided herein which compare the retrograde condensate effects at two levels of interfacial tension and as a function of rock permeability. It has been found that in a review of four gas condensate reservoirs, one of which included a fractured system, there was a coupling of a multiplicity of factors including:Interfacial tension effectsViscosity ratioThe healing of fractures with its concomitant effect on absolute permeability In order to adequately forecast such systems, a simulator must in corporate these effects. Sampling condensate reservoirs Condensate reservoirs are inherently more difficult to characterize correctly. The literature shows many differences between gas condensate reservoirs and dry gas reservoirs(l-6). One question often asked is during and after sampling. Figure 1 provides a fairly typical GOR versus total flow rate response from a gas condensate reservoir. One sees that, at very low flow rates, one has a high producing GOR and, beyond the certain minimum value in GOR, the trend is again upwards It is easy to identify why this occurs, but sometimes, when faced with the possibility of having extra sampling runs and spending more time in the field, the generation of a plot such as Figure 1 is not easy. In the same plot one compares the response which would normally be seen for an oil reservoir. With the oil reservoir, the sampling technique is fairly easy to specify. All one must do is try to produce the well in the domain low enough so that a constant GOR is produced. Since the behavior is asymptotic as a function of decreasing total flow rate from the well, it is easy to identify what production level one needs to apply for taking the gas and liquid samples.

@inproceedings{thomas1995towards,
    author = "Thomas, F.B. and Zhou, X. and Bennion, D.B. and Bennion, D.W.",
    title = "Towards Optimizing Gas Condensate Reservoirs",
    year = "1995",
    booktitle = "Annual Technical Meeting",
    abstract = "In the last year the authors have fielded many questions from companies, both international and domestic, concerning gas condensate reservoirs. It appears that gas condensates are becoming more important throughout the world. Many international petroleum societies are beginning to have conferences specifically oriented to gas condensate reservoirs and discussing all parameters germane to such systems. In light of this increased interest, the authors have made a short list of questions which are most often asked. Indeed, these questions point to two specific areas which govern the production and future exploitation plans for gas condensate systems. These two areas are characterization and retrograde condensate influences on relative permeability. It has been found that the characterization of the gas condensate fluids can be strongly influenced by two main factors:Any degree of contamination by a free liquid phase insitu;Hold-up of the retrograde condensate in the formation resulting in excessive producing GOR's. Care must be taken when sampling gas condensate wells n order to produce representative recombined fluids. In order to gain an appropriate evaluation of the gas condensate reservoir one must be able to adequately characterize the fluids insitu. Experimental and theoretical work performed on evaluating retrograde condensate effects has pointed to the fact that the influence of retrograde condensate is much more deleterious in tighter formations and higher interfacial fluids. The ability to identify the influence of retrograde liquid on gas phase production rates is a difficult task and data are provided herein which compare the retrograde condensate effects at two levels of interfacial tension and as a function of rock permeability. It has been found that in a review of four gas condensate reservoirs, one of which included a fractured system, there was a coupling of a multiplicity of factors including:Interfacial tension effectsViscosity ratioThe healing of fractures with its concomitant effect on absolute permeability In order to adequately forecast such systems, a simulator must in corporate these effects. Sampling condensate reservoirs Condensate reservoirs are inherently more difficult to characterize correctly. The literature shows many differences between gas condensate reservoirs and dry gas reservoirs(l-6). One question often asked is during and after sampling. Figure 1 provides a fairly typical GOR versus total flow rate response from a gas condensate reservoir. One sees that, at very low flow rates, one has a high producing GOR and, beyond the certain minimum value in GOR, the trend is again upwards It is easy to identify why this occurs, but sometimes, when faced with the possibility of having extra sampling runs and spending more time in the field, the generation of a plot such as Figure 1 is not easy. In the same plot one compares the response which would normally be seen for an oil reservoir. With the oil reservoir, the sampling technique is fairly easy to specify. All one must do is try to produce the well in the domain low enough so that a constant GOR is produced. Since the behavior is asymptotic as a function of decreasing total flow rate from the well, it is easy to identify what production level one needs to apply for taking the gas and liquid samples.",
    url = "https://doi.org/10.2118/95-09",
    doi = "10.2118/95-09",
    openalex = "W2025110695",
    references = "doi1010160016003259903692, doi101016002197978390396x, doi101016s0376736108x70013, doi10211819729pa, doi1021189354"
}

Summary Gas-condensate reservoirs are usually produced by primary depletion. This technique is normally an efficient means of producing the gaseous hydrocarbon components but can be very inefficient in producing the more valuable liquid components that are left in the reservoir in a condensed liquid phase (oil). The recovery efficiency of the liquid components decreases with increasing richness of the gas condensate, making for a large improved oil recovery (IOR) target in some reservoirs. The usual approach to improving liquid recovery is to recycle produced gas through the reservoir. However, this technique may not be economically attractive when there is the possibility of immediate gas sales because of the discounting applied to the gas value when sales are delayed. An alternative means of improving liquid recovery is to keep the reservoir pressure above the dewpoint for a period by injecting water. Depending on reservoir characteristics, water injection may be continued throughout field life or the reservoir may be pressure depleted after a period of injection. Special relative permeability data, describing the mobilization of waterflood trapped gas by expansion, are necessary for the latter case. This paper reports a simulation study that quantifies the potential benefits of the waterflood technique by use of simple reservoir models. For a fluid with a condensate to gas ratio (CGR) of 180 STB/ MMscf, total hydrocarbon recovery was optimized by injecting 0.25 hydrocarbon PV of water before pressure depletion. This increased the recovery efficiency of both the liquid and gaseous components, raising the total hydrocarbon recovery by 10% of the hydrocarbon mass initially present in the reservoir. For a richer, near-critical fluid with a CGR of 300 STB/MMscf, continued water injection gave the optimum total recovery, which was 21% of initial mass higher than for primary depletion. This improvement was achieved by greatly increasing the liquids recovery at the expense of a smaller reduction in the gas recovery. The results of this paper suggest that waterflooding of gas-condensate reservoirs might be a valuable IOR technique.

@article{fishlock1996waterflooding,
    author = "Fishlock, T. P. and Probert, C. J.",
    title = "Waterflooding of Gas-Condensate Reservoirs",
    year = "1996",
    journal = "SPE Reservoir Engineering",
    abstract = "Summary Gas-condensate reservoirs are usually produced by primary depletion. This technique is normally an efficient means of producing the gaseous hydrocarbon components but can be very inefficient in producing the more valuable liquid components that are left in the reservoir in a condensed liquid phase (oil). The recovery efficiency of the liquid components decreases with increasing richness of the gas condensate, making for a large improved oil recovery (IOR) target in some reservoirs. The usual approach to improving liquid recovery is to recycle produced gas through the reservoir. However, this technique may not be economically attractive when there is the possibility of immediate gas sales because of the discounting applied to the gas value when sales are delayed. An alternative means of improving liquid recovery is to keep the reservoir pressure above the dewpoint for a period by injecting water. Depending on reservoir characteristics, water injection may be continued throughout field life or the reservoir may be pressure depleted after a period of injection. Special relative permeability data, describing the mobilization of waterflood trapped gas by expansion, are necessary for the latter case. This paper reports a simulation study that quantifies the potential benefits of the waterflood technique by use of simple reservoir models. For a fluid with a condensate to gas ratio (CGR) of 180 STB/ MMscf, total hydrocarbon recovery was optimized by injecting 0.25 hydrocarbon PV of water before pressure depletion. This increased the recovery efficiency of both the liquid and gaseous components, raising the total hydrocarbon recovery by 10\% of the hydrocarbon mass initially present in the reservoir. For a richer, near-critical fluid with a CGR of 300 STB/MMscf, continued water injection gave the optimum total recovery, which was 21\% of initial mass higher than for primary depletion. This improvement was achieved by greatly increasing the liquids recovery at the expense of a smaller reduction in the gas recovery. The results of this paper suggest that waterflooding of gas-condensate reservoirs might be a valuable IOR technique.",
    url = "https://doi.org/10.2118/35370-pa",
    doi = "10.2118/35370-pa",
    number = "04",
    openalex = "W2077759576",
    pages = "245-251",
    volume = "11",
    references = "doi10211811277pa, doi10211815875pa, doi10211816355ms, doi1021181942pa, doi10211822636pa, doi10211825070ms, doi1021185106pa, openalexw1573752853, openalexw3213753921, openalexw560405057"
}

Summary Coreflood experiments on gas condensate flow behavior were conducted for two North Sea gas condensate reservoirs. The objectives were to investigate the effects of rock and fluid characteristics on critical condensate saturation (CCS), gas and condensate relative permeabilities, hydrocarbon recovery and trapping by water injection, and incremental recovery by subsequent blowdown. Both CCS and relative permeability were sensitive to flow rate and interfacial tension. The results on gas relative permeability rate sensitivity suggest that gas productivity curtailed by condensate dropout can be somewhat restored by increasing production rate. High interfacial tension ultimately caused condensate relative permeability to decrease with increasing condensate saturation. Condensate immobile under gas injection could be recovered by water injection, but more immediate and efficient condensate recovery was observed when the condensate saturation prior to water injection exceeded the CCS. Subsequent blowdown recovered additional gas, but incremental condensate recovery was insignificant.

@article{doi10211857596pa,
    author = "Chen, H. L. and Wilson, Sam and Monger-McClure, T. G.",
    title = "Determination of Relative Permeability and Recovery for North Sea Gas-Condensate Reservoirs",
    year = "1999",
    journal = "SPE Reservoir Evaluation \& Engineering",
    abstract = "Summary Coreflood experiments on gas condensate flow behavior were conducted for two North Sea gas condensate reservoirs. The objectives were to investigate the effects of rock and fluid characteristics on critical condensate saturation (CCS), gas and condensate relative permeabilities, hydrocarbon recovery and trapping by water injection, and incremental recovery by subsequent blowdown. Both CCS and relative permeability were sensitive to flow rate and interfacial tension. The results on gas relative permeability rate sensitivity suggest that gas productivity curtailed by condensate dropout can be somewhat restored by increasing production rate. High interfacial tension ultimately caused condensate relative permeability to decrease with increasing condensate saturation. Condensate immobile under gas injection could be recovered by water injection, but more immediate and efficient condensate recovery was observed when the condensate saturation prior to water injection exceeded the CCS. Subsequent blowdown recovered additional gas, but incremental condensate recovery was insignificant.",
    url = "https://doi.org/10.2118/57596-pa",
    doi = "10.2118/57596-pa",
    openalex = "W2122169610",
    references = "doi10211822636pa, doi10211825070ms"
}

Abstract Testing of gas condensate reservoirs requires careful coordination of all parameters in the analytical process. Therefore, the sampling procedure, the laboratory analysis of the collected samples, the design of the testing equipment, and the design and analysis of the test itself are all critical to the accuracy of the analysis. This paper will outline the methodology and procedures used in testing gas condensate reservoirs. Obtaining a representative formation fluid sample that may be used for compositional and pressure-volume-temperature (PVT) analysis is crucial in testing gas condensate reservoirs. In most cases, this means maintaining a monophasic sample as close as possible to actual reservoir conditions. New sampling technologies have been introduced that improve the quality of the initial sample and can maintain the sample integrity. Additionally, new downhole sensor technologies show promise of improving sample contamination estimates and making in-situ fluid property measurements. The various sampling techniques are discussed, and comparisons of processes that include wireline formation testing and bottomhole sampling, isokinetic sampling used in drillstem and production testing, and surface sampling are made. Laboratory testing procedures including sample quality validation, error propagation, and sample contamination are also discussed. The flow of gas condensate in a reservoir is a complicated mathematical problem involving phase changes, condensate loss into the small pores of the rock, multi-phase-flow of the wet gas oil and possibly water, phase redistribution in and around the wellbore, and finally, liquid vaporization back into the condensate gas. A well test can provide identification of the absolute reservoir and relative permeabilities, the source of declining gas permeability, near wellbore damage, and the reservoir pressure. It can also distinguish the extent of the liquid-condensate bank that forms a composite reservoir, as well as the location of the nearby boundaries. The analysis procedure and techniques will be illustrated through presentation of two field cases. In the first case, the flowing pressure is above the dewpoint pressure. Thus, the fluid inside the reservoir is a single-phase gas, and liquid dropout causes phase segregation in the wellbore. In the second case, the well is producing below the dewpoint pressure while the original reservoir pressure is above the dewpoint pressure. This caused the well test to resemble that of a composite reservoir with earlier phase-segregation effects.

