Relevant bibliographies by topics / Gas condensate reservoirs – Permeability

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Academic literature on the topic 'Gas condensate reservoirs – Permeability'

Author: Grafiati
Published: 4 June 2021
Last updated: 2 February 2022

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Journal articles on the topic "Gas condensate reservoirs – Permeability"

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Hu, Wen Ge, Xiang Fang Li, Xin Zhou Yang, Ke Liu Wu, and Jun Tai Shi. "Energy Control in the Depletion of Gas Condensate Reservoirs with Different Permeabilities." Advanced Materials Research 616-618 (December 2012): 796–803. http://dx.doi.org/10.4028/www.scientific.net/amr.616-618.796.

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Energy control (i. e. pressure control) has an obvious effect on development effect in the depletion of gas condensate reservoir. Phase change behavior and characteristics of the relative pemeability in gas condensate reservoirs were displayed in this paper, then pressure and condensate distribution were showed through reservoir simulation. Finally, the influence of the pressure drop on condensate distribution and condensate oil production in gas condensate reservoirs with different permeabilities was studied. Results show that: First, in high / moderate permeability gas condensate reservoirs, the pressure and the condensate blocking will extend to further reservoir, while the pressure and condensate just appear in the vicinity of wellbore in low permeability gas condensate reservoirs. Second, the influence of pressure drop on condensate distribution in high permeability gas condensate reservoirs is obvious, the condensate blocking extends with the increasing of the pressure drop, and condensate extent can be controlled by optimizing a rational pressure drop, while the influence is inconspicuous in low permeability gas condensate reservoirs. Third, the influence of pressure drop on condensate oil production in high / moderate permeability gas condensate reservoirs is conspicuous, a rational pressure drop exists, while the influence is indistinct in low permeability or tight gas condensate reservoirs, before the retrograde condensation, a low pressure drop should be adopted in a long term until the bottom hole flowing pressure drops below the dew point pressure, when the condensate blocking forms, well stimulation is advised before developing by pressure control.
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Chen, H. L., S. D. Wilson, and T. G. Monger-McClure. "Determination of Relative Permeability and Recovery for North Sea Gas-Condensate Reservoirs." SPE Reservoir Evaluation & Engineering 2, no. 04 (August 1, 1999): 393–402. http://dx.doi.org/10.2118/57596-pa.

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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. Introduction Reservoirs bearing gas condensates are becoming more commonplace as developments are encountering greater depths, higher pressures, and higher temperatures. In the North Sea, gas condensate reservoirs comprise a significant portion of the total hydrocarbon reserves. Accuracy in engineering computations for gas condensate systems (e.g., estimating reserves, sizing surface facilities, and predicting productivity trends) depends upon a basic understanding of phase and flow behavior interrelationships. For example, gas productivity may be curtailed as condensate accumulates by pressure depletion below the dew point pressure (Pd). Conceptual modeling on gas condensate systems suggests that relative permeability (kr) curves govern the magnitude of gas productivity loss.1,2 Unfortunately, available gas and condensate relative permeability (krg and krc) results for gas condensates are primarily limited to synthetic systems. Such results show that higher CCS and less krg reduction were observed for a conventional gas/oil system compared to a gas condensate system.3,4 If condensate accumulates as a continuous film due to low interfacial tension (IFT), then high IFT gas/oil and water/oil kr data may not be applicable to gas condensates.5 Water invasion of gas condensate reservoirs may enhance hydrocarbon recovery or trap potential reserves. Laboratory results suggest water invasion of low IFT gas condensates may not be represented using high IFT water/oil and water/gas displacements.6 Subsequent blowdown may remobilize hydrocarbons trapped by water invasion. The presence of condensate may hinder gas remobilization, thus conventional gas/water blowdown experiments may not be appropriate in evaluating the feasibility of depressurization for gas condensates.7,8 Other laboratory evaluations of gas condensate flow behavior indicate measured results depend upon experimental procedures, fluid properties, and rock properties.3,9–20 Factors to consider include the history of condensate formation (i.e., imbibition or drainage), how condensate was introduced (i.e., in-situ dropout versus external injection or inflowing gas), flow rate, differential pressure, system pressure, IFT, connate water saturation, core permeability, and core orientation. Experiments performed to evaluate the consequences of water invasion suggest optimum conditions depend upon IFT, initial gas saturation, and core permeability.7,21,22 Reported blowdown experiments imply gas recovery depends upon the degree of gas expansion.7,8 The kr results obtained in this study represent gas condensate flow between the far-field and the near-wellbore region. The results are useful input for numerical simulation, especially to test rate- or IFT-sensitive relative permeability functions. Results on hydrocarbon recovery and trapping from water injection and blowdown are beneficial in evaluating improved recovery options for gas condensates. Experimental Procedures Coreflooding experiments were performed under reservoir conditions using rock and fluid samples from two distinct North Sea gas condensate reservoirs. A detailed description of the experimental methods is provided in the Appendix. Briefly, the experiments were conducted in a horizontal coreflood apparatus equipped with in-line PVT and viscosity measuring devices. The entire system experienced in-situ condensate drop out by constant volume depletion (CVD) from above Pd to either the pressure corresponding to CCS, or to the pressure of maximum condensate saturation Scmax Steady-state krg was measured by injecting equilibrated gas (before CCS). Steady-state krg and krc were measured by injecting gas condensate repressurized to above Pd (after CCS). The gas/oil fractional flow rate was defined by the pressure level in the core which was controlled by the core outlet back-pressure regulator. During krg measurements, the injection rate was varied to access rate effects. After the krg or krg and krc measurements to Scmax were completed, water injection was performed to quantify hydrocarbon trapping and recovery. Blowdown followed to evaluate additional hydrocarbon recovery. Recombined Reservoir Fluid Properties. Two North Sea gas condensate reservoir fluids were recombined using separator oil and synthetic gas. Tables 1 and 2 list compositions and PVT properties for the reconstituted fluids. The Pd was 7,070 psig at 250°F for Reservoir A, and 6,074 psig at 259°F for Reservoir B (Table 2). The maximum liquid dropout under constant composition expansion (CCE) was 31.7% for Reservoir A, and 42.5% for Reservoir B (Fig. 1). Reservoir B is a richer gas condensate and exhibits more near-critical phase behavior than Reservoir A.
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Panja, Palash, and Milind Deo. "Factors That Control Condensate Production From Shales: Surrogate Reservoir Models and Uncertainty Analysis." SPE Reservoir Evaluation & Engineering 19, no. 01 (December 31, 2015): 130–41. http://dx.doi.org/10.2118/179720-pa.

