Condensate blockage study in gas condensate reservoir

Rahimzadeh, Alireza; Bazargan, Mohammad; Darvishi, Rouhollah; Mohammadi, Amir H.

doi:10.1016/j.jngse.2016.05.048

Cited by 47 publications

(19 citation statements)

References 9 publications

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“…where d m = −d J /du and ω is step size multiplier. Given search direction, d, the standard line search algorithm is to determine some step size multiplier, ω, which maximizes the objective function value Passino (2005):…”

Section: Gradient Optimization Methodsmentioning

confidence: 99%

Utilization of nature-inspired algorithms for gas condensate reservoir optimization

et al. 2018

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

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Section: Gradient Optimization Methodsmentioning

confidence: 99%

Utilization of nature-inspired algorithms for gas condensate reservoir optimization

et al. 2018

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“…Fluid flow near well bore region in depleted gas condensate reservoir below the dew point is in the form of two phases "gas and condensate (light oil)" (Fevang and Whitson, 1996;Mott, 2003;Qasem et al, 2014;Rahimzadeh et al, 2016;Thomas and Bennion, 2009;Whitson et al, 1999). Furthermore, gas condensate PVT properties are different from natural gas and crude oil due to the compositional changes that occurs below the dew point (Elsharkawy, 2006;Rayes et al, 1992;Whitson et al, 2000;Yang et al, 2007).…”

Section: Accepted Manuscriptmentioning

confidence: 99%

“…Transient pressure test data from high temperature heavy gas condensate well was obtained from Economides et al, (1989) and utilized to generate the IPR curves. New IPRs covers effect of condensate blockage near wellbore region as an important factor in reducing well productivity (Behmanesh et al, 2017;Chen et al, 1995;Fevang and Whitson, 1996;Gondouin et al, 1967;Rahimzadeh et al, 2016).…”

Section: Accepted Manuscriptmentioning

confidence: 99%

Development of inflow performance model in high temperature gas-condensate reservoirs

Faraji¹,

Ugwu²,

Nabhani³

et al. 2019

Journal of Petroleum Science and Engineering

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Inflow Performance Relationships (IPRs) are important element for reservoir engineers in the design of new wells and also for monitoring and optimizing existing wells. IPRs are used to determine optimum production of gas rate and condensate rate in a well for any specified value of average reservoir pressure and predict the performance. Jokhio and Tiab proposed a simple method of establishing IPR for gas condensate wells. The method uses transient pressure test data to estimate effective permeability as a function of pressure. Effective permeability data used to convert production bottomhole flow pressure into pseudopressure to establish well performance. Despite the effectiveness of the method, single phase correlations were used in PVT calculations of each phase, which over simplified the fluid flow in gas condensate wells. Single phase dry gas equations do not reflect the multiphase flow behaviour of gas condensate wells below the dew point. Due to this limitation Jokhio and Tiab method modified by this study and new analytical IPRs for gas condensate well proposed. The major improvement of the above method is incorporating new viscosity correlation developed by this study and using two-phase compressibility factor as key parameters for predicting gas condensate inflow performance. Therefore, the main contribution of this study is development of viscosity correlation which is a critical issue in predicting gas condensate inflow performance both above and below the dew point. Optimization techniques and nonlinear regression used to develop a new viscosity correlation for high temperature heavy gas condensate reservoirs under depletion. The application of the new model is illustrated with field example for current IPR curves. Compositional simulation study of the well performed in PIPSIM simulator. The proposal approach provides reasonable estimates of simulator input reservoir properties (e.g. IPRs). Accuracy of the new method compared with compositional simulation study. The proposed method presents average absolute relative deviation (AARD) of 5.8% for gas IPR and 7.5% for condensate IPR compare to compositional simulation results. New method provides a tool for quick estimation of gas condensate wells without need of relative permeability curves and expensive and time consuming compositional simulation.

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“…By lowering the pressure below the dew point, formed liquids may not be produced and the relative permeability of the gas, especially around the well, maybe reduced (Hinchman and Barree 1985;Lal 2003;Imo-Jack 2010;Najafi-Marghmaleki et al 2016). Pressure drop due to condensate clogging in these areas can increase up to 200% of pressure drop in tubing (Rahimzadeh et al 2016). The low absolute permeability and condensate wettability of the rock cause the liquid phase to trap and adhere to the reservoir rock in the area.…”

Section: Introductionmentioning

confidence: 99%

Effect of a synthesized anionic fluorinated surfactant on wettability alteration for chemical treatment of near-wellbore zone in carbonate gas condensate reservoirs

2020

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The pressure drop during production in the near-wellbore zone of gas condensate reservoirs causes condensate formation in this area. Condensate blockage in this area causes an additional pressure drop that weakens the effective parameters of production, such as permeability. Reservoir rock wettability alteration to gas-wet through chemical treatment is one of the solutions to produce these condensates and eliminate condensate blockage in the area. In this study, an anionic fluorinated surfactant was synthesized and used for chemical treatment and carbonate rock wettability alteration. The synthesized surfactant was characterized by Fourier transform infrared spectroscopy and thermogravimetric analysis. Then, using surface tension tests, its critical micelle concentration (CMC) was determined. Contact angle experiments on chemically treated sections with surfactant solutions and spontaneous imbibition were performed to investigate the wettability alteration. Surfactant adsorption on porous media was calculated using flooding. Finally, the surfactant foamability was investigated using a Ross–Miles foam generator. According to the results, the synthesized surfactant has suitable thermal stability for use in gas condensate reservoirs. A CMC of 3500 ppm was obtained for the surfactant based on the surface tension experiments. Contact angle experiments show the ability of the surfactant to chemical treatment and wettability alteration of carbonate rocks to gas-wet so that at the constant concentration of CMC and at 373 K, the contact angles at treatment times of 30, 60, 120 and 240 min were obtained 87.94°, 93.50°, 99.79° and 106.03°, respectively. However, this ability varies at different surfactant concentrations and temperatures. The foamability test also shows the suitable stability of the foam generated by the surfactant, and a foam half-life time of 13 min was obtained for the surfactant at CMC.

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Condensate blockage study in gas condensate reservoir

Cited by 47 publications

References 9 publications

Utilization of nature-inspired algorithms for gas condensate reservoir optimization

Utilization of nature-inspired algorithms for gas condensate reservoir optimization

Development of inflow performance model in high temperature gas-condensate reservoirs

Effect of a synthesized anionic fluorinated surfactant on wettability alteration for chemical treatment of near-wellbore zone in carbonate gas condensate reservoirs

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