@article{doi10211868668ms,
    author = "Kool, Henk and Azari, Mehdi and Soliman, M. Y. and Proett, Mark and Irani, Cyrus A. and Bjørn, Dybdahl",
    title = "Testing of Gas Condensate Reservoirs - Sampling, Test Design and Analysis",
    year = "2001",
    journal = "SPE Asia Pacific Oil and Gas Conference and Exhibition",
    abstract = "Abstract Testing of gas condensate reservoirs requires careful coordination of all parameters in the analytical process. Therefore, the sampling procedure, the laboratory analysis of the collected samples, the design of the testing equipment, and the design and analysis of the test itself are all critical to the accuracy of the analysis. This paper will outline the methodology and procedures used in testing gas condensate reservoirs. Obtaining a representative formation fluid sample that may be used for compositional and pressure-volume-temperature (PVT) analysis is crucial in testing gas condensate reservoirs. In most cases, this means maintaining a monophasic sample as close as possible to actual reservoir conditions. New sampling technologies have been introduced that improve the quality of the initial sample and can maintain the sample integrity. Additionally, new downhole sensor technologies show promise of improving sample contamination estimates and making in-situ fluid property measurements. The various sampling techniques are discussed, and comparisons of processes that include wireline formation testing and bottomhole sampling, isokinetic sampling used in drillstem and production testing, and surface sampling are made. Laboratory testing procedures including sample quality validation, error propagation, and sample contamination are also discussed. The flow of gas condensate in a reservoir is a complicated mathematical problem involving phase changes, condensate loss into the small pores of the rock, multi-phase-flow of the wet gas oil and possibly water, phase redistribution in and around the wellbore, and finally, liquid vaporization back into the condensate gas. A well test can provide identification of the absolute reservoir and relative permeabilities, the source of declining gas permeability, near wellbore damage, and the reservoir pressure. It can also distinguish the extent of the liquid-condensate bank that forms a composite reservoir, as well as the location of the nearby boundaries. The analysis procedure and techniques will be illustrated through presentation of two field cases. In the first case, the flowing pressure is above the dewpoint pressure. Thus, the fluid inside the reservoir is a single-phase gas, and liquid dropout causes phase segregation in the wellbore. In the second case, the well is producing below the dewpoint pressure while the original reservoir pressure is above the dewpoint pressure. This caused the well test to resemble that of a composite reservoir with earlier phase-segregation effects.",
    url = "https://doi.org/10.2118/68668-ms",
    doi = "10.2118/68668-ms",
    openalex = "W2011174284",
    references = "crossref2002gascondensate, doi1010160016003259903692, doi102118219g, doi10211826496pa, doi10211828829ms, doi10211838649ms, doi10252330766ms, doi10252362920ms, doi10252363071ms, doi10252364650ms, openalexw1481537814"
}

@incollection{crossref2002gascondensate,
    title = "Gas/Condensate Reservoirs",
    year = "2002",
    booktitle = "Fundamental Principles of Reservoir Engineering",
    url = "https://doi.org/10.2118/9781555630928-10",
    doi = "10.2118/9781555630928-10",
    openalex = "W4300259531",
    pages = "104-117"
}

Abstract Coreflood experiments were conducted on carbonate and sandstone cores from gas-condensate reservoirs in Saudi Arabia to assess the loss in gas relative permeability caused by condensate accumulation and water blockage. Field samples of condensate were used in these experiments to mimic two-phase flow around the wellbore region when the bottom hole flowing pressure dropped below the dewpoint. The impact of several fluids used as completion fluids was also investigated at reservoir conditions. Several solvents were evaluated to remove both condensate and water blockages. Experimental results show that reductions of 70% to 95% in gas relative permeability were seen in reservoir cores due to condensate blockage. The studied solvents were found to be effective for enhancing gas relative permeability. This study also quantified the required methanol treatment volumes to increase gas relative permeability at lab conditions, which could be extrapolated to field conditions. The reduction in gas relative permeability was more pronounced during two-phase flow in the presence of water saturation due to the dual effect of condensate and water blockage. Methanol displaces retrograde condensate and maintains improved gas relative permeability well into the post-treatment production period. Methanol-water mixtures were ineffective in removing condensate blockage and decreased gas productivity after their treatment. Methanol was effective in removing water from the cores. A mixture of isopropyl alcohol and methanol yielded similar favorable results as pure methanol. In summary, the evaluated solvents were all effective in removing condensate blockage from the core, delayed condensate accumulation, and enhanced gas productivity.

@article{doi10211893210ms,
    author = "Al-Anazi, Hamoud and Solares, J. Ricardo and Al-Faifi, M. G.",
    title = "The Impact of Condensate Blockage and Completion Fluids on Gas Productivity in Gas-Condensate Reservoirs",
    year = "2005",
    journal = "SPE Asia Pacific Oil and Gas Conference and Exhibition",
    abstract = "Abstract Coreflood experiments were conducted on carbonate and sandstone cores from gas-condensate reservoirs in Saudi Arabia to assess the loss in gas relative permeability caused by condensate accumulation and water blockage. Field samples of condensate were used in these experiments to mimic two-phase flow around the wellbore region when the bottom hole flowing pressure dropped below the dewpoint. The impact of several fluids used as completion fluids was also investigated at reservoir conditions. Several solvents were evaluated to remove both condensate and water blockages. Experimental results show that reductions of 70\% to 95\% in gas relative permeability were seen in reservoir cores due to condensate blockage. The studied solvents were found to be effective for enhancing gas relative permeability. This study also quantified the required methanol treatment volumes to increase gas relative permeability at lab conditions, which could be extrapolated to field conditions. The reduction in gas relative permeability was more pronounced during two-phase flow in the presence of water saturation due to the dual effect of condensate and water blockage. Methanol displaces retrograde condensate and maintains improved gas relative permeability well into the post-treatment production period. Methanol-water mixtures were ineffective in removing condensate blockage and decreased gas productivity after their treatment. Methanol was effective in removing water from the cores. A mixture of isopropyl alcohol and methanol yielded similar favorable results as pure methanol. In summary, the evaluated solvents were all effective in removing condensate blockage from the core, delayed condensate accumulation, and enhanced gas productivity.",
    url = "https://doi.org/10.2118/93210-ms",
    doi = "10.2118/93210-ms",
    openalex = "W2035483863"
}

Abstract Gas wells in tight reservoirs have shown low gas deliverability after drilling and completion operations. This is partially attributed to penetration of completion fluids into the near the wellbore. This increase of liquid saturation into the reservoir can play a significant role in the blocking of tight rock due to high capillary forces and vapor pressure. The scope of this study was to investigate the impact of completion fluids on gas productivity in carbonate and sandstone reservoirs, and to evaluate feasibility of using various solvents to remove and/or minimize liquid blocking effects. In this study, extensive coreflood experiments were conducted on carbonate and sandstone cores recovered from gas reservoirs in Saudi Arabia to assess the loss in gas relative permeability caused by several fluids used as completion fluids. Alcohols were also evaluated as solvents to remove or minimize water blockage. Interfacial tension of fluids was measured using the pendent drop method at reservoir conditions. Experimental results showed that the used completion fluids (brines, KCl, alcoholic brines, and diesel) caused a severe reduction in gas productivity. The clean-up of these fluids was found to be a very slow process and is a function of capillary forces. Neat diesel caused a decline in the gas productivity index (PI) more than brine because it has a lower mobility. The solvents used were effective in displacing the completion fluids studied and consequently restoring gas productivity. Mixing brine with alcohol speedup the cleanup of trapped liquids.

@article{doi10211894256ms,
    author = "Al-Anazi, Hamoud and Okasha, Taha and Haas, Michael and Ginest, Noel and Al-Faifi, M. G.",
    title = "Impact of Completion Fluids on Productivity in Gas/Condensate Reservoirs",
    year = "2005",
    journal = "SPE Production Operations Symposium",
    abstract = "Abstract Gas wells in tight reservoirs have shown low gas deliverability after drilling and completion operations. This is partially attributed to penetration of completion fluids into the near the wellbore. This increase of liquid saturation into the reservoir can play a significant role in the blocking of tight rock due to high capillary forces and vapor pressure. The scope of this study was to investigate the impact of completion fluids on gas productivity in carbonate and sandstone reservoirs, and to evaluate feasibility of using various solvents to remove and/or minimize liquid blocking effects. In this study, extensive coreflood experiments were conducted on carbonate and sandstone cores recovered from gas reservoirs in Saudi Arabia to assess the loss in gas relative permeability caused by several fluids used as completion fluids. Alcohols were also evaluated as solvents to remove or minimize water blockage. Interfacial tension of fluids was measured using the pendent drop method at reservoir conditions. Experimental results showed that the used completion fluids (brines, KCl, alcoholic brines, and diesel) caused a severe reduction in gas productivity. The clean-up of these fluids was found to be a very slow process and is a function of capillary forces. Neat diesel caused a decline in the gas productivity index (PI) more than brine because it has a lower mobility. The solvents used were effective in displacing the completion fluids studied and consequently restoring gas productivity. Mixing brine with alcohol speedup the cleanup of trapped liquids.",
    url = "https://doi.org/10.2118/94256-ms",
    doi = "10.2118/94256-ms",
    openalex = "W2054967725"
}

Abstract Gas condensate reservoirs experience significant productivity losses as reservoir pressure drops below the dewpoint due to condensate accumulation and the subsequent reduction in gas relative permeability. One potential way to overcome this problem is to alter reservoir wettability to gas-wetting to reduce condensate accumulation in the near-wellbore and maintain high productivity. The aim of this study was to evaluate the effectiveness of various chemical treatments in altering wettability of gas-condensate reservoirs from liquid wetting to intermediate gas wetting. Coreflood experiments were conducted on carbonate and sandstone reservoir cores and Berea cores at simulated reservoir conditions. Several chemicals (fluorochemical and silane) were screened in this study to determine their capability in removing the trapped condensate from cores, enhancing gas relative permeability, and delaying condensate accumulation. The results of coreflood tests showed that the effectiveness of fluorochemical surfactant is affected by treatment volume, aging time, core permeability and temperature. Sandstone cores treated with 1.25 wt% silane chemical showed repellency to liquids (water and condensate) and an enhancement (up to 42%) in gas relative permeability. It was found that core permeability plays a role in wettability alteration agents' effectiveness. Wettability tests showed that contact angle on treated cores is 116° for water and 114° for condensate, indicating wettability alteration from liquid to intermediate gas wetting. Environmental Scanning Electron Microscope (ESEM) analysis performed on silanes-treated cores gave a conclusive evidence of wettability alteration at the pore scale.

@article{doi102118107493ms,
    author = "Al-Anazi, Hamoud and Xiao, J. J. and Aleidan, Ahmed and Buhidma, Ismail M. and Ahmed, Mahbub S. and Al-Faifi, Mohammad and Assiri, Wisam",
    title = "Gas Productivity Enhancement by Wettability Alteration of Gas-Condensate Reservoirs",
    year = "2007",
    abstract = "Abstract Gas condensate reservoirs experience significant productivity losses as reservoir pressure drops below the dewpoint due to condensate accumulation and the subsequent reduction in gas relative permeability. One potential way to overcome this problem is to alter reservoir wettability to gas-wetting to reduce condensate accumulation in the near-wellbore and maintain high productivity. The aim of this study was to evaluate the effectiveness of various chemical treatments in altering wettability of gas-condensate reservoirs from liquid wetting to intermediate gas wetting. Coreflood experiments were conducted on carbonate and sandstone reservoir cores and Berea cores at simulated reservoir conditions. Several chemicals (fluorochemical and silane) were screened in this study to determine their capability in removing the trapped condensate from cores, enhancing gas relative permeability, and delaying condensate accumulation. The results of coreflood tests showed that the effectiveness of fluorochemical surfactant is affected by treatment volume, aging time, core permeability and temperature. Sandstone cores treated with 1.25 wt\% silane chemical showed repellency to liquids (water and condensate) and an enhancement (up to 42\%) in gas relative permeability. It was found that core permeability plays a role in wettability alteration agents' effectiveness. Wettability tests showed that contact angle on treated cores is 116° for water and 114° for condensate, indicating wettability alteration from liquid to intermediate gas wetting. Environmental Scanning Electron Microscope (ESEM) analysis performed on silanes-treated cores gave a conclusive evidence of wettability alteration at the pore scale.",
    url = "https://doi.org/10.2118/107493-ms",
    doi = "10.2118/107493-ms",
    openalex = "W2045121780",
    references = "doi10211822636pa"
}

Abstract The complex behavior exhibited by gas condensate reservoirs due to the existence of a two-phase system: reservoir gas and liquid condensate and its implications plus the nature of heterogeneities is the subject of the present article which involves handling of reservoir engineering concepts subject to be interpreted, so that by coupling them with pressure transient analysis using a compositional simulator, we can obtain some patterns which lead to facilitate the understanding of the reservoir's dynamics. Great volumes of fluids are stored in Naturally Fractured Reservoirs (NFR). Simulation of this type of deposits presents great challenges, from not only the geomechanical point of view but also the thermodynamical modeling of the different phases flowing throughout the fracture system. In this work, we present an attempt to model a gas condensate formation involving the implications of relative permeabilities to observe their effect on the flow behavior once pressure finally falls below the dewpoint and the effect of the capillary number on the fluid flow phenomena in the near-wellbore region. Interpretation of the pressure test is conducted by the TDS technique.