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Summary Rapid development of shales for the production of oils and condensates may not be permitting adequate analysis of the important factors governing recovery. Understanding the performance of shales or tight oil reservoirs producing condensates requires numerically extensive compositional simulations. The purpose of this study is to identify important factors that control production of condensates from low-permeability plays and to develop analytical “surrogate” models suitable for Monte Carlo analysis. In this study, the surrogate reservoir models were second-order response surfaces functionally dependent on the nine main factors that most affect condensate recovery in ultralow-permeability reservoirs. The models were developed by regressing the results of experimentally designed compositional simulations. The Box-Behnken (Box and Behnken 1960) technique, a partial-factorial method, was used for design of these experiments or simulations. The main factors that controlled condensate recovery from ultralow-permeability reservoirs were reservoir permeability, rock compressibility, initial condensate/gas ratio (CGR), initial reservoir pressure, and fracture spacing. Another main outcome of this paper was the generation of probability-density functions, and P10, P50, and P90 values for condensate recovery on the basis of the uncertainty in input parameters. The condensate-recovery P50 for rate-based outcome of a 5-B/D per fracture was found to be less than 10%.
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Bilotu Onoabhagbe, Benedicta, Paul Russell, Johnson Ugwu, and Sina Rezaei Gomari. "Application of Phase Change Tracking Approach in Predicting Condensate Blockage in Tight, Low, and High Permeability Reservoirs." Energies 13, no. 24 (December 11, 2020): 6551. http://dx.doi.org/10.3390/en13246551.

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Prediction of the timing and location of condensate build-up around the wellbore in gas condensate reservoirs is essential for the selection of appropriate methods for condensate recovery from these challenging reservoirs. The present work focuses on the use of a novel phase change tracking approach in monitoring the formation of condensate blockage in a gas condensate reservoir. The procedure entails the simulation of tight, low and high permeability reservoirs using global and local grid analysis in determining the size and timing of three common regions (Region 1, near wellbore; Region 2, condensate build-up; and Region 3, single-phase gas) associated with single and two-phase gas and immobile and mobile gas condensate. The results show that permeability has a significant influence on the occurrence of the three regions around the well, which in turn affects the productivity of the gas condensate reservoir studied. Predictions of the timing and location of condensate in reservoirs with different permeability levels of 1 mD to 100 mD indicate that local damage enhances condensate formation by 60% and shortens the duration of the immobile phase by 45%. Meanwhile, the global change in permeability increases condensate formation by 80% and reduces the presence of the immobile phase by 60%. Finally, this predictive approach can help in mitigating condensate blockage around the wellbore during production.
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Henderson, G. D., A. Danesh, D. H. Tehrani, S. Al-Shaidi, and J. M. Peden. "Measurement and Correlation of Gas Condensate Relative Permeability by the Steady-State Method." SPE Reservoir Evaluation & Engineering 1, no. 02 (April 1, 1998): 134–40. http://dx.doi.org/10.2118/30770-pa.

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Abstract High pressure core flood experiments using gas condensate fluids in long sandstone cores have been conducted. Steady-state relative permeability points were measured over a wide range of condensate to gas ratio's (CGR), with the velocity and interfacial tension (IFT) being varied between tests in order to observe the effect on relative permeability. The experimental procedures ensured that the fluid distribution in the cores was representative of gas condensate reservoirs. Hysteresis between drainage and imbibition during the steady-state measurements was also investigated, as was the repeatability of the data. A relative permeability rate effect for both gas and condensate phases was observed, with the relative permeability of both phases increasing with an increase in flow rate. The relative permeability rate effect was still evident as the IFT increased by an order of magnitude, with the relative permeability of the gas phase reducing more than the condensate phase. The influence of end effects was shown to be negligible at the IFT conditions used in the tests, with the Reynolds number indicating that flow was well within the so called laminar regime at all test conditions. The observed rate effect was contrary to that of the conventional non-Darcy flow where the effective permeability should decrease with increasing flow rate. A generalised correlation between relative permeability, velocity and IFT has been proposed, which should be more appropriate for condensing fluids than the conventional correlation. The results highlight the need for appropriate experimental methods and relative permeability relations where the distribution of the phases are representative of those in gas condensate reservoirs. This study will be particularly applicable to the vicinity of producing wells, where the rate effect on gas relative permeability can significantly affect well productivity. The findings provide previously unreported data on relative permeability and recovery of gas condensate fluids at realistic conditions. Introduction During the production of gas condensate reservoirs, the reservoir pressure will be gradually reduced to below the dew-point, giving rise to retrograde condensation. In the vicinity of producing wells where the rate of pressure reduction is greatest, the increase in the condensate saturation from zero is accompanied by a reduction in relative permeability of gas, due to the loss of pore space available to gas flow. It is the perceived effect of this local condensate accumulation on the near wellbore gas and condensate mobility that is one of the main areas of interest for reservoir engineers. The availability of accurate relative permeability data applicable to flow in the wellbore region impacts the management of gas condensate reservoirs.
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Bei, Yu Bei, Li Hui, and Li Dong Lin. "The Researches on Reasonable Well Spacing of Gas Wells in Deep and low Permeability Gas Reservoirs." E3S Web of Conferences 38 (2018): 01038. http://dx.doi.org/10.1051/e3sconf/20183801038.

