(296b) Phase Transition, Fracture Parameters, Relative Permeability, and Capillary Pressure Effects on Condensate Production in Fractured Reservoirs

Problem Statement

Since the commercial production of natural gas began in the United States in 1821 [1], petroleum engineers have been trying to improve productivity by better understanding shale formations, especially since the 1970s.  Because of extremely low matrix permeability in shale reservoirs, profitable commercial production currently involves hydraulic fracture networks. Understanding the effect of hydraulic fracturing parameters is therefore beneficial to operators in terms of both fracture design optimization and production enhancement.

Recent fast progress in hydraulic fracturing technology has brought much attention to gas reservoirs, where condensate forming and extraction become problematic. Liquid flow meets significantly more resistance compared to gas in shale fractures filled with proppants and in wellbores. Reservoir productivity also becomes more complex by including condensate phase relative permeability and capillary pressure effects. At the same time, many widely used analytical production decline models work poorly in cases of liquid-rich formations. To perform fracture design optimization and sensitivity analysis, an approach is required that is much less time consuming than detailed reservoir simulation while being sufficiently accurate to capture the physics of the process. To address situations involving gas condensates, it must rely on the numerical simulation of multiphase flow in the interconnected system of the wellbore and fractures within a reservoir, represented by productivity.

An effective numerical model reported in an accompanying paper [2] was developed to predict production decline in a fracture-stimulated liquid-rich gas field. It allows for easy investigation of the impact of gas-condensate system phase transition, fracture parameters, relative permeabilities, and capillary pressures on the well productivity. The model solves the transient pressure depletion process with focus on the effects of condensate banking and condensate-phase-related permeability and capillary pressure changes.

Method

A detailed description of the model calculating transient pressure depletion in the stimulated volume between and around parallel-plane fractures perpendicular to a horizontal wellbore is provided in [2].

The flows of gas, condensate (oil), and water phases are simulated in the model. To describe the gas-oil phase transition in the system, the Extended Black Oil model is used. The gas and oil components can transfer between the hydrocarbon phases according to pressure-volume-temperature (PVT) rules, while the water component remains in the aqueous phase. Calculation of transient mass transport and phase distribution is coupled with pressure field distribution.

Relative permeabilities and capillary pressures are accounted for each phase as functions of phase saturations. With the oil phase having much higher viscosity and resistance while flowing within a tight formation, its banking (blocking) effect on the production rate was simulated and studied in detail.

A sensitivity screening of fracture parameters, including fracture length, fracture spacing, and fracture conductivity was conducted to facilitate fracture design optimization and production enhancement, with the primary focus on production rate and net present value (NPV).

Results

An effective production model of a fractured reservoir was developed for this study. In this paper, the oil condensation process is shown, and the condensation banking effect on the production rate decline is identified and analyzed. The relative permeability and capillary pressure effect of the condensate phase on production is also discussed. Sensitivity analysis of reservoir productivity related to fracturing parameters, with respect to changes of fracture length, fracture spacing, and fracture conductivity, was performed.

Conclusions

To simulate the condensate production decline in fracture-stimulated condensate reservoirs, an effective numerical model was developed. It accounts for a variety of physical effects influencing liquid-rich reservoir productivity, including gas-condensate phase transition, relative permeabilities, and phase capillary pressures. The simplicity and simulation speed of the model makes it possible to incorporate it into a wellbore simulator to model the transient pressure drop and phase transitions in the near-wellbore region, reducing the necessity for more complex reservoir simulations. It also opens up opportunities for applications related to fast fracture and well design optimization and net profit estimates.

References

[1] J.B. Curtis, 2002, Fractured Shale-Gas Systems. AAPG Bulletin, v. 86, No. 11, P1921-1938.

[2] A. Filippov, X. Jia, and V. Khoriakov, 2015, Effective Modeling of Production Decline in Fractured Condensate Reservoirs. Presented at the AIChE Annual Meeting, Salt Lake City, Utah, 8–13 November.