@article{doi102118107721ms,
    author = "Escobar, Freddy Humberto and Garcia-Rocha, Humberto and Suaza, Ivan Mauricio and Cantillo, José Humberto",
    title = "Well Pressure Behavior for a Vertical Well in a Gas Condensate Naturally-Fractured Reservoir",
    year = "2007",
    abstract = "Abstract The complex behavior exhibited by gas condensate reservoirs due to the existence of a two-phase system: reservoir gas and liquid condensate and its implications plus the nature of heterogeneities is the subject of the present article which involves handling of reservoir engineering concepts subject to be interpreted, so that by coupling them with pressure transient analysis using a compositional simulator, we can obtain some patterns which lead to facilitate the understanding of the reservoir's dynamics. Great volumes of fluids are stored in Naturally Fractured Reservoirs (NFR). Simulation of this type of deposits presents great challenges, from not only the geomechanical point of view but also the thermodynamical modeling of the different phases flowing throughout the fracture system. In this work, we present an attempt to model a gas condensate formation involving the implications of relative permeabilities to observe their effect on the flow behavior once pressure finally falls below the dewpoint and the effect of the capillary number on the fluid flow phenomena in the near-wellbore region. Interpretation of the pressure test is conducted by the TDS technique.",
    url = "https://doi.org/10.2118/107721-ms",
    doi = "10.2118/107721-ms",
    openalex = "W2087459851",
    references = "doi10211868668ms"
}

@inproceedings{alanazi2010effective,
    author = "Al-Anazi, Hamoud Ali and Baqawi, Ahmad and Aziz, Ahmad Azly Abdul and Kanaan, Adnan A.",
    title = "Effective Strategies in Development Heterogeneous Gas Condensate Carbonate Reservoirs (Russian)",
    year = "2010",
    booktitle = "SPE Russian Oil and Gas Conference and Exhibition",
    url = "https://doi.org/10.2118/136399-ru",
    doi = "10.2118/136399-ru",
    openalex = "W4255996432"
}

Summary Many gas wells suffer a loss in productivity because of liquid accumulation in the near-wellbore region. Chemical stimulation may be used as a remedy by altering the wettability to nonliquid wetting. Successful treatments decrease liquid trapping, increase fluids mobility, and improve the well's deliverability. This paper presents the first effective chemical treatment to mitigate liquid blocking in carbonate gas reservoirs. Screening tests were developed to quickly and effectively identify suitable chemicals from a large pool of compounds. X-ray photoelectron spectroscopy (XPS) measurements and drop-imbibition tests with water and n-decane were found to be necessary but not sufficient indicators of the effectiveness of the chemicals and were used as screening tests. An integral part of the development of the treatment solution was the selection of a solvent mixture capable of delivering the fluorinated chemical to the rock surface. The treatment solution, mixture of chemical dissolved in solvent, must be stable in the presence of both brine and condensate so that it will not precipitate and will not reduce permeability of the rock. We acquired measured relative permeability values in Texas cream limestone (TCL) cores from high-pressure/high-temperature (HP/HT) coreflood experiments before and after treatment. Measurements were made using a pseudosteady-state method with a synthetic gas/condensate mixture. To enhance the durability of the treatment, a special amine primer is introduced. The gas relative permeability increased considerably (approximately 80%) after the treatment compared to that before treatment. This increase remained substantial, greater than 60% after injection of more than 1,000 pore volumes (PV) of gas/condensate mixture. We found an even greater increase in gas relative permeability during unsteady displacement of water by methane. The improvement remained after injecting 20 PV of brine and increasing the temperature in the treated core from 175 to 275°F. The chemical treatment developed in this research can be applied to increase well deliverability of both gas and condensate in the field, providing that it is properly designed by considering key parameters such as reservoir pressure and temperature, brine salinity, and initial water saturation.

@article{doi102118133591pa,
    author = "Ahmadi, Mohabbat and Sharma, Mukul and Pope, G. A. and Torres, D. E. and McCulley, C. A. and Linnemeyer, Harry",
    title = "Chemical Treatment To Mitigate Condensate and Water Blocking in Gas Wells in Carbonate Reservoirs",
    year = "2010",
    journal = "SPE Production \& Operations",
    abstract = "Summary Many gas wells suffer a loss in productivity because of liquid accumulation in the near-wellbore region. Chemical stimulation may be used as a remedy by altering the wettability to nonliquid wetting. Successful treatments decrease liquid trapping, increase fluids mobility, and improve the well's deliverability. This paper presents the first effective chemical treatment to mitigate liquid blocking in carbonate gas reservoirs. Screening tests were developed to quickly and effectively identify suitable chemicals from a large pool of compounds. X-ray photoelectron spectroscopy (XPS) measurements and drop-imbibition tests with water and n-decane were found to be necessary but not sufficient indicators of the effectiveness of the chemicals and were used as screening tests. An integral part of the development of the treatment solution was the selection of a solvent mixture capable of delivering the fluorinated chemical to the rock surface. The treatment solution, mixture of chemical dissolved in solvent, must be stable in the presence of both brine and condensate so that it will not precipitate and will not reduce permeability of the rock. We acquired measured relative permeability values in Texas cream limestone (TCL) cores from high-pressure/high-temperature (HP/HT) coreflood experiments before and after treatment. Measurements were made using a pseudosteady-state method with a synthetic gas/condensate mixture. To enhance the durability of the treatment, a special amine primer is introduced. The gas relative permeability increased considerably (approximately 80\%) after the treatment compared to that before treatment. This increase remained substantial, greater than 60\% after injection of more than 1,000 pore volumes (PV) of gas/condensate mixture. We found an even greater increase in gas relative permeability during unsteady displacement of water by methane. The improvement remained after injecting 20 PV of brine and increasing the temperature in the treated core from 175 to 275°F. The chemical treatment developed in this research can be applied to increase well deliverability of both gas and condensate in the field, providing that it is properly designed by considering key parameters such as reservoir pressure and temperature, brine salinity, and initial water saturation.",
    url = "https://doi.org/10.2118/133591-pa",
    doi = "10.2118/133591-pa",
    openalex = "W1992767771"
}

Abstract Khuff-B and Khuff-C are the two carbonate reservoirs in the SA-1 field discovered in 1980 with the drilling of exploratory well SA-A. Production from Khuff-B began in December 1983 when a second well was drilled and both were put onstream. The development of Khuff-B was minimal until two years back and only nine stand-alone wells were exclusively completed in this reservoir at that time. Three of these nine wells were actually tied-in to the gas plant. Few other wells were combined Khuff-B/Khuff-C producers. In the commingled producers, Khuff-B’s contribution is significant only in areas where Khuff-C is of relatively poorer quality. The dominant production is generally from Khuff-C reservoir. A large area is currently within Khuff-B reservoir boundaries with only few producing wells. The development of this vast area is required to meet the increased gas demand. Accurate evaluation of Khuff-B to ascertain reservoir potential and deliverability is of utmost importance. This paper evaluates the Khuff-B reservoir in the SA-1 field and proposes an optimal development plan to effectively deplete its reserves. Based on detailed analyses, the Khuff-B area has been divided into three regions, namely AREA-1, AREA-2 and AREA-3: The good, moderate, and challenging low quality, tight reservoir. The average production rates from those areas vary between 5 and 50 MMSCFD. The optimal drilling plan in the low quality, low productivity area consists of identifying the productive layer through a slanted pilot hole followed by drilling an extended lateral to attain maximum reservoir contact. A second lateral can also be drilled in special cases where more than one developed layer is encountered in the pilot hole. This development approach also allows placing the production lateral much above the gas-water contact to avoid any future water production or influx. The strategy is promising, has already been implemented in the field, and the results have confirmed a high production, water-free gas rate from the Khuff-B interval.

@article{doi102118136953ms,
    author = "Rahim, Zillur and Al-Anazi, Hamoud and Al-Kanaan, Adnan and Aziz, Azly Abdul",
    title = "Successful Exploitation of Khuff-B Low Permeability Gas Condensate Reservoir through Optimized Development Strategy",
    year = "2010",
    abstract = "Abstract Khuff-B and Khuff-C are the two carbonate reservoirs in the SA-1 field discovered in 1980 with the drilling of exploratory well SA-A. Production from Khuff-B began in December 1983 when a second well was drilled and both were put onstream. The development of Khuff-B was minimal until two years back and only nine stand-alone wells were exclusively completed in this reservoir at that time. Three of these nine wells were actually tied-in to the gas plant. Few other wells were combined Khuff-B/Khuff-C producers. In the commingled producers, Khuff-B’s contribution is significant only in areas where Khuff-C is of relatively poorer quality. The dominant production is generally from Khuff-C reservoir. A large area is currently within Khuff-B reservoir boundaries with only few producing wells. The development of this vast area is required to meet the increased gas demand. Accurate evaluation of Khuff-B to ascertain reservoir potential and deliverability is of utmost importance. This paper evaluates the Khuff-B reservoir in the SA-1 field and proposes an optimal development plan to effectively deplete its reserves. Based on detailed analyses, the Khuff-B area has been divided into three regions, namely AREA-1, AREA-2 and AREA-3: The good, moderate, and challenging low quality, tight reservoir. The average production rates from those areas vary between 5 and 50 MMSCFD. The optimal drilling plan in the low quality, low productivity area consists of identifying the productive layer through a slanted pilot hole followed by drilling an extended lateral to attain maximum reservoir contact. A second lateral can also be drilled in special cases where more than one developed layer is encountered in the pilot hole. This development approach also allows placing the production lateral much above the gas-water contact to avoid any future water production or influx. The strategy is promising, has already been implemented in the field, and the results have confirmed a high production, water-free gas rate from the Khuff-B interval.",
    url = "https://doi.org/10.2118/136953-ms",
    doi = "10.2118/136953-ms",
    openalex = "W1988074922"
}

Condensate-to-gas ratio (CGR) plays an important role in sales potential assessment of both gas and liquid, design of required surface processing facilities, reservoir characterization, and modeling of gas condensate reservoirs. Field work and laboratory determination of CGR is both time consuming and resource intensive. Developing a rapid and inexpensive technique to accurately estimate CGR is of great interest. An intelligent model is proposed in this paper based on a feed-forward artificial neural network (ANN) optimized by particle swarm optimization (PSO) technique. The PSO-ANN model was evaluated using experimental data and some PVT data available in the literature. The model predictions were compared with field data, experimental data, and the CGR obtained from an empirical correlation. A good agreement was observed between the predicted CGR values and the experimental and field data. Results of this study indicate that mixture molecular weight among input parameters selected for PSO-ANN has the greatest impact on CGR value, and the PSO-ANN is superior over conventional neural networks and empirical correlations. The developed model has the ability to predict the CGR with high precision in a wide range of thermodynamic conditions. The proposed model can serve as a reliable tool for quick and inexpensive but effective assessment of CGR in the absence of adequate experimental or field data.