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This Gs64 gas reservoir is a condensate gas reservoir which is relatively integrated with low porosity and low permeability found in Dagang Oilfield in recent years. The condensate content is as high as 610g/m3. At present, there are few reports about the well spacing of similar gas reservoirs at home and abroad. Therefore, determining the reasonable well spacing of the gas reservoir is important for ensuring the optimal development effect and economic benefit of the gas field development. This paper discusses the reasonable well spacing of the deep and low permeability gas reservoir from the aspects of percolation mechanics, gas reservoir engineering and numerical simulation. considering there exist the start-up pressure gradient in percolation process of low permeability gas reservoir, this paper combined with productivity equation under starting pressure gradient, established the formula of gas well spacing with the formation pressure and start-up pressure gradient. The calculation formula of starting pressure gradient and well spacing of gas wells. Adopting various methods to calculate values of gas reservoir spacing are close to well testing' radius, so the calculation method is reliable, which is very important for the determination of reasonable well spacing in low permeability gas reservoirs.
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Mott, R. E., A. S. Cable, and M. C. Spearing. "Measurements of Relative Permeabilities for Calculating Gas-Condensate Well Deliverability." SPE Reservoir Evaluation & Engineering 3, no. 06 (December 1, 2000): 473–79. http://dx.doi.org/10.2118/68050-pa.

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Summary Well deliverability in many gas-condensate reservoirs is reduced by condensate banking when the bottomhole pressure falls below the dewpoint, although the impact of condensate banking may be reduced due to improved mobility at high capillary number in the near-well region. This paper presents the results of relative permeability measurements on a sandstone core from a North Sea gas-condensate reservoir, at velocities that are typical of the near-well region. The results show a clear increase in mobility with capillary number, and the paper describes how the data can be modeled with empirical correlations which can be used in reservoir simulators. Introduction Well deliverability is an important issue in the development of many gas-condensate reservoirs, especially where permeability is low. When the well bottomhole flowing pressure falls below the dewpoint, condensate liquid may build up around the wellbore, causing a reduction in gas permeability and well productivity. In extreme cases the liquid saturation may reach values as high as 50 or 60% and the well deliverability may be reduced by up to an order of magnitude. The loss in productivity due to this "condensate banking" effect may be significant, even in very lean gas-condensate reservoirs. For example, in the Arun reservoir,1 the productivity reduced by a factor of about 2 as the pressure fell below the dewpoint, even though the reservoir fluid was very lean with a maximum liquid drop out of only 1% away from the well. Most of the pressure drop from condensate blockage occurs within a few feet of the wellbore, where velocities are very high. There is a growing body of evidence from laboratory coreflood experiments to suggest that gas-condensate relative permeabilities increase at high velocities, and that these changes can be correlated against the capillary number.2–8 The capillary number is a dimensionless number that measures the relative strength of viscous and capillary forces. There are several gas-condensate fields where simulation with conventional relative permeability models has been found to underestimate well productivity.1,9,10 To obtain a good match between simulation results and well-test data, it was necessary to increase the mobility in the near-well region, either empirically or through a model of the increase in relative permeability at high velocity. This effect can increase well productivity significantly, and in some cases may eliminate most of the effect of condensate blockage. Experimental Data Requirements Fevang and Whitson11 have shown that the key parameter in determining well deliverability is the relationship between krg and the ratio krg/ kro. When high-velocity effects are significant, the most important information is the variation of krg with krg/k ro and the capillary number Nc. The relevant values of krg/kro are determined by the pressure/volume/temperature (PVT) properties of the reservoir fluids, but typical values might be 10 to 100 for lean condensates, 1 to 10 for rich condensates, and 0.1 to 10 for near-critical fluids. There are various ways of defining the capillary number, but in this paper we use the definition (1)Nc=vgμgσ, so that the capillary number is proportional to the gas velocity and inversely proportional to interfacial tension (IFT). The capillary numbers that are relevant for well deliverability depend on the flow rate, fluid type, and well bottomhole pressure, but as a general rule, values between 10?6 and 10?3 are most important. Experimental Methods In a gas-condensate reservoir, there are important differences between the flow regimes in the regions close to and far from the well. These different flow regimes are reflected in the requirements for relative permeability data for the deep reservoir and near-well regions. Far from the well, velocities are low, and liquid mobility is usually less important, except in reservoirs containing very rich fluids. In the near-well region, both liquid and gas phases are mobile, velocities are high, and the liquid mobility is important because of its effect on the relationship between krg and krg/kro. Depletion Method. Relative permeabilities for the deep reservoir region are often measured in a coreflood experiment, where the fluids in the core are obtained by a constant volume depletion (CVD) on a reservoir fluid sample. Relative permeabilities are measured at decreasing pressures from the fluid dewpoint, and increasing liquid saturation. In this type of experiment, the liquid saturation cannot exceed the critical condensate saturation or the maximum value in a CVD experiment, so that it is not possible to acquire data at the high liquid saturations that occur in the reservoir near to the well. The "depletion" experiment provides relative permeability data that are relevant to the deep reservoir, but there can be problems in interpreting the results due to the effects of IFT. Changes in liquid saturation are achieved by reducing pressure, which results in a change of IFT. The increase in IFT as pressure falls may cause a large reduction in mobility, and Chen et al.12 describe an example where the condensate liquid relative permeability decreases with increasing liquid saturation. Steady-State Method. The steady-state technique can be used to measure relative permeabilities at the higher liquid saturations that occur in the near-well region. Liquid and gas can be injected into the core from separate vessels, allowing relative permeabilities to be measured for a wide range of saturations. Results of gas-condensate relative permeabilities measured by this technique have been reported by Henderson et al.2,6 and Chen et al.12 .
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Hassan, Amjed M., Mohamed A. Mahmoud, Abdulaziz A. Al-Majed, Dhafer Al-Shehri, Ayman R. Al-Nakhli, and Mohammed A. Bataweel. "Gas Production from Gas Condensate Reservoirs Using Sustainable Environmentally Friendly Chemicals." Sustainability 11, no. 10 (May 18, 2019): 2838. http://dx.doi.org/10.3390/su11102838.

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Unconventional reservoirs have shown tremendous potential for energy supply for long-term applications. However, great challenges are associated with hydrocarbon production from these reservoirs. Recently, injection of thermochemical fluids has been introduced as a new environmentally friendly and cost-effective chemical for improving hydrocarbon production. This research aims to improve gas production from gas condensate reservoirs using environmentally friendly chemicals. Further, the impact of thermochemical treatment on changing the pore size distribution is studied. Several experiments were conducted, including chemical injection, routine core analysis, and nuclear magnetic resonance (NMR) measurements. The impact of thermochemical treatment in sustaining gas production from a tight gas reservoir was quantified. This study demonstrates that thermochemical treatment can create different types of fractures (single or multistaged fractures) based on the injection method. Thermochemical treatment can increase absolute permeability up to 500%, reduce capillary pressure by 57%, remove the accumulated liquids, and improve gas relative permeability by a factor of 1.2. The findings of this study can help to design a better thermochemical treatment for improving gas recovery. This study showed that thermochemical treatment is an effective method for sustaining gas production from tight gas reservoirs.
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Bozorgzadeh, Manijeh, and Alain C. Gringarten. "Estimating Productivity-Controlling Parameters in Gas/Condensate Wells From Transient Pressure Data." SPE Reservoir Evaluation & Engineering 10, no. 02 (April 1, 2007): 100–111. http://dx.doi.org/10.2118/94018-pa.

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Summary The ability to predict well deliverability is a key issue for the development of gas/condensate reservoirs. We show in this paper that well deliverability depends mainly on the gas relative permeabilities at both the endpoint and the near-wellbore saturations, as well as on the reservoir permeability. We then demonstrate how these parameters and the base capillary number can be obtained from pressure-buildup data by using single-phase and two-phase pseudopressures simultaneously. These parameters can in turn be used to estimate gas relative permeability curves. Finally, we illustrate this approach with both simulated pressure-buildup data and an actual field case. Introduction and Background In gas/condensate reservoirs, a condensate bank forms around the wellbore when the bottomhole pressure (BHP) falls below the dewpoint pressure. This creates three different saturation zones around the well. Close to the wellbore, high condensate saturation reduces the effective permeability to gas, resulting in severe well productivity decline (Kniazeff and Nvaille 1965; Afidick et al. 1994; Lee and Chaverra 1998; Jutila et al. 2001; Briones et al. 2002). This decline is reduced at high gas rates and/or low capillary forces, which lower condensate saturation in the immediate vicinity of the wellbore, resulting in a corresponding increase in the gas relative permeability. This is called the capillary-number effect, positive coupling, viscous stripping, or velocity stripping (Boom et al. 1995; Henderson et al. 1998, 2000a; Ali et al. 1997a; Blom et al. 1997). High gas rates, on the other hand, induce inertia (also referred to as turbulent or non-Darcy flow effects), which reduces productivity. Well productivity is thus a balance between capillary number and inertia effects (Boom et al. 1995; Henderson et al. 1998, 2000a; Ali et al. 1997a, 1997b; Blom et al. 1997; Mott et al. 2000.). Well-deliverability forecasts for gas/condensate wells are usually performed with the help of numerical compositional simulators. Compositional simulation requires fine gridding to model the formation of the condensate bank with the required accuracy (Ali et al. 1997a). Non-Darcy flow and capillary-number effects (Mott 2003) are accounted for through empirical correlations, which require inputs such as the base capillary number (i.e., the minimum value required to see capillary-number effects), the reservoir absolute permeability, and the relative permeability curves. These are usually determined experimentally, but laboratory measurements at near-wellbore conditions are very difficult and expensive to obtain. An alternative, as shown in this paper, is to obtain them from well-test data. Well-test analysis is recognized as a valuable tool for reservoir surveillance and monitoring and provides estimates of a number of parameters required for reservoir characterization, reservoir simulation, and well-productivity forecasting. In gas/condensate reservoirs, when the BHP is below the dewpoint pressure, the effective permeability to gas in the near-wellbore region and at initial liquid saturation can be estimated with single-phase pseudopressures (Al-Hussainy et al. 1966) and a two- or three-region radial composite well-test-interpretation model (Chu and Shank 1993; Gringarten et al. 2000; Daungkaew et al. 2002), whereas the reservoir absolute permeability may be determined with two-phase steady-state pseudopressures (Raghavan et al. 1999; Xu and Lee 1999). In this paper, we show that well-test analysis can provide additional parameters, such as the gas relative permeabilities at both the endpoint and the near-wellbore saturations and the base capillary number. These in turn can be used to generate estimated relative permeability curves for gas.
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Safari-Beidokhti, Mohsen, Abdolnabi Hashemi, Reza Abdollahi, Hamed Hematpur, and Hamid Esfandyari. "Numerical Well Test Analysis of Condensate Dropout Effects in Dual-Permeability Model of Naturally Fractured Gas Condensate Reservoirs: Case Studies in the South of Iran." Mathematical Problems in Engineering 2021 (May 7, 2021): 1–10. http://dx.doi.org/10.1155/2021/9916914.