@article{doi101021ef300443j,
    author = "Zendehboudi, Sohrab and Ahmadi, Mohammad Ali and James, Lesley and Chatzis, Ioannis",
    title = "Prediction of Condensate-to-Gas Ratio for Retrograde Gas Condensate Reservoirs Using Artificial Neural Network with Particle Swarm Optimization",
    year = "2012",
    journal = "Energy \& Fuels",
    abstract = "Condensate-to-gas ratio (CGR) plays an important role in sales potential assessment of both gas and liquid, design of required surface processing facilities, reservoir characterization, and modeling of gas condensate reservoirs. Field work and laboratory determination of CGR is both time consuming and resource intensive. Developing a rapid and inexpensive technique to accurately estimate CGR is of great interest. An intelligent model is proposed in this paper based on a feed-forward artificial neural network (ANN) optimized by particle swarm optimization (PSO) technique. The PSO-ANN model was evaluated using experimental data and some PVT data available in the literature. The model predictions were compared with field data, experimental data, and the CGR obtained from an empirical correlation. A good agreement was observed between the predicted CGR values and the experimental and field data. Results of this study indicate that mixture molecular weight among input parameters selected for PSO-ANN has the greatest impact on CGR value, and the PSO-ANN is superior over conventional neural networks and empirical correlations. The developed model has the ability to predict the CGR with high precision in a wide range of thermodynamic conditions. The proposed model can serve as a reliable tool for quick and inexpensive but effective assessment of CGR in the absence of adequate experimental or field data.",
    url = "https://doi.org/10.1021/ef300443j",
    doi = "10.1021/ef300443j",
    openalex = "W2331880329",
    references = "doi10211862930ms"
}

Abstract Heterogeneity and tightness of carbonate retrograde reservoirs are the main challenges to maintain gas well productivities. The degree of heterogeneity changes over the field and within well drainage areas where permeability decreases from few millidarcies to less than 0.2 md. Thorough studies have been conducted to exploit these tight reservoirs and not only focused on well performance, but have extended to assure enhancing and sustaining gas productivity through practical applications of technologies. The main objective of this paper is to assess the performance of Multi-Stage Fracturing (MSF) in horizontal wells that were drilled conventionally and did not meet gas deliverability expectation. This paper gives a detailed analysis of well performances, exploitation approaches, and successful implementation and optimal cases to utilize new completion technologies such as horizontal multi stage fracturing to revive low producing gas wells due to reservoir tightness. Placing the horizontal wellbore reference to the stress directions plays a major role in the success and effectiveness of fracturing in enhancing and sustaining productivity. Several wells have been drilled in tight reservoirs, but could not achieve or sustain the target gas rate. Recently, two wells were geometrically sidetracked targeting the development intervals based on logs of the original hole and completed with MSF toward the minimum stress direction. Open hole logs showed a low porosity development similar of the vertical holes. However, after conducting multiple stages fracturing, both wells produced a sustainable rate of more than 25 MMSCFD that prompted to connecting them to gas plants. Placing these sidetracks in the minimum stress direction helped to create transverse fractures that connect to sweet spots and sustain gas production. This paper provides thorough guidelines for selecting optimal candidates for MSF based on reservoir heterogeneity, proper design and execution of fracturing. It also addresses various components that contributed to the success of both wells, such as reservoir development, workover preplanning, geo-mechanics studies, drilling operations and real-time support, completion operations optimization and best-practices, and performance evaluation of other producers in the field. The paper also includes essential recommendations for development of tight gas reservoirs.

@article{doi102118161664ms,
    author = "Al-Anazi, Hamoud and Abdulbaqi, Dana M. and Habbtar, Ali and Al-Kanaan, Adnan",
    title = "Successful Implementation of Horizontal Multi-Stage Fracturing Enhanced Gas Production in Heterogeneous \& Tight Gas-Condensate Reservoirs: Case Studies",
    year = "2012",
    journal = "Abu Dhabi International Petroleum Conference and Exhibition",
    abstract = "Abstract Heterogeneity and tightness of carbonate retrograde reservoirs are the main challenges to maintain gas well productivities. The degree of heterogeneity changes over the field and within well drainage areas where permeability decreases from few millidarcies to less than 0.2 md. Thorough studies have been conducted to exploit these tight reservoirs and not only focused on well performance, but have extended to assure enhancing and sustaining gas productivity through practical applications of technologies. The main objective of this paper is to assess the performance of Multi-Stage Fracturing (MSF) in horizontal wells that were drilled conventionally and did not meet gas deliverability expectation. This paper gives a detailed analysis of well performances, exploitation approaches, and successful implementation and optimal cases to utilize new completion technologies such as horizontal multi stage fracturing to revive low producing gas wells due to reservoir tightness. Placing the horizontal wellbore reference to the stress directions plays a major role in the success and effectiveness of fracturing in enhancing and sustaining productivity. Several wells have been drilled in tight reservoirs, but could not achieve or sustain the target gas rate. Recently, two wells were geometrically sidetracked targeting the development intervals based on logs of the original hole and completed with MSF toward the minimum stress direction. Open hole logs showed a low porosity development similar of the vertical holes. However, after conducting multiple stages fracturing, both wells produced a sustainable rate of more than 25 MMSCFD that prompted to connecting them to gas plants. Placing these sidetracks in the minimum stress direction helped to create transverse fractures that connect to sweet spots and sustain gas production. This paper provides thorough guidelines for selecting optimal candidates for MSF based on reservoir heterogeneity, proper design and execution of fracturing. It also addresses various components that contributed to the success of both wells, such as reservoir development, workover preplanning, geo-mechanics studies, drilling operations and real-time support, completion operations optimization and best-practices, and performance evaluation of other producers in the field. The paper also includes essential recommendations for development of tight gas reservoirs.",
    url = "https://doi.org/10.2118/161664-ms",
    doi = "10.2118/161664-ms",
    openalex = "W2008011200",
    references = "alanazi2010effective, doi10130606160909012, doi102118102262ms, doi102118107493ms, doi102118133591pa, doi102118136953ms, doi102118160848ms, doi10211884258ms, doi10211893210ms, doi10211894256ms, doi102523107493ms"
}

Abstract Retrograde gas condensate systems are complex systems as a result of the unique compositional changes that when the reservoir pressure is decreased. Correct selection of Equation of State (EOS) is necessary for proper fluid characterization so that the PVT behavior in the simulation model is a good representation of the reservoir fluid. High quality and accurate PVT data can reduce uncertainty in reservoir fluid properties and set the stage for reservoir engineering modeling whilst improving the technical work on which investment decisions are made. In order to obtain reliable PVT data for effective reservoir modeling, the following steps are essential: Acquisition of sufficient volumes of representative reservoir fluid samples. Proper examination and supervision of all field and laboratory experiments to ensure accuracy, consistency and validity of the resulting PVT analysis results. Results from the PVT experiments are imported into PVT software for validation in order to ascertain a good match between the simulated and experimental data. This process generates the Equation of State model required for material balance and other simulation studies for gas condensate reservoirs. The mass balance test is one of the methods that can be used to validate laboratory PVT data. It is a rigorous test for the evaluation of compositional consistency between feed composition, separator vapor and liquid compositions. Other laboratory PVT data validation means include Mass balance plot, Hoffman plot CVD/CCE comparison plots and Campbell diagrams. These plots serve as data quality assessment methods prior to their use for EOS characterization. PVT validation checks helps to confirm the true content of the fluid as either a rich or lean gas condensate and also confirm the Gas oil ratio of the system. Inaccurate PVT data can give misleading information that could cause a wrong evaluation of hydrocarbon in place. However, when these methods are properly applied it could lead to huge savings for the company as accurate results are obtained from reservoir simulation models which could aid optimization efforts and achieve incremental recovery.

@article{doi102118172359ms,
    author = "Akpabio, Julius U. and Udofia, Emmanuel and Ogbu, Michael",
    title = "PVT Fluid Characterization and Consistency Check for Retrograde Condensate Reservoir Modeling",
    year = "2014",
    journal = "SPE Nigeria Annual International Conference and Exhibition",
    abstract = "Abstract Retrograde gas condensate systems are complex systems as a result of the unique compositional changes that when the reservoir pressure is decreased. Correct selection of Equation of State (EOS) is necessary for proper fluid characterization so that the PVT behavior in the simulation model is a good representation of the reservoir fluid. High quality and accurate PVT data can reduce uncertainty in reservoir fluid properties and set the stage for reservoir engineering modeling whilst improving the technical work on which investment decisions are made. In order to obtain reliable PVT data for effective reservoir modeling, the following steps are essential: Acquisition of sufficient volumes of representative reservoir fluid samples. Proper examination and supervision of all field and laboratory experiments to ensure accuracy, consistency and validity of the resulting PVT analysis results. Results from the PVT experiments are imported into PVT software for validation in order to ascertain a good match between the simulated and experimental data. This process generates the Equation of State model required for material balance and other simulation studies for gas condensate reservoirs. The mass balance test is one of the methods that can be used to validate laboratory PVT data. It is a rigorous test for the evaluation of compositional consistency between feed composition, separator vapor and liquid compositions. Other laboratory PVT data validation means include Mass balance plot, Hoffman plot CVD/CCE comparison plots and Campbell diagrams. These plots serve as data quality assessment methods prior to their use for EOS characterization. PVT validation checks helps to confirm the true content of the fluid as either a rich or lean gas condensate and also confirm the Gas oil ratio of the system. Inaccurate PVT data can give misleading information that could cause a wrong evaluation of hydrocarbon in place. However, when these methods are properly applied it could lead to huge savings for the company as accurate results are obtained from reservoir simulation models which could aid optimization efforts and achieve incremental recovery.",
    url = "https://doi.org/10.2118/172359-ms",
    doi = "10.2118/172359-ms",
    openalex = "W2082418539",
    references = "doi10211868668ms"
}

Pore-scale coupled flow of gas and condensate is believed to be the main mechanism for condensate production in low interfacial tension (IFT) gas condensate reservoirs. While coupling enhances condensate flow due to transport of condensate lenses by the gas, it dramatically reduces gas permeability by introducing capillary resistance against gas flow. In this study, a dynamic wetting approach is used to investigate the effect of viscous resistance, IFT and disjoining pressure on pore-scale coupling of gas and condensate. Disjoining pressure arises from van der Waals interactions between gas and solid through thin liquid films, e.g., condensate films on pore walls. Low values of IFT and small pore diameters, as involved in many gas condensate reservoirs, give rise to importance of disjoining pressure. Calculations show that disjoining pressure postpones gas condensate coupling to higher condensate flow fractions-from about 0.08 for vanishing disjoining effect to more than 0.16 for strong disjoining effect. Results also suggest that strong disjoining effect will result in higher gas relative permeability after coupling. Finally, the positive rate effect on gas permeability is only observed when disjoining effects are weak.

@article{mohammadikhanaposhtani2014disjoining,
    author = "Mohammadi-Khanaposhtani, Mohammad and Bahramian, Alireza and Pourafshary, Peyman",
    title = "Disjoining Pressure and Gas Condensate Coupling in Gas Condensate Reservoirs",
    year = "2014",
    journal = "Journal of Energy Resources Technology",
    abstract = "Pore-scale coupled flow of gas and condensate is believed to be the main mechanism for condensate production in low interfacial tension (IFT) gas condensate reservoirs. While coupling enhances condensate flow due to transport of condensate lenses by the gas, it dramatically reduces gas permeability by introducing capillary resistance against gas flow. In this study, a dynamic wetting approach is used to investigate the effect of viscous resistance, IFT and disjoining pressure on pore-scale coupling of gas and condensate. Disjoining pressure arises from van der Waals interactions between gas and solid through thin liquid films, e.g., condensate films on pore walls. Low values of IFT and small pore diameters, as involved in many gas condensate reservoirs, give rise to importance of disjoining pressure. Calculations show that disjoining pressure postpones gas condensate coupling to higher condensate flow fractions-from about 0.08 for vanishing disjoining effect to more than 0.16 for strong disjoining effect. Results also suggest that strong disjoining effect will result in higher gas relative permeability after coupling. Finally, the positive rate effect on gas permeability is only observed when disjoining effects are weak.",
    url = "https://doi.org/10.1115/1.4027851",
    doi = "10.1115/1.4027851",
    number = "4",
    openalex = "W2090322008",
    volume = "136",
    references = "doi101016002197979090248m, doi101016b9780080363646500314, doi101016s030193220200037x, doi101017s0022112061000160, doi101017s0022112083002451, doi101017s0022112090002774, doi101023a1006645515791, doi1010631857530, doi10211831065pa, doi10211856014pa"
}

@inproceedings{abdullatif2015optimising,
    author = "Abdul-Latif, Benson Lamidi and Kwesi, Dziwornu Christian and Ernest, Adaze and Fahd, King",
    title = "Optimising Spacing of Horizontal Wells in Gas and Gas-Condensate Reservoirs (Russian)",
    year = "2015",
    booktitle = "SPE Russian Petroleum Technology Conference",
    url = "https://doi.org/10.2118/176586-ru",
    doi = "10.2118/176586-ru",
    openalex = "W4239982112",
    references = "doi10211854627ms"
}

Abstract Horizontal Open Hole multistage fracturing (OHMSF) completion is the preferred completion to develop the tight and heterogeneous carbonate reservoir. Production data analyses and pressure transient tests are systematically and routinely conducted on these wells to determine the well productivity indices and evaluate key reservoir and fracture parameters. The OHMSF completions have been implemented since 2009 and have showed remarkable results compared to other completions and stimulation strategies such as vertical wells with single or multistage fracturing and open hole multilateral wells with maximum reservoir contacts. This paper presents the modeling and interpretation of production and actual pressure transient responses of horizontal OHMSF wells that were drilled in both the minimum horizontal stress (σmin) direction and the maximum horizontal stress (σmax) directions to assess the production and fracture behavior. Creating transverse fractures has shown better productivity compared to the longitudinal fractures in terms of production performance, which is corroborated in the paper through pressure transient analyses (PTA) and results from field data. The paper evaluates the impact of the fracture parameters such as fracture half length, conductivity, orientation, and number of fractures on production and pressure behavior. Well testing and production analyses tools are very powerful techniques to assess and compare different types of flow regimes for horizontal OHMSF wells drilled in different azimuth directions. This paper discusses and explains the different derivative shapes captured during well tests and compares these to the simulated and theoretical models. Also, the transmissibility values obtained from the mini falloff (MFO) test following during the fracture injectivity operations are compared with the flow capacity values calculated from the PTA. Challenges impacting pressure transient responses such as high wellbore storage are addressed in the paper and proper planning and use of best practices in the PTA to obtain accurate results are discussed and presented.