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Naturally fractured reservoirs (NFR) represent an important percentage of worldwide hydrocarbon reserves and production. The performance of naturally fractured gas condensate reservoirs would be more complicated regarding both rock and fluid effects. In contrast to the dual-porosity model, dual-porosity/dual-permeability (dual-permeability) model is considered as a modified model, in which flow to the wellbore occurs through both matrix and fracture systems. Fluid flow in gas condensate reservoirs usually demonstrates intricate flow behavior when the flowing bottom-hole pressure falls below the dew point. Accordingly, different regions with different characteristics are formed within the reservoir. These regions can be recognized by pressure transient analysis. Consequently, distinguishing between reservoir effects and fluid effects is challenging in these specific reservoirs and needs numerical simulation. The main objective of this paper is to examine the effect of condensate banking on the pressure behavior of lean and rich gas condensate NFRs through a simulation approach. Subsequently, evaluation of early-time characteristics of the pressure transient data is provided through a single well compositional simulation model. Then, drawdown, buildup, and multirate tests are conducted to establish the condition in which the flowing bottom-hole pressure drops below the dew point causing retrograde condensation. The simulation results are confirmed through well test analysis in both Iranian naturally fractured rich and lean gas condensate fields. Interpretations of simulation analysis revealed that the richer gas is more prone to condensation. When the pressure drops below the dew point, the pressure derivative curves in the rich gas system encounter a more shift to the right, and the trough becomes more pronounced as compared to the lean one.
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Dissertations / Theses on the topic "Gas condensate reservoirs – Permeability"

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Al-Kharusi, Badr Soud. "Relative permeability of gas-condensate near wellbore, and gas-condensate-water in bulk of reservoir." Thesis, Heriot-Watt University, 2000. http://hdl.handle.net/10399/1098.

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Kgogo, Thabo C. "Well test analysis of low permeability medium-rich to rich gas condensate homogeneous and layered reservoirs." Thesis, Imperial College London, 2011. http://hdl.handle.net/10044/1/6856.

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This study investigates near-wellbore effects during well testing in low permeability, single- and multi-layered, medium-rich to rich, gas condensate reservoirs. Theoretical results obtained from compositional simulations are validated with actual well test data. We first study well test behaviours for a range of gas condensate fluids with increasing condensate to gas ratios (CGR), from lean to medium-rich to rich. We verify that, during a drawdown below the dew point pressure, a condensate bank forms around the wellbore for all fluids studied. We show that, in the case of a medium-rich gas, as pressure increases above the dew point pressure in a subsequent build up, part of the condensate bank closer to the well dissolves into the gas, with the fluid returning to being a single-phase gas. This is different from what happens with rich gas, where the bank disappears completely; and with lean gas, where condensate saturation at the end of a drawdown and in the subsequent build up are very similar. Lean and medium-rich gas condensate fluids yield three-region radial composite derivative behaviours corresponding to dry gas away from the well, condensate bank, and capillary number effects in the immediate vicinity of the well. Only two-region radial composite behaviours are created in the case of rich gas fluids, as rates required to see capillary number effects are not reached in practice. We then study layered systems and show that composite behaviour due to condensate bank and a multi-layer behaviour are superimposed, with the condensate bank appearing on top of multi-layer effects. In addition, the production rate ratio of the most permeable layer rate to the total rate tends to one as the least permeable layer is choked by its condensate bank. We also investigated gravity effects and conclude that gravity has little impact on pressure response once the condensate bank develops near the wellbore and in particular does not create a partial penetration behaviour. Lastly, we show that drilling horizontal wells and hydraulically-fracturing vertical wells improve well productivity when pressure is below the dew point pressure. Condensate drop-out effects are minimized when wells are fractured prior to being produced.
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Al, Ghamdi Bander Nasser Ayala H. Luis Felipe. "Analysis of capillary pressure and relative permeability effects on the productivity of naturally fractured gas-condensate reservoirs using compositional simulation." [University Park, Pa.] : Pennsylvania State University, 2009. http://etda.libraries.psu.edu/theses/approved/WorldWideIndex/ETD-4622/index.html.

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Ouzzane, Djamel Eddine. "Phase behaviour in gas condensate reservoirs." Thesis, Imperial College London, 2005. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.417922.

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Labed, Ismail. "Gas-condensate flow modelling for shale gas reservoirs." Thesis, Robert Gordon University, 2016. http://hdl.handle.net/10059/2144.

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In the last decade, shale reservoirs emerged as one of the fast growing hydrocarbon resources in the world unlocking vast reserves and reshaping the landscape of the oil and gas global market. Gas-condensate reservoirs represent an important part of these resources. The key feature of these reservoirs is the condensate banking which reduces significantly the well deliverability when the condensate forms in the reservoir below the dew point pressure. Although the condensate banking is a well-known problem in conventional reservoirs, the very low permeability of shale matrix and unavailability of proven pressure maintenance techniques make it more challenging in shale reservoirs. The nanoscale range of the pore size in the shale matrix affects the gas flow which deviates from laminar Darcy flow to Knudsen flow resulting in enhanced gas permeability. Furthermore, the phase behaviour of gas-condensate fluids is affected by the high capillary pressure in the matrix causing higher condensate saturation than in bulk conditions. A good understanding and an accurate evaluation of how the condensate builds up in the reservoir and how it affects the gas flow is very important to manage successfully the development of these high-cost hydrocarbon resources. This work investigates the gas Knudsen flow under condensate saturation effect and phase behaviour deviation under capillary pressure of gas-condensate fluids in shale matrix with pore size distribution; and evaluates their effect on well productivity. Supplementary MATLAB codes are provided elsewhere on OpenAIR: http://hdl.handle.net/10059/2145.
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Vo, Dyung Tien. "Well test analysis for gas condensate reservoirs /." Access abstract and link to full text, 1989. http://0-wwwlib.umi.com.library.utulsa.edu/dissertations/fullcit/9014121.

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Al, Harrasi Mahmood Abdul Wahid Sulaiman. "Fluid flow properties of tight gas-condensate reservoirs." Thesis, University of Leeds, 2011. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.582106.

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Tight gas-condensate reservoirs contain large reserves, but can be extremely costly to develop. Understanding the fundamental controls on the fluid flow behaviour of tight gas and gas-condensate reservoirs has the potential to result in more cost-effective reservoir development and help increase the world's producible reserves. Therefore, the principal objective of the thesis is to improve understanding of multiphase flow within tight gas-condensate reservoirs. In order to achieve this objective a series of pore-to-core scale experiments under controlled conditions were performed, followed by numerical simulation. Three methodologies were used in this study: First, pore-scale experiments in glass micromodels with liquid-liquid systems were performed to improve understanding of the phase separation and flow mechanisms at pore level. Second, coreflood experiments were performed while in-situ saturation was monitored using an X-ray C'I' -scanner. A newly developed liquid-liquid system was used in these experiments. Flow through tight gas sandstones allowed the determination of relative penneabilities as well as determining their dependence on absolute permeability and capillary number. Third, production simulation modelling has been conducted to investigate the implications of the results. The micromodel experiments have proved extremely useful for characterizing the flow behaviour . of condensate systems. The results showed that the flow mechanisms and phases' distributions were affected largely by interfacial tension, pore structure and wettability.
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Del, Castillo Maravi Yanil. "New inflow performance relationships for gas condensate reservoirs." Texas A&M University, 2003. http://hdl.handle.net/1969/354.

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Aluko, Olalekan A. "Well test dynamics of rich gas condensate reservoirs." Thesis, Imperial College London, 2011. http://hdl.handle.net/10044/1/7887.

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Saleh, Amer Mohamed. "Well test and production prediction of gas condensate reservoirs." Thesis, Heriot-Watt University, 1992. http://hdl.handle.net/10399/813.

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Books on the topic "Gas condensate reservoirs – Permeability"

1

Kushnirov, V. V. Retrogradnye gazozhidkostnye sistemy v nedrakh. Tashkent: Izd-vo "Fan" Uzbekskoĭ SSR, 1987.

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Zibert, G. K. Perspektivnye tekhnologii i oborudovanie dli︠a︡ podgotovki i perepodgotovki uglevodorodnykh gazov i kondensata: Prospective Tecnologies and Equipment for Preparation and Processing Hydrocarbon Gases and Condensate. Moskva: Nedra, 2005.

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Ė, Ramazanova Ė. Prikladnai͡a︡ termodinamika neftegazokondensatnykh mestorozhdeniĭ. Moskva: "Nedra", 1986.

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Dolgushin, N. V. Terminologii︠a︡ i osnovnye polozhenii︠a︡ tekhnologii gazokondensatnykh issledovaniĭ = Terminology and basic principles of technique for gas condensate research. Moskva: Nedra, 2004.

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Serebri︠a︡kov, A. O. Sinergetika razvedki i razrabotki nefti︠a︡nykh i gazovykh mestorozhdeniĭ-gigantov s kislymi komponentami: Monografii︠a︡. Astrakhanʹ: Astrakhanskiĭ gos. universitet, 2006.

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Krylov, G. V., and I︠U︡ K. Vasilʹchuk. Kriosfera neftegazokondensatnykh mestorozhdeniĭ poluostrova I︠A︡mal: Cryosphere of oil and gas condensate fields of Yamal Peninsula. Ti︠u︡menʹ: Ti︠u︡menNIIgiprogaz, 2006.

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Gasumov, R. A. Geologii︠a︡, burenie i razrabotka gazovykh i gazokondensatnykh mestorozhdeniĭ. Stavropolʹ: SevKavNIPIgaz, 2008.

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P, Zaporozhet︠s︡ E., and Valiullin I. M, eds. Podgotovka i pererabotka uglevodorodnykh gazov i kondensata: Tekhnologii i oborudovanie, spravochnoe posobie. 2nd ed. Moskva: Nedra, 2008.

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Vysot͡skiĭ, I. V. Formirovanie nefti͡anykh, gazovykh i kondensatnogazovykh mestorozhdeniĭ. Moskva: "Nedra", 1986.

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I͡Azik, A. V. Sistemy i sredstva okhlazhdenii͡a prirodnogo gaza. Moskva: "Nedra", 1986.

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Book chapters on the topic "Gas condensate reservoirs – Permeability"

1

Reffstrup, Jan, and Henrik Olsen. "Evaluation of PVT Data from Low Permeability Gas Condensate Reservoirs." In North Sea Oil and Gas Reservoirs — III, 289–96. Dordrecht: Springer Netherlands, 1994. http://dx.doi.org/10.1007/978-94-011-0896-6_25.