@article{doi102118172697ms,
    author = "Dawood, Mahdi Al and Aziz, Azly Abdul and Rahim, Zillur and Al-Omair, Ahmed and Rahman, N. M. Anisur",
    title = "Well Testing Analysis of Horizontal Open Hole Multistage Fracturing Wells in Tight Gas Condensate Reservoirs in Saudi Arabia to Characterize Production Performance and Fracture Behavior: Case Studies",
    year = "2015",
    abstract = "Abstract Horizontal Open Hole multistage fracturing (OHMSF) completion is the preferred completion to develop the tight and heterogeneous carbonate reservoir. Production data analyses and pressure transient tests are systematically and routinely conducted on these wells to determine the well productivity indices and evaluate key reservoir and fracture parameters. The OHMSF completions have been implemented since 2009 and have showed remarkable results compared to other completions and stimulation strategies such as vertical wells with single or multistage fracturing and open hole multilateral wells with maximum reservoir contacts. This paper presents the modeling and interpretation of production and actual pressure transient responses of horizontal OHMSF wells that were drilled in both the minimum horizontal stress (σmin) direction and the maximum horizontal stress (σmax) directions to assess the production and fracture behavior. Creating transverse fractures has shown better productivity compared to the longitudinal fractures in terms of production performance, which is corroborated in the paper through pressure transient analyses (PTA) and results from field data. The paper evaluates the impact of the fracture parameters such as fracture half length, conductivity, orientation, and number of fractures on production and pressure behavior. Well testing and production analyses tools are very powerful techniques to assess and compare different types of flow regimes for horizontal OHMSF wells drilled in different azimuth directions. This paper discusses and explains the different derivative shapes captured during well tests and compares these to the simulated and theoretical models. Also, the transmissibility values obtained from the mini falloff (MFO) test following during the fracture injectivity operations are compared with the flow capacity values calculated from the PTA. Challenges impacting pressure transient responses such as high wellbore storage are addressed in the paper and proper planning and use of best practices in the PTA to obtain accurate results are discussed and presented.",
    url = "https://doi.org/10.2118/172697-ms",
    doi = "10.2118/172697-ms",
    openalex = "W2074526776",
    references = "doi102118161664ms"
}

@inproceedings{esmaeili2015enhancing,
    author = "Esmaeili, A.",
    title = "Enhancing condensate recovery from gas condensate reservoirs through gas injection",
    year = "2015",
    booktitle = "2015 International Field Exploration and Development Conference (IFEDC 2015)",
    url = "https://doi.org/10.1049/cp.2015.0587",
    doi = "10.1049/cp.2015.0587",
    openalex = "W2318675139",
    pages = "6 .-6 ."
}

@inproceedings{abdullatif2016modeling,
    author = "Abdul-Latif, Benson Lamidi and Dziwornu, Christian Kwesi and Phu Ha, Nguyen and Riverson, Oppong",
    title = "Modeling and Optimization of Waterflooding in Gas Condensate Reservoirs (Russian)",
    year = "2016",
    booktitle = "SPE Russian Petroleum Technology Conference and Exhibition",
    url = "https://doi.org/10.2118/182058-ru",
    doi = "10.2118/182058-ru",
    openalex = "W2528850395",
    references = "doi10211815875pa, doi10211822636pa, doi10211825070ms"
}

Abstract Naturally fractured-vuggy carbonate gas condensate reservoirs in China have some distinctive characteristics: deep buried depth, multi-scale fractures, vugs and caves developed, poor reservoir connectivity, high production decline rate and low estimated ultimate recovery. So how to properly develop this kind of reservoirs is a major challenge. This paper presents the study on development strategy optimization for fractured-vuggy carbonate gas condensate reservoirs in detail. Based on the geological survey of palaeokarst outcrops and seismic interpretation, representative reservoir type patterns of fractured-vuggy carbonate gas condensate reservoirs can be determined. And combined geological study and dynamic characterization, different reservoir patterns can be identified and characterized. After that, simulation models of different reservoir patterns are built, in order to study the detailed development strategy on primary depletion and water flooding huff-and-puff. And optimal development strategies are applied into the TZ fractured-vuggy carbonate gas condensate reservoir in China. Take TZ carbonate gas condensate reservoir in China for example. The mid-depth of TZ reservoir is 5500m with annual production decline rate higher than 25%. Through geological and dynamic characterization, six representative reservoir type patterns are identified and characterized. And more than half drilled patterns in TZ are isolated and developed in very limited volume, which only need one well to develop each pattern. Then reservoir simulation models of the six patterns are built to investigate the optimized development strategies. The results show vertical wells are optimum for four patterns and horizontal wells are optimum for two patterns. For isolated karst caves pattern, there are still lots of remaining condensate oil after primary depletion, so water injection huff-and-puff are studied for this pattern. The results are applied to TZ reservoir. This paper offers a case study on development strategy optimization of different reservoir patterns for fractured-caved gas condensate carbonate reservoirs, and the understandings are successfully applied to TZ carbonate gas condensate reservoir. It also provides a methodology and an improved oil recovery reference case for engineers and geologists to develop other similar reservoirs.

@article{doi102118182054ms,
    author = "Li, Yong and Li, Baozhu and Xia, Jing and Zhang, Xuelei and Deng, Xingliang and Zhicheng, She and Liu, Zhiliang",
    title = "Development Strategy Optimization and Application for Fractured-Vuggy Carbonate Gas Condensate Reservoirs",
    year = "2016",
    journal = "SPE Russian Petroleum Technology Conference and Exhibition",
    abstract = "Abstract Naturally fractured-vuggy carbonate gas condensate reservoirs in China have some distinctive characteristics: deep buried depth, multi-scale fractures, vugs and caves developed, poor reservoir connectivity, high production decline rate and low estimated ultimate recovery. So how to properly develop this kind of reservoirs is a major challenge. This paper presents the study on development strategy optimization for fractured-vuggy carbonate gas condensate reservoirs in detail. Based on the geological survey of palaeokarst outcrops and seismic interpretation, representative reservoir type patterns of fractured-vuggy carbonate gas condensate reservoirs can be determined. And combined geological study and dynamic characterization, different reservoir patterns can be identified and characterized. After that, simulation models of different reservoir patterns are built, in order to study the detailed development strategy on primary depletion and water flooding huff-and-puff. And optimal development strategies are applied into the TZ fractured-vuggy carbonate gas condensate reservoir in China. Take TZ carbonate gas condensate reservoir in China for example. The mid-depth of TZ reservoir is 5500m with annual production decline rate higher than 25\%. Through geological and dynamic characterization, six representative reservoir type patterns are identified and characterized. And more than half drilled patterns in TZ are isolated and developed in very limited volume, which only need one well to develop each pattern. Then reservoir simulation models of the six patterns are built to investigate the optimized development strategies. The results show vertical wells are optimum for four patterns and horizontal wells are optimum for two patterns. For isolated karst caves pattern, there are still lots of remaining condensate oil after primary depletion, so water injection huff-and-puff are studied for this pattern. The results are applied to TZ reservoir. This paper offers a case study on development strategy optimization of different reservoir patterns for fractured-caved gas condensate carbonate reservoirs, and the understandings are successfully applied to TZ carbonate gas condensate reservoir. It also provides a methodology and an improved oil recovery reference case for engineers and geologists to develop other similar reservoirs.",
    url = "https://doi.org/10.2118/182054-ms",
    doi = "10.2118/182054-ms",
    openalex = "W2528034899",
    references = "doi102118161664ms"
}

Abstract Most secondary recovery projects are usually not commenced in a gas or oil reservoir until dictated by the reservoir depleting pressure or by the gas-oil-ratio (GOR) or declining productivity index of the reservoir. During this process it is required to effectively disperse an injection pattern to prevent the oil banks from fleeing away from the production wells. Gas condensate reservoirs usually are produced using primary depletion techniques, which averagely is inefficient for producing the valuable liquid components in the form of condensed liquid. Though the most common approach used to improve liquid productivity in gas condensate reservoirs is the method of recycling produced gas through the reservoir, this technique is economically not friendly due to the fact that larger discounts are usually applied on gas sale values for delayed selling. This paper presents a technique of improving liquid productivity in gas condensate wells by keeping the reservoir pressure above the dew point pressure. Water injection in a gas condensate simulation model with equal well spacing patterns in five- and seven-spot developmental patterns is used. Simulation results showed that continued water injection resulted in optimum hydrocarbon recovery of 15% and 27% respectively of initial mass higher than primary depletion for gas condensate reservoir with condensate gas ratio of 190 STB/MMscf and 300 STB/MMscf. These results vividly demonstrate that waterflooding of gas condensate wells can perhaps be used as an effective improved oil recovery technique.

@article{doi102118182058ms,
    author = "Abdul-Latif, Benson Lamidi and Dziwornu, Christian Kwesi and Ha, Nguyen Phu and Riverson, Oppong",
    title = "Modeling and Optimization of Waterflooding in Gas Condensate Reservoirs",
    year = "2016",
    journal = "SPE Russian Petroleum Technology Conference and Exhibition",
    abstract = "Abstract Most secondary recovery projects are usually not commenced in a gas or oil reservoir until dictated by the reservoir depleting pressure or by the gas-oil-ratio (GOR) or declining productivity index of the reservoir. During this process it is required to effectively disperse an injection pattern to prevent the oil banks from fleeing away from the production wells. Gas condensate reservoirs usually are produced using primary depletion techniques, which averagely is inefficient for producing the valuable liquid components in the form of condensed liquid. Though the most common approach used to improve liquid productivity in gas condensate reservoirs is the method of recycling produced gas through the reservoir, this technique is economically not friendly due to the fact that larger discounts are usually applied on gas sale values for delayed selling. This paper presents a technique of improving liquid productivity in gas condensate wells by keeping the reservoir pressure above the dew point pressure. Water injection in a gas condensate simulation model with equal well spacing patterns in five- and seven-spot developmental patterns is used. Simulation results showed that continued water injection resulted in optimum hydrocarbon recovery of 15\% and 27\% respectively of initial mass higher than primary depletion for gas condensate reservoir with condensate gas ratio of 190 STB/MMscf and 300 STB/MMscf. These results vividly demonstrate that waterflooding of gas condensate wells can perhaps be used as an effective improved oil recovery technique.",
    url = "https://doi.org/10.2118/182058-ms",
    doi = "10.2118/182058-ms",
    openalex = "W2528264400",
    references = "doi10211825070ms"
}

Abstract Condensate banking results from a combination of factors including fluid properties, formation flow characteristics, and pressures in the formation and wellbore. The production performance may suffer provided these factors are not understood at the beginning of field development. Determining the fluid properties can be vital in any reservoir, hence it plays a crucial role in gas-condensate reservoirs where condensate/gas ratio is significant in estimates for the sales potential of gas and liquid. Once reservoir fluids enter a wellbore both temperature and pressure conditions may change, where condensate liquid can be produced into the wellbore but liquid can also drop out within the wellbore. If the liquid falls back down the wellbore, the liquid percentage will increase and may eventually restrict the production. Thus, it is very important for robust reservoir management that each and every control and uncertainty parameter is understood not only in theory but also in practice with solid examples as done in this study. A robust commercial optimization and uncertainty software is coupled with a full-physics commercial simulator that models the phenomenon so as to investigate the significance of major parameters on performance of gas-condensate reservoirs under recycling. Control and uncertainty variables have been investigated via several simulation runs in specified ranges to represent real reservoir and performance conditions rather than theoretical assumptions. This study aims to prepare an insight into the mechanism of gas injection process in reducing gas-well productivity losses due to condensate blockage in the near wellbore region. The main goal of this work is to investigate gas recycling into the reservoir to enhance condensate recovery. The results show the influence of each control or uncertainty variable, leading to a better understanding of management of gas-condensate reservoirs under gas recycling. Impact of fractures is significant and the tornado diagrams illustrate the relative significance of each factor. The results and sensitivities are compared and discussed in light of a comprehensive literature review of recycling gas-condensate reservoirs with different process optimization methods. The significance of all major parameters are outlined using tornado charts to serve as a practical example for optimization of relevant future applications.