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Saucier, Antoine. "Scaling of the Effective Permeability in Multifractal Reservoirs." In North Sea Oil and Gas Reservoirs — III, 273–76. Dordrecht: Springer Netherlands, 1994. http://dx.doi.org/10.1007/978-94-011-0896-6_23.

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Tyberø, G., L. Johannessen, and A. J. Bouchard. "Heidrun Long Core Study — An Alternative Approach to Relative Permeability Determination." In North Sea Oil and Gas Reservoirs — III, 325–29. Dordrecht: Springer Netherlands, 1994. http://dx.doi.org/10.1007/978-94-011-0896-6_29.

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Sundal, L., C. A. Kossack, and J. Kleppe. "The Effect of Low-Permeability Layers on Oil Production from Vertical and Horizontal Wells in the Troll Field." In North Sea Oil and Gas Reservoirs—II, 213–21. Dordrecht: Springer Netherlands, 1990. http://dx.doi.org/10.1007/978-94-009-0791-1_17.

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Main, I. G., B. G. D. Smart, G. B. Shimmield, S. C. Elphick, B. R. Crawford, and B. T. Ngwenya. "The Effects of Combined Changes in Pore Fluid Chemistry and Stress State on Permeability in Reservoir Rocks: Preliminary Results from Analogue Materials." In North Sea Oil and Gas Reservoirs — III, 357–70. Dordrecht: Springer Netherlands, 1994. http://dx.doi.org/10.1007/978-94-011-0896-6_32.

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Yakush, S. E., A. N. Galybin, A. M. Polishchuk, and S. A. Vlasov. "Modeling of Thermal Gas Treatment of Low-Permeability Reservoirs of Bazhenov Formation." In Springer Proceedings in Earth and Environmental Sciences, 380–94. Cham: Springer International Publishing, 2019. http://dx.doi.org/10.1007/978-3-030-11533-3_38.

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Dekang, Zhong, and Zhu Xiaomin. "Impaction of the Stacking Pattern of Sandstone and Mudstone on the Porosity and Permeability of Sandstone Reservoirs in Different Buried Depths." In Acid Gas Injection and Related Technologies, 411–27. Hoboken, NJ, USA: John Wiley & Sons, Inc., 2011. http://dx.doi.org/10.1002/9781118094273.ch26.

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Berezovsky, Vladimir, Ivan Belozerov, Yungfeng Bai, and Marsel Gubaydullin. "Digital Rock Modeling of a Terrigenous Oil and Gas Reservoirs for Predicting Rock Permeability with Its Fitting Using Machine Learning." In Communications in Computer and Information Science, 203–13. Cham: Springer International Publishing, 2019. http://dx.doi.org/10.1007/978-3-030-36592-9_17.

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Shi, Lin-hui, Xiao-feng Li, Ke-feng Huo, Zhang-liang Zhao, Te-bo Yang, Yan Wang, and Yan-xia Liu. "Study on the Distribution of Low-Permeability Carbonate Reservoirs in the Paleozoic Under Sulige Gas Field – A Case Study of the Combined Mawu 1 +2 Reservoir in Majiagou Formation of TX Block." In Springer Series in Geomechanics and Geoengineering, 51–63. Singapore: Springer Singapore, 2020. http://dx.doi.org/10.1007/978-981-15-2485-1_6.

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"Gas-Condensate Reservoirs." In Rules of Thumb for Petroleum Engineers, 365–66. Hoboken, NJ, USA: John Wiley & Sons, Inc., 2017. http://dx.doi.org/10.1002/9781119403647.ch165.

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Conference papers on the topic "Gas condensate reservoirs – Permeability"

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Pope, G. A., W. Wu, G. Narayanaswamy, M. Delshad, M. Sharma, and P. Wang. "Modeling Relative Permeability Effects in Gas-Condensate Reservoirs." In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 1998. http://dx.doi.org/10.2118/49266-ms.

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Nasieef, Abdulelah, Mahmoud Jamiolahmady, Hosein Doryanidaryuni, Alejandro Restrepo, Alonso Ocampo, Toushar Chakrabarty, and Ifeanyi Seteyeobot. "Condensate Recovery from Tight Gas-Condensate Reservoirs using a new Method Based on a Gas-Based Chemical." In SPE Annual Technical Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/206080-ms.

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Abstract Recovery from gas condensate reservoirs, when the pressure is below dew point pressure (Pdew), is adversely affected by the accumulation of condensate in the near wellbore region. The mitigation of the near-well bore condensate banking is the main purpose of any enhanced recovery method implemented in gas condensate reservoirs. In this work, a new method was tested to improve condensate recovery by using a chemical that was delivered using hydrocarbon gas as a carrier into a very low permeability and very low porosity reservoir rock. Chemicals are typically injected using liquid carrier solvents. The use of hydrocarbon gas as the carrier provides a remedy to mitigate condensate banking in very low permeability cores by minimizing complications associated with low injectivity and back flow clean-up process requirements of an injected liquid. The chemical potential was evaluated by recording production data from unsteady-state coreflood experiments. The injection of the chemical with equilibrated gas resulted in condensate saturation to decrease from 19.6% to 6.5%. This decrease was not instantaneous and took some time to occur indicating that the chemical needs time to interact with the resident fluid and rock. The benefit of the method, at the field scale, was also estimated by performing single-well numerical simulations that use relative permeability (kr) data which history matched the measured coreflood production data. The results of these preliminary simulations also showed improved recovery of gas and condensate compared to pure depletion, without chemical, by around 40% for the cases considered.
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Kabir, C. S., and J. L. Landa. "Interpreting Transient Tests in High-Permeability, Gas-Condensate Reservoirs." In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 2004. http://dx.doi.org/10.2118/89752-ms.

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Al-Honi, Mohamed, and Abdulrazag Y. Zekri. "Determination of Recovery and Relative Permeability for Gas Condensate Reservoirs." In Abu Dhabi International Conference and Exhibition. Society of Petroleum Engineers, 2004. http://dx.doi.org/10.2118/88797-ms.

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T. Potsch, K., W. Liebl, and P. Bedrikovetsky. "*Depletion of Gas-Condensate Low Permeability Reservoirs (Höflein Field, Vienna Basin)." In IOR 1995 - 8th European Symposium on Improved Oil Recovery. European Association of Geoscientists & Engineers, 1995. http://dx.doi.org/10.3997/2214-4609.201406974.

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Tani, Kengo, Tatsuya Yamada, and Shuichiro Ikeda. "Application of Velocity-Dependent Relative Permeability for Modelling Gas-Condensate Reservoirs: Field Example." In SPE Asia Pacific Oil & Gas Conference and Exhibition. Society of Petroleum Engineers, 2014. http://dx.doi.org/10.2118/171434-ms.

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Chen, H. L., S. D. Wilson, and T. G. Monger-McClure. "Determination of Relative Permeability and Recovery for North Sea Gas Condensate Reservoirs." In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 1995. http://dx.doi.org/10.2118/30769-ms.

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Al Abdulwahab, Ibrahim, Mahmoud Jamiolahmady, and Tim Whittle. "Calculation of Relative Permeability Using Well Test Data in Gas-Condensate Reservoirs." In SPE Europec featured at 80th EAGE Conference and Exhibition. Society of Petroleum Engineers, 2018. http://dx.doi.org/10.2118/190878-ms.

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Giraldo, Luis A., Her-Yuan Chen, and Lawrence W. Teufel. "Field Case Study of Geomechanical Impact of Pressure Depletion in the Low-Permeability Cupiagua Gas-Condensate Reservoir." In SPE Rocky Mountain Regional/Low-Permeability Reservoirs Symposium and Exhibition. Society of Petroleum Engineers, 2000. http://dx.doi.org/10.2118/60297-ms.

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El Hajj, Hicham, Uchenna Odi, and Anuj Gupta. "Study of Use of Supercritical CO2 to Enhance Gas Recovery and its Interaction With Carbonate Reservoirs." In ASME 2013 32nd International Conference on Ocean, Offshore and Arctic Engineering. American Society of Mechanical Engineers, 2013. http://dx.doi.org/10.1115/omae2013-11253.

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It is well known that with continued production from wet gas reservoirs, the reservoir pressure eventually falls below the dew point pressure leading to condensation and loss of gas productivity in the reservoir. The concept of simultaneously injecting CO2 in a gas reservoir for long term storage while at the same time accelerating production of the natural gas is intriguing and promising. CO2 may also interact with carbonate matrix by changing porosity and permeability of the host rock; this is true for reservoirs that are found in the Gulf Region. To maintain field gas production targets, operators routinely set the bottom hole pressure below the dew point pressure which results in condensate blockage. Injecting CO2 can delay the onset of condensate blockage by reducing the dew point pressure of the condensate blockage zone. The approach illustrated, utilizes CO2 to delay the onset of condensate blockage. Factors such as improved effusion were analyzed to justify the use of CO2 for wellbore condensate removal and enhanced gas recovery (EGR). Experimental verification of a new method of determining dew point pressures for wet gas fluids is presented in this work and compared to simulation results. Core floods experiments with carbon dioxide were conducted in a core sample analogue to carbonate at reservoir conditions in order to study the interaction between CO2 and carbonate reservoir. CO2 sequestration in carbonate formation was evaluated by XRF and AFM. Experimental and simulation results show increases in productivity index after CO2 injection. Increases in productivity index were caused by CO2 evaporating the condensate blockage. Condensate vaporization was caused by CO2 reducing the dew point pressure of the condensate. Carbonate aging in presence of CO2 shows two mechanism of CO2 trapping which are dissolution and mineralization.
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Reports on the topic "Gas condensate reservoirs – Permeability"

1

Sheng, James, Lei Li, Yang Yu, Xingbang Meng, Sharanya Sharma, Siyuan Huang, Ziqi Shen, et al. Maximize Liquid Oil Production from Shale Oil and Gas Condensate Reservoirs by Cyclic Gas Injection. Office of Scientific and Technical Information (OSTI), November 2017. http://dx.doi.org/10.2172/1427584.

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Mark E. Willis, Daniel R. Burns, and M. Nafi Toksoz. Natural and Induced Fracture Diagnostics from 4-D VSP Low Permeability Gas Reservoirs. Office of Scientific and Technical Information (OSTI), September 2008. http://dx.doi.org/10.2172/963893.

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Lorenz, J. C., N. R. Warpinski, and L. W. Teufel. Geotechnology for low permeability gas reservoirs; [Progress report], April 1, 1992--September 30, 1993. Office of Scientific and Technical Information (OSTI), November 1993. http://dx.doi.org/10.2172/140175.

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Fred Sabins. Increasing Production from Low-Permeability Gas Reservoirs by Optimizing Zone Isolation for Successful Stimulation Treatments. Office of Scientific and Technical Information (OSTI), March 2005. http://dx.doi.org/10.2172/928210.

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Fouch, T. D., J. W. Schmoker, L. E. Boone, C. J. Wandrey, R. A. Crovelli, and W. C. Butler. Nonassociated gas resources in low-permeability sandstone reservoirs, lower tertiary Wasatch Formation, and upper Cretaceous Mesaverde Group, Uinta Basin, Utah. Office of Scientific and Technical Information (OSTI), August 1994. http://dx.doi.org/10.2172/78565.

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