@article{doi102118182854ms,
    author = "Temizel, Cenk and Kirmaci, Harun and Tiwari, Aditya and Balaji, Karthik and Suhag, Anuj and Ranjith, Rahul and Wijaya, Zein and Zhu, Ying and Yegin, Cengiz and Gazar, Ashraf Lofty El",
    title = "An Investigation of Gas Recycling in Fractured Gas-Condensate Reservoirs",
    year = "2016",
    abstract = "Abstract Condensate banking results from a combination of factors including fluid properties, formation flow characteristics, and pressures in the formation and wellbore. The production performance may suffer provided these factors are not understood at the beginning of field development. Determining the fluid properties can be vital in any reservoir, hence it plays a crucial role in gas-condensate reservoirs where condensate/gas ratio is significant in estimates for the sales potential of gas and liquid. Once reservoir fluids enter a wellbore both temperature and pressure conditions may change, where condensate liquid can be produced into the wellbore but liquid can also drop out within the wellbore. If the liquid falls back down the wellbore, the liquid percentage will increase and may eventually restrict the production. Thus, it is very important for robust reservoir management that each and every control and uncertainty parameter is understood not only in theory but also in practice with solid examples as done in this study. A robust commercial optimization and uncertainty software is coupled with a full-physics commercial simulator that models the phenomenon so as to investigate the significance of major parameters on performance of gas-condensate reservoirs under recycling. Control and uncertainty variables have been investigated via several simulation runs in specified ranges to represent real reservoir and performance conditions rather than theoretical assumptions. This study aims to prepare an insight into the mechanism of gas injection process in reducing gas-well productivity losses due to condensate blockage in the near wellbore region. The main goal of this work is to investigate gas recycling into the reservoir to enhance condensate recovery. The results show the influence of each control or uncertainty variable, leading to a better understanding of management of gas-condensate reservoirs under gas recycling. Impact of fractures is significant and the tornado diagrams illustrate the relative significance of each factor. The results and sensitivities are compared and discussed in light of a comprehensive literature review of recycling gas-condensate reservoirs with different process optimization methods. The significance of all major parameters are outlined using tornado charts to serve as a practical example for optimization of relevant future applications.",
    url = "https://doi.org/10.2118/182854-ms",
    doi = "10.2118/182854-ms",
    openalex = "W2555269578",
    references = "thomas1995towards"
}

Summary This paper examines the potential of huff ’n’ puff gas-injection method to recover condensate in shale gas–condensate reservoirs by conducting experiments on a shale core. Numerical models were developed to verify experiment results. Our laboratory study shows that condensate recovery was increased to 25% by applying huff ’n’ puff gas injection on a shale core. Also, we compared the efficiency of huff ’n’ puff gas injection with that of gasflooding. At the end of same flooding with time that is the same as the time for five huff ’n’ puff cycles, the condensate recovery is 19%. From the experimental results, we found that huff ’n’ puff was more effective than gasflooding. During the experiment, condensate accumulated near the production-end region. In the huff ’n’ puff process, because the location for injection in the core was the same as that for production, the pressure in the condensate region built up faster than pressure in the flooding experiment. Also, because of the ultralow permeability, the pressure propagation was much slower in the shale core than in a conventional reservoir core, and the efficiency of gasflooding is much lower than that of the huff ’n’ puff. This study indicates that huff ’n’ puff has the potential to effectively enhance condensate recovery in shale gas–condensate reservoirs.

@article{doi102118183645pa,
    author = "Meng, Xingbang and Sheng, James J. and Yu, Yang",
    title = "Experimental and Numerical Study of Enhanced Condensate Recovery by Gas Injection in Shale Gas–Condensate Reservoirs",
    year = "2016",
    journal = "SPE Reservoir Evaluation \& Engineering",
    abstract = "Summary This paper examines the potential of huff ’n’ puff gas-injection method to recover condensate in shale gas–condensate reservoirs by conducting experiments on a shale core. Numerical models were developed to verify experiment results. Our laboratory study shows that condensate recovery was increased to 25\% by applying huff ’n’ puff gas injection on a shale core. Also, we compared the efficiency of huff ’n’ puff gas injection with that of gasflooding. At the end of same flooding with time that is the same as the time for five huff ’n’ puff cycles, the condensate recovery is 19\%. From the experimental results, we found that huff ’n’ puff was more effective than gasflooding. During the experiment, condensate accumulated near the production-end region. In the huff ’n’ puff process, because the location for injection in the core was the same as that for production, the pressure in the condensate region built up faster than pressure in the flooding experiment. Also, because of the ultralow permeability, the pressure propagation was much slower in the shale core than in a conventional reservoir core, and the efficiency of gasflooding is much lower than that of the huff ’n’ puff. This study indicates that huff ’n’ puff has the potential to effectively enhance condensate recovery in shale gas–condensate reservoirs.",
    url = "https://doi.org/10.2118/183645-pa",
    doi = "10.2118/183645-pa",
    openalex = "W2512637518",
    references = "doi10211862930ms"
}

To achieve maximum economic revenues in gas-condensate reservoirs, an optimisation tool is employed to estimate the optimum well placement. Uncertainty analysis in gas-condensate reservoirs is a prerequisite requirement before the developing phase of the hydrocarbon reservoir. Contrary to most conventional reservoir development, well spacing optimisation in gas-condensate fields has received less attention due to a general assumption that optimisation techniques and computational methodologies applied to oil fields development can be applied to gas-condensate fields. Uncertainty analyses were performed using fourth-order factorial design on a domain of gas-condensate field's data to identify key factors affecting the production of condensates from heterogeneous and ultra-low permeability reservoirs. Well placement objective functions for gas-condensate reservoirs were optimised as functions of cumulative condensate production using genetic algorithms. With compositional modeling, exhaustive search mechanisms were employed to validate the results of our proposed optimisation tool. Results from the proposed optimisation tool was more economically feasible compared to that of the exhaustive search mechanisms and thus, could be employed as a much simpler, less exhaustive and economically feasible optimisation tool for well placement projects in gas-condensate reservoirs. In using genetic algorithms we concluded that most optimisation tools do not have both reliability and efficiency. Genetic algorithms optimisation tool was observed to be the most reliable method for gas condensate reservoirs though excessive number of simulation runs for large fields makes their application expensive. A more strategic approach was used to formulate objective functions whilst incorporating the effect of condensate banking in gas-condensate reservoirs.

@inproceedings{abdullatif2017well,
    author = "Abdul-Latif, Benson Lamidi and Edem, Tsikplornu Daniel and Hikmahtiar, Syouma",
    title = "Well Placement Optimisation in Gas-Condensate Reservoirs Using Genetic Algorithms",
    year = "2017",
    booktitle = "SPE/IATMI Asia Pacific Oil \& Gas Conference and Exhibition",
    abstract = "To achieve maximum economic revenues in gas-condensate reservoirs, an optimisation tool is employed to estimate the optimum well placement. Uncertainty analysis in gas-condensate reservoirs is a prerequisite requirement before the developing phase of the hydrocarbon reservoir. Contrary to most conventional reservoir development, well spacing optimisation in gas-condensate fields has received less attention due to a general assumption that optimisation techniques and computational methodologies applied to oil fields development can be applied to gas-condensate fields. Uncertainty analyses were performed using fourth-order factorial design on a domain of gas-condensate field's data to identify key factors affecting the production of condensates from heterogeneous and ultra-low permeability reservoirs. Well placement objective functions for gas-condensate reservoirs were optimised as functions of cumulative condensate production using genetic algorithms. With compositional modeling, exhaustive search mechanisms were employed to validate the results of our proposed optimisation tool. Results from the proposed optimisation tool was more economically feasible compared to that of the exhaustive search mechanisms and thus, could be employed as a much simpler, less exhaustive and economically feasible optimisation tool for well placement projects in gas-condensate reservoirs. In using genetic algorithms we concluded that most optimisation tools do not have both reliability and efficiency. Genetic algorithms optimisation tool was observed to be the most reliable method for gas condensate reservoirs though excessive number of simulation runs for large fields makes their application expensive. A more strategic approach was used to formulate objective functions whilst incorporating the effect of condensate banking in gas-condensate reservoirs.",
    url = "https://doi.org/10.2118/186251-ms",
    doi = "10.2118/186251-ms",
    openalex = "W2766319640",
    references = "doi1010079781447107217, doi101007s1059600690319, doi10211838895ms, doi10211869439ms, doi10211871625ms, doi10252338895ms, doi10252369439ms, openalexw2186773233"
}

@misc{crossref2017gascondensate,
    title = "Gas‐Condensate Reservoirs",
    year = "2017",
    booktitle = "Rules of Thumb for Petroleum Engineers",
    url = "https://doi.org/10.1002/9781119403647.ch165",
    doi = "10.1002/9781119403647.ch165",
    openalex = "W2593849555",
    pages = "365-366"
}

Gas-condensate productivity is highly dependent on the thermodynamic behavior of the fluids-in-place. The condensation attendant with the depletion of gas-condensate reservoirs leads to a deficiency in the flow of fluids moving toward the production channels. The impairment is a result of condensate accumulation near the production channels in an immobility state until reaching a critical saturation point. Considering the flow phenomenon of gas-condensate reservoirs, tight formations can be inevitably complex hosting environments in which to achieve economical production. This work is aimed to assess the productivity gas-condensate reservoirs in a naturally fractured setting against the effect of capillary pressure and relative permeability constraints. The severity of condensate coating and magnitude of impairment was evaluated in a system with a permeability of 0.001 mD using an in-house compositional simulator. Several composition combinations were considered to portray mixtures ascending in complexity from light to heavy. The examination showed that thicker walls of condensate and greater impairment are attained with mixture containing higher nonvolatile concentrations. In addition, the influence of different capillary curves was insignificant to the overall behavior of fluids-in-place and movement within the pores medium. A greater impact on the transport of fluids was owed to relative permeability curves, which showed dependency on the extent of condensate content. Activating diffusion was found to diminish flow constraints due to the capturing of additional extractions that were not accounted for under Darcy's law alone.

@article{doi10111514035905,
    author = "Ghamdi, Bander N. Al and Ayala, Luis F.",
    title = "Evaluation of Transport Properties Effect on the Performance of Gas-Condensate Reservoirs Using Compositional Simulation",
    year = "2017",
    journal = "Journal of Energy Resources Technology",
    abstract = "Gas-condensate productivity is highly dependent on the thermodynamic behavior of the fluids-in-place. The condensation attendant with the depletion of gas-condensate reservoirs leads to a deficiency in the flow of fluids moving toward the production channels. The impairment is a result of condensate accumulation near the production channels in an immobility state until reaching a critical saturation point. Considering the flow phenomenon of gas-condensate reservoirs, tight formations can be inevitably complex hosting environments in which to achieve economical production. This work is aimed to assess the productivity gas-condensate reservoirs in a naturally fractured setting against the effect of capillary pressure and relative permeability constraints. The severity of condensate coating and magnitude of impairment was evaluated in a system with a permeability of 0.001 mD using an in-house compositional simulator. Several composition combinations were considered to portray mixtures ascending in complexity from light to heavy. The examination showed that thicker walls of condensate and greater impairment are attained with mixture containing higher nonvolatile concentrations. In addition, the influence of different capillary curves was insignificant to the overall behavior of fluids-in-place and movement within the pores medium. A greater impact on the transport of fluids was owed to relative permeability curves, which showed dependency on the extent of condensate content. Activating diffusion was found to diminish flow constraints due to the capturing of additional extractions that were not accounted for under Darcy's law alone.",
    url = "https://doi.org/10.1115/1.4035905",
    doi = "10.1115/1.4035905",
    openalex = "W2583447833",
    references = "mohammadikhanaposhtani2014disjoining"
}

Critical condensate saturation, Scc, is a key parameter for the evaluation of well deliverability in gas condensate reservoirs. We propose a new method to determine Scc by performing three-phase flow simulations with three-dimensional (3D) pore network model. First, we establish a network model with random fractal methodology. Second, based on the condensation model in the literature of Li and Firoozabadi, we develop a modified condensation model to describe the condensation phenomenon of gas with connate water in the porous medium. The numerical model is verified by experimental measurements in the literature. Then, we investigate the influence of different factors on the critical condensate saturation, including micro pore structure (pore radius and fractal dimension), condensate gas/oil interfacial tension (IFT), and flow rate at different irreducible water saturation, Swi. The simulation results show that Scc decreases with increasing of average pore radius, but increases with increasing of fractal dimension. In the case of the same gas/oil interfacial tension, the higher the connate water saturation, the higher the critical condensate saturation. There is a critical gas/oil interfacial tension, below the critical value, the critical condensate saturation increases drastically with increasing of interfacial tension while it keeps almost unchanged when the interfacial tension is above the critical value. The critical condensate saturation decreases with increasing in the gas flow rate. High capillary number results in low critical condensate saturation. Reasonable increase in producing pressure drop can effectively improve the flow capacity of condensate oil.

@article{doi10111514037812,
    author = "Yang, Yi and Li, Juhua and Ji, Lei",
    title = "Numerical Determinationof Critical Condensate Saturation in Gas Condensate Reservoirs",
    year = "2017",
    journal = "Journal of Energy Resources Technology",
    abstract = "Critical condensate saturation, Scc, is a key parameter for the evaluation of well deliverability in gas condensate reservoirs. We propose a new method to determine Scc by performing three-phase flow simulations with three-dimensional (3D) pore network model. First, we establish a network model with random fractal methodology. Second, based on the condensation model in the literature of Li and Firoozabadi, we develop a modified condensation model to describe the condensation phenomenon of gas with connate water in the porous medium. The numerical model is verified by experimental measurements in the literature. Then, we investigate the influence of different factors on the critical condensate saturation, including micro pore structure (pore radius and fractal dimension), condensate gas/oil interfacial tension (IFT), and flow rate at different irreducible water saturation, Swi. The simulation results show that Scc decreases with increasing of average pore radius, but increases with increasing of fractal dimension. In the case of the same gas/oil interfacial tension, the higher the connate water saturation, the higher the critical condensate saturation. There is a critical gas/oil interfacial tension, below the critical value, the critical condensate saturation increases drastically with increasing of interfacial tension while it keeps almost unchanged when the interfacial tension is above the critical value. The critical condensate saturation decreases with increasing in the gas flow rate. High capillary number results in low critical condensate saturation. Reasonable increase in producing pressure drop can effectively improve the flow capacity of condensate oil.",
    url = "https://doi.org/10.1115/1.4037812",
    doi = "10.1115/1.4037812",
    openalex = "W2753842238",
    references = "mohammadikhanaposhtani2014disjoining"
}

When the reservoir pressure is decreased lower than the dew point pressure in shale gas condensate reservoirs, condensate would be formed in the formation. Condensate accumulation severely reduces the commercial production of shale gas condensate reservoirs. Seeking ways to mitigate condensate in the formation and enhance both condensate and gas recovery in shale reservoirs has important significance. Very few related studies have been done. In this paper, both experimental and numerical studies were conducted to evaluate the performance of CO2 huff-n-puff to enhance the condensate recovery in shale reservoirs. Experimentally, CO2 huff-n-puff tests on shale core were conducted. A theoretical field scale simulation model was constructed. The effects of injection pressure, injection time, and soaking time on the efficiency of CO2 huff-n-puff were examined. Experimental results indicate that condensate recovery was enhanced to 30.36% after 5 cycles of CO2 huff-n-puff. In addition, simulation results indicate that the injection period and injection pressure should be optimized to ensure that the pressure of the main condensate region remains higher than the dew point pressure. The soaking process should be determined based on the injection pressure. This work may shed light on a better understanding of the CO2 huff-n-puff- enhanced oil recovery (EOR) strategy in shale gas condensate reservoirs.

@article{doi103390en12010042,
    author = "Meng, Xingbang and Meng, Zhan and Ma, Jixiang and Wang, Tengfei",
    title = "Performance Evaluation of CO2 Huff-n-Puff Gas Injection in Shale Gas Condensate Reservoirs",
    year = "2018",
    journal = "Energies",
    abstract = "When the reservoir pressure is decreased lower than the dew point pressure in shale gas condensate reservoirs, condensate would be formed in the formation. Condensate accumulation severely reduces the commercial production of shale gas condensate reservoirs. Seeking ways to mitigate condensate in the formation and enhance both condensate and gas recovery in shale reservoirs has important significance. Very few related studies have been done. In this paper, both experimental and numerical studies were conducted to evaluate the performance of CO2 huff-n-puff to enhance the condensate recovery in shale reservoirs. Experimentally, CO2 huff-n-puff tests on shale core were conducted. A theoretical field scale simulation model was constructed. The effects of injection pressure, injection time, and soaking time on the efficiency of CO2 huff-n-puff were examined. Experimental results indicate that condensate recovery was enhanced to 30.36\% after 5 cycles of CO2 huff-n-puff. In addition, simulation results indicate that the injection period and injection pressure should be optimized to ensure that the pressure of the main condensate region remains higher than the dew point pressure. The soaking process should be determined based on the injection pressure. This work may shed light on a better understanding of the CO2 huff-n-puff- enhanced oil recovery (EOR) strategy in shale gas condensate reservoirs.",
    url = "https://doi.org/10.3390/en12010042",
    doi = "10.3390/en12010042",
    openalex = "W2905916867",
    references = "doi10211862930ms"
}

The study of flooding gas condensate reservoirs at different stages of depletion (25, 50, 75% of the dew point pressure and at the maximum condensation pressure) with different potential hydrocarbon content of 100, 300 and 500 g/m 3 and different voidage replacement by using injection (50, 100 and 150%). The results showed a positive effect of water injection on the increase of the condensate recovery factor, but a decrease in gas production compared to the basic options of development at depletion drive. Thus, for formation systems with medium and high potential yield of liquid hydrocarbons C 5+, the largest incremental production is obtained in the case when water injection begins with minimum depletion of formation energy. While for a formation system with a low potential yield (100 g/m 3) the maximum technological effect is obtained under the condition of maximum depletion. In the case of medium and high C 5+ yield in the formation gas, with a slight decrease in the formation pressure by 25 or 50% of the dew point pressure, the maximum increase in the condensate recovery factor is achieved at high injection rates with 100 or 150% voidage replacement. The obtained results can be used for rapid screening of potential methods of impact on the gas condensate reservoir, and the final decision concerning the technological parameters of production and injection wells operation will be made due to the results of optimization of multivariate hydrodynamic calculations using geological and technological models.

@article{doi101051e3sconf202123001010,
    author = "Burachok, O. and Kondrat, Oleksandr and Matkivskyі, S. V.",
    title = "Investigation of the efficiency of gas condensate reservoirs waterflooding at different stages of development",
    year = "2021",
    journal = "E3S Web of Conferences",
    abstract = "The study of flooding gas condensate reservoirs at different stages of depletion (25, 50, 75\% of the dew point pressure and at the maximum condensation pressure) with different potential hydrocarbon content of 100, 300 and 500 g/m 3 and different voidage replacement by using injection (50, 100 and 150\%). The results showed a positive effect of water injection on the increase of the condensate recovery factor, but a decrease in gas production compared to the basic options of development at depletion drive. Thus, for formation systems with medium and high potential yield of liquid hydrocarbons C 5+, the largest incremental production is obtained in the case when water injection begins with minimum depletion of formation energy. While for a formation system with a low potential yield (100 g/m 3) the maximum technological effect is obtained under the condition of maximum depletion. In the case of medium and high C 5+ yield in the formation gas, with a slight decrease in the formation pressure by 25 or 50\% of the dew point pressure, the maximum increase in the condensate recovery factor is achieved at high injection rates with 100 or 150\% voidage replacement. The obtained results can be used for rapid screening of potential methods of impact on the gas condensate reservoir, and the final decision concerning the technological parameters of production and injection wells operation will be made due to the results of optimization of multivariate hydrodynamic calculations using geological and technological models.",
    url = "https://doi.org/10.1051/e3sconf/202123001010",
    doi = "10.1051/e3sconf/202123001010",
    openalex = "W3121886392",
    references = "fishlock1996waterflooding, thomas1995towards"
}

Gas condensate reservoirs exhibit complex thermodynamic behaviors when the reservoir pressure is below the dew point pressure, leading to a condensate bank being created inside the reservoir, including gas and oil condensation. Due to natural fractures and multi-phase flows in fractured gas condensate reservoirs, there can be an erroneous interpretation of pressure-transient data using traditional multi-phase models or a fractured model alone. This paper establishes an analytical model for a well test analysis in a gas condensate reservoir with natural fractures. A three-region composite model was employed to characterize the multi-phase flow of retrograde condensation, and the fractured formation was described by a dual-porosity medium. In the first region, both the gas and condensate phases were mobile. In the second region, the gas was mobile whereas the condensates were immobile. In the third region, the only moving phase was the gas phase. The analytical solution was solved by a Laplace transformation to change the partial differential equations to ordinary differential equations. The Stehfest numerical inversion technique was then used to convert the solution of the proposed model into real space. Subsequently, the type curve was obtained and six flow regimes were determined. The influence of several factors on the pressure performance were studied by a sensitivity analysis. Finally, the accuracy of the model was verified by a case study. The model analysis results were in good agreement with the actual formation data. The proposed model provides a few insights toward the production behavior of fractured gas condensate reservoirs, and can be used to evaluate the productivity of such reservoirs.

@article{doi103390en15249442,
    author = "Zhang, Lijun and Yin, Fuguo and Liang, Bin and Cheng, Shiqing and Wang, Yang",
    title = "Pressure Transient Analysis for the Fractured Gas Condensate Reservoir",
    year = "2022",
    journal = "Energies",
    abstract = "Gas condensate reservoirs exhibit complex thermodynamic behaviors when the reservoir pressure is below the dew point pressure, leading to a condensate bank being created inside the reservoir, including gas and oil condensation. Due to natural fractures and multi-phase flows in fractured gas condensate reservoirs, there can be an erroneous interpretation of pressure-transient data using traditional multi-phase models or a fractured model alone. This paper establishes an analytical model for a well test analysis in a gas condensate reservoir with natural fractures. A three-region composite model was employed to characterize the multi-phase flow of retrograde condensation, and the fractured formation was described by a dual-porosity medium. In the first region, both the gas and condensate phases were mobile. In the second region, the gas was mobile whereas the condensates were immobile. In the third region, the only moving phase was the gas phase. The analytical solution was solved by a Laplace transformation to change the partial differential equations to ordinary differential equations. The Stehfest numerical inversion technique was then used to convert the solution of the proposed model into real space. Subsequently, the type curve was obtained and six flow regimes were determined. The influence of several factors on the pressure performance were studied by a sensitivity analysis. Finally, the accuracy of the model was verified by a case study. The model analysis results were in good agreement with the actual formation data. The proposed model provides a few insights toward the production behavior of fractured gas condensate reservoirs, and can be used to evaluate the productivity of such reservoirs.",
    url = "https://doi.org/10.3390/en15249442",
    doi = "10.3390/en15249442",
    openalex = "W4311376705",
    references = "doi10211868668ms"
}

Reservoirs of natural gas and gas condensate have been proposed as a potential for providing affordable and cleaner energy sources to the global population growth and industrialization expansion simultaneously. This work evaluates reservoir simulation for production optimization using Deep Neural network - artificial neural network (DNN-ANN) model to predict the dew point pressure in gas condensate reservoirs from Field-X in the Niger Delta Region of Nigeria. The dew-point pressure (DPP) of gas condensate reservoirs was estimated as a function of gas composition, reservoir temperature, molecular weight and specific gravity of heptane plus percentage. Results obtained show that the mean relative error (MRE) and R-squared (R2) are 0.99965 and 3.35%, respectively, indicating that the model is excellent in predicting DPP values. The Deep Neural Network - Artificial Neural Network (DNN-ANN) model is also evaluated in comparison to earlier models created by previous authors. It was recommended that the DNN - ANN model developed in this study could be applied to reservoir simulation and modeling well performance analysis, reservoir engineering problems and production optimization.

@article{doi104314jasemv27i1135,
    author = "Abeshi, P. U. and Oliomogbe, Timothy Imanobe and Emegha, Joseph Onyeka and Adeyeye, V.A. and Atunwa, Y. O.",
    title = "Application of Deep Neural Network-Artificial Neural Network Model for Prediction Of Dew Point Pressure in Gas Condensate Reservoirs from Field-X in the Niger Delta Region Nigeria",
    year = "2023",
    journal = "Journal of applied science and environmental management",
    abstract = "Reservoirs of natural gas and gas condensate have been proposed as a potential for providing affordable and cleaner energy sources to the global population growth and industrialization expansion simultaneously. This work evaluates reservoir simulation for production optimization using Deep Neural network - artificial neural network (DNN-ANN) model to predict the dew point pressure in gas condensate reservoirs from Field-X in the Niger Delta Region of Nigeria. The dew-point pressure (DPP) of gas condensate reservoirs was estimated as a function of gas composition, reservoir temperature, molecular weight and specific gravity of heptane plus percentage. Results obtained show that the mean relative error (MRE) and R-squared (R2) are 0.99965 and 3.35\%, respectively, indicating that the model is excellent in predicting DPP values. The Deep Neural Network - Artificial Neural Network (DNN-ANN) model is also evaluated in comparison to earlier models created by previous authors. It was recommended that the DNN - ANN model developed in this study could be applied to reservoir simulation and modeling well performance analysis, reservoir engineering problems and production optimization.",
    url = "https://doi.org/10.4314/jasem.v27i11.35",
    doi = "10.4314/jasem.v27i11.35",
    openalex = "W4389673199",
    references = "crossref2017gascondensate"
}

The gas condensate reservoir is classified as a natural gas resource that produces condensate liquid in the reservoir when the pressure in the reservoir drops below the dew point. An innovative strategy to address condensate blockage near the wellbore involves modifying the wettability of the surface of the reservoir rock. This is achieved through chemical treatment, transitioning the surface from a state of strong liquid-wetting to either strong or intermediate gas-wetting. This modern approach effectively mitigates condensate blockage and its associated challenges. Adjusting and sustaining wettability conditions within gas reservoirs requires proper chemicals for a certain reservoir condition. The paper presents a thorough review of wettability and the processes involved in wettability alteration specifically in gas condensate reservoirs. Then, the commonly used wettability alteration chemicals along with their induced flow mechanisms are discussed and reviewed together with a molecular modeling point of view on modern problems of wetting and interfacial phenomena. This paper also focuses on using nanoparticles and fluorochemicals as wettability alteration agents, given that fluorinated nanoparticles are allegedly superior to the chemical wettability altering agents as they change the wettability of the rock surface by modifying both surface energy and surface roughness. This Review indicates the promising use of various nanoparticles along with fluoro materials to enhance ultimate hydrocarbon recovery in gas condensate reservoirs. In the next part, molecular dynamic simulation of imbibition of n-alkanes in kerogen organic slits are presented. The influence of competitive adsorption on multicomponent flows of crude oil and wetting transition on surfaces with molecular roughness are discussed. Actual problems and challenges of molecular modeling methods are also presented.

@article{doi101021acsenergyfuels3c03515,
    author = "Kazemi, Fatemeh and Khlyupin, Aleksey and Azin, Reza and Osfouri, Shahriar and Khosravi, Arash and Sedaghat, Mohammad Hossein and Kazemzadeh, Yousef and Gerke, Kirill M. and Karsanina, Marina V.",
    title = "Wettability Alteration in Gas Condensate Reservoirs: A Critical Review of the Opportunities and Challenges",
    year = "2024",
    journal = "Energy \& Fuels",
    abstract = "The gas condensate reservoir is classified as a natural gas resource that produces condensate liquid in the reservoir when the pressure in the reservoir drops below the dew point. An innovative strategy to address condensate blockage near the wellbore involves modifying the wettability of the surface of the reservoir rock. This is achieved through chemical treatment, transitioning the surface from a state of strong liquid-wetting to either strong or intermediate gas-wetting. This modern approach effectively mitigates condensate blockage and its associated challenges. Adjusting and sustaining wettability conditions within gas reservoirs requires proper chemicals for a certain reservoir condition. The paper presents a thorough review of wettability and the processes involved in wettability alteration specifically in gas condensate reservoirs. Then, the commonly used wettability alteration chemicals along with their induced flow mechanisms are discussed and reviewed together with a molecular modeling point of view on modern problems of wetting and interfacial phenomena. This paper also focuses on using nanoparticles and fluorochemicals as wettability alteration agents, given that fluorinated nanoparticles are allegedly superior to the chemical wettability altering agents as they change the wettability of the rock surface by modifying both surface energy and surface roughness. This Review indicates the promising use of various nanoparticles along with fluoro materials to enhance ultimate hydrocarbon recovery in gas condensate reservoirs. In the next part, molecular dynamic simulation of imbibition of n-alkanes in kerogen organic slits are presented. The influence of competitive adsorption on multicomponent flows of crude oil and wetting transition on surfaces with molecular roughness are discussed. Actual problems and challenges of molecular modeling methods are also presented.",
    url = "https://doi.org/10.1021/acs.energyfuels.3c03515",
    doi = "10.1021/acs.energyfuels.3c03515",
    openalex = "W4391134604",
    references = "doi10211815875pa, esmaeili2015enhancing"
}

Deep condensate gas reservoirs exhibit highly complex and variable phase behaviors, making it crucial to understand the relationship between fluid phase states and flow patterns. This study conducts a comprehensive analysis of the actual production process of the deep condensate gas well A1 in a certain oilfield in China. Combining phase behavior analysis and CMG software simulations, the study systematically investigates phase transitions, viscosity, and density changes in the gas and liquid phases under different pressure conditions, with a reservoir temperature of 165°C. The research covers three crucial depletion stages of the reservoir: single-phase flow, two-phase transition, and two-phase flow. The findings indicate that retrograde condensation occurs when the pressure falls below the dew point pressure, reaching maximum condensate liquid production at around 25 MPa. As pressure decreases, gas phase density and viscosity gradually decrease, while liquid phase density and viscosity show an increasing trend. In the initial single-phase flow stage, maintaining a consistent gas-oil ratio is observed when both bottom-hole and reservoir pressures are higher than the dew point pressure. However, a sudden drop in bottom-hole pressure below the dew point triggers the production of condensate oil, significantly reducing subsequent gas and oil production. In the transitional two-phase flow stage, as the bottom-hole pressure further decreases, the reservoir exhibits a complex flow regime with coexisting areas of gas and liquid. In the subsequent two-phase flow stage, when both bottom-hole and reservoir pressures are below the dew point pressure, a significant increase in the gas-oil ratio is observed. The reservoir manifests a two-phase flow regime, devoid of single-phase gas flow areas. For low-pressure conditions in deep condensate gas reservoirs, considerations include gas injection, gas lift, and cyclic gas injection and production in surrounding wells. Additionally, techniques such as hot nitrogen or CO injection can be employed to mitigate retrograde condensation damage. The implications of this study are crucial for developing targeted development strategies and enhancing the overall development of deep condensate gas reservoirs.

@article{doi1032604ee2024052007,
    author = "Liu, Qiang and Wang, Rujun and Zhang, Yintao and Sun, Chong and Yang, Meichun and Su, Yuliang and Wang, Wendong and Shi, Ying and Chen, Zheng",
    title = "Phase Transitions and Seepage Characteristics during the Depletion Development of Deep Condensate Gas Reservoirs",
    year = "2024",
    journal = "Energy Engineering",
    abstract = "Deep condensate gas reservoirs exhibit highly complex and variable phase behaviors, making it crucial to understand the relationship between fluid phase states and flow patterns. This study conducts a comprehensive analysis of the actual production process of the deep condensate gas well A1 in a certain oilfield in China. Combining phase behavior analysis and CMG software simulations, the study systematically investigates phase transitions, viscosity, and density changes in the gas and liquid phases under different pressure conditions, with a reservoir temperature of 165°C. The research covers three crucial depletion stages of the reservoir: single-phase flow, two-phase transition, and two-phase flow. The findings indicate that retrograde condensation occurs when the pressure falls below the dew point pressure, reaching maximum condensate liquid production at around 25 MPa. As pressure decreases, gas phase density and viscosity gradually decrease, while liquid phase density and viscosity show an increasing trend. In the initial single-phase flow stage, maintaining a consistent gas-oil ratio is observed when both bottom-hole and reservoir pressures are higher than the dew point pressure. However, a sudden drop in bottom-hole pressure below the dew point triggers the production of condensate oil, significantly reducing subsequent gas and oil production. In the transitional two-phase flow stage, as the bottom-hole pressure further decreases, the reservoir exhibits a complex flow regime with coexisting areas of gas and liquid. In the subsequent two-phase flow stage, when both bottom-hole and reservoir pressures are below the dew point pressure, a significant increase in the gas-oil ratio is observed. The reservoir manifests a two-phase flow regime, devoid of single-phase gas flow areas. For low-pressure conditions in deep condensate gas reservoirs, considerations include gas injection, gas lift, and cyclic gas injection and production in surrounding wells. Additionally, techniques such as hot nitrogen or CO injection can be employed to mitigate retrograde condensation damage. The implications of this study are crucial for developing targeted development strategies and enhancing the overall development of deep condensate gas reservoirs.",
    url = "https://doi.org/10.32604/ee.2024.052007",
    doi = "10.32604/ee.2024.052007",
    openalex = "W4400839440",
    references = "fishlock1996waterflooding"
}

This study investigates the optimization of condensate recovery in a retrograde gas reservoir, where production efficiency is hindered by complex interactions between subsurface and surface processes. Accurate modeling of these interactions is essential for reliable production forecasting and economic assessment. This research compares the efficacy of two simulation methodologies: (1) standalone reservoir modeling and (2) integrated modeling encompassing the reservoir, wells, pipelines, and surface facilities under various gas reinjection and production scenarios. Key economic metrics, including Net Present Value (NPV) and Modified Internal Rate of Return (MIRR), are employed to assess scenario feasibility and identify optimal recovery strategies. The findings demonstrate that integrated modeling significantly enhances production forecasts' accuracy by capturing interdependencies often neglected in standalone models. Specifically, optimized gas reinjection in the integrated model resulted in a 15% increase in condensate recovery and improved reservoir pressure maintenance, thereby facilitating sustained productivity. Economically, integrated simulations yielded an NPV up to 10% higher than the standalone approach under optimal reinjection conditions, indicating enhanced economic resilience to market fluctuations. Through this methodology, the study provides a more comprehensive framework for evaluating technical and economic performance in gas condensate reservoir management, offering refined tools for informed decision-making in complex field operations.

@article{doi101007s13202025020441,
    author = "Kaykanloo, Masud Ramezanian and Khademvatani, Asgar and Amiri, Hossein Ali Akhlaghi",
    title = "Techno-economic evaluation of production integration from a reservoir to market under multiple scenarios: a case study of a condensate gas reservoir",
    year = "2025",
    journal = "Journal of Petroleum Exploration and Production Technology",
    abstract = "This study investigates the optimization of condensate recovery in a retrograde gas reservoir, where production efficiency is hindered by complex interactions between subsurface and surface processes. Accurate modeling of these interactions is essential for reliable production forecasting and economic assessment. This research compares the efficacy of two simulation methodologies: (1) standalone reservoir modeling and (2) integrated modeling encompassing the reservoir, wells, pipelines, and surface facilities under various gas reinjection and production scenarios. Key economic metrics, including Net Present Value (NPV) and Modified Internal Rate of Return (MIRR), are employed to assess scenario feasibility and identify optimal recovery strategies. The findings demonstrate that integrated modeling significantly enhances production forecasts' accuracy by capturing interdependencies often neglected in standalone models. Specifically, optimized gas reinjection in the integrated model resulted in a 15\% increase in condensate recovery and improved reservoir pressure maintenance, thereby facilitating sustained productivity. Economically, integrated simulations yielded an NPV up to 10\% higher than the standalone approach under optimal reinjection conditions, indicating enhanced economic resilience to market fluctuations. Through this methodology, the study provides a more comprehensive framework for evaluating technical and economic performance in gas condensate reservoir management, offering refined tools for informed decision-making in complex field operations.",
    url = "https://doi.org/10.1007/s13202-025-02044-1",
    doi = "10.1007/s13202-025-02044-1",
    openalex = "W4414120133",
    references = "crossref2017gascondensate"
}