Production Pressure-Drawdown Management for Fractured Horizontal Shale Gas Wells

Fig. 1—Average apparent matrix-permeability variations showing effects of different mechanisms/models.

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The primary objective of this study is to address all known causes of productivity declines in unconventional shale gas formations with horizontal multifractured wells and to develop a fully coupled geomechanical/flow simulation model to simulate these production conditions. The model mimics the effect of depletion-induced in-situ stress variations on productivity by taking into account several phenomena, such as stress-dependent matrix and natural-fracture permeability and reduction in fracture conductivity because of fracture-face creep and proppant crushing, deformation, and embedment.

Model Formulation

Reservoir Matrix. The gas-storage mechanism in a shale gas reservoir is conceptually different from that of a conventional reservoir. Natural gas is adsorbed on the organic matter present in shales and, in some cases, on certain clay minerals. This adsorbed-gas layer further constricts the area for flow through the pore structure, thus reducing the effective pore radius. As the pressure in the pores reduces, gas is desorbed and the effective pore radius increases, resulting in an increase in the apparent matrix permeability. It has been suggested that desorption of methane might be partially responsible for the relatively long and flat production tails that have been observed in some shale reservoirs. 

Fig. 1 above shows the effects of different mechanisms on permeability evolution. Clearly, shale gas long-term performance forecasting will be affected severely if these effects are not properly considered.

Hydraulic Fractures. Hydraulic fractures are generally kept open and conductive by proppant. After exposure to confining stress for a long period of time, proppant can become deformed, causing degradation of its mechanical and physical properties. This leads to reductions in fracture width and fracture-pack permeability because of intermixing and plugging. 

Additionally, the interaction between the proppant and fracture surfaces under the same confining stress can result in embedment, decreasing the fracture aperture and impairing conductivity.

The fracture conductivity can vary because of changes in the fracture permeability or changes in the fracture width. This study models changes in both of these parameters and develops an analytical solution for fracture-conductivity variations as a function of in-situ effective stress.

Proppant Crushing—Modeling Changes in Proppant-Pack Permeability. Data describing stress-dependent evolution in proppant-pack conductivity are among the more common and easy-to-find data in the technical literature.

Although recent procedures have enabled users to evaluate and compare proppant characteristics under specifically described test conditions for use in hydraulic fracturing, their limitation resides in the necessary conversion to infer the values of proppant-pack permeability that are upscaled into discrete grid models that constitute the input for numerical reservoir simulators. Even within the most advanced autogridding algorithms used to generate the unstructured grid for the complex fracture patterns predicted by the most advanced complex fracture models, local grid refinement rarely determines cells with characteristic dimensions less than 1 ft, whereas reported fracture widths in such unconventional reservoirs are on the order of millimeters.

The newly developed integrated reservoir simulator presented in this paper accounts directly for crushing-induced evolution of proppant-pack permeability.

Proppant Embedment and Deformation and Fracture-Face Creep—Modeling Changes in Fracture Width. Proppant embedment has been defined as a stress-driven plastic indentation and subsidence of the proppant into the softer fracture walls, decreasing the fracture aperture and impairing conductivity.

The total net reduction in fracture width is given as the summation of the proppant embedment, proppant deformation, and the time-dependent creep deformation.

A hydraulic-fracture-conductivity multiplier, defined as a function of the fracture conductivity at any confining stress and the unaltered fracture conductivity, can be introduced into analytical models. This hydraulic-fracture-conductivity multiplier is conveniently used in the integrated reservoir simulator presented in this paper to capture pressure-dependent changes concurrently in the proppant-pack permeability and in the proppant-pack width during the production life of shale gas wells. 

Natural Fractures. Natural fractures are the principal source of flow capacity in many reservoirs. Changes in fracture flow capacity and conductivity are expected to have a significant effect on reservoir performance.

One of the major tenets in shale gas stimulation is the beneficial activation of the contacted natural-fracture network with fracturing fluid, caused by tensile or shear failure. Such poorly sealed natural fractures are generally reported to interact heavily with the hydraulic fractures during the injection treatments, serving as preferential paths for the growth of complex fracture networks.

However, these natural fractures are poorly propped or even unpropped because of the difficulty in “turning the corners” encountered by the proppant transported by fracturing fluids. Therefore, the activated natural-fracture-network conductivity is susceptible to severe pressure-dependent conductivity impairment during depletion, and this must be taken into consideration in an integrated reservoir simulator. 

Model Setup

This study addresses all supported known pressure-dependent phenomena that have an effect on the productivity decline of shale gas wells and incorporates them into an integrated reservoir simulator. All the derived coupled equations are solved numerically. The input parameters used for the presented analysis include reservoir conditions, drainage geometry, hydraulic-fracture conductivity, real-gas gas-adsorption parameters, and the randomly generated discrete fracture network.

This simulator makes use of a finite-element-analysis scheme based on the Newton-Raphson method, which requires evaluating a Jacobian matrix starting from initial-guess values to approximate the solution throughout successive iterations. All the variables in the system are updated at the end of each time increment and entered as initial values at the start of the next time increment.

To make a consistent assessment on how the non-Darcy flow, adsorption layer, and geomechanical factors affect the shale-matrix permeability during production, the reference input values for porosity, intrinsic permeability, and pore radius for all models are considered at standard conditions under laboratory conditions, whereas their corresponding values at initial reservoir conditions are calculated on the basis of in-situ reservoir-pressure/temperature and stress conditions.

The propped-hydraulic-fracture sections are modeled using the sieve-size analysis of a 20/40 natural sandpack exposed to different confining-stress conditions.

Results and Discussion

Effect of Pressure-Dependent Phenomena on Long-Term Well Performance. To demonstrate the pressure-dependent changes in matrix permeability and hydraulic- and natural-fracture conductivity, two 10-year production simulations were compared with and without the incorporation of the modeled pressure-dependent phenomena. A difference of almost 30% was observed in cumulative production after the simulated 10 years, reflecting the deleterious effect of the depletion-related increase of the effective stress on matrix and fracture flow potential.

Effect of Flowing Bottomhole Pressure on Long-Term Well Performance. The model is run for two 10-year production simulations under two drawdown scenarios. The more aggressive drawdown strategy performs better during the early life of the well, but, eventually, the production rate declines much faster compared with the milder drawdown strategy. Consequently, the cumulative-production curves cross (after approximately 3.5 years). 

This constitutes relevant evidence of the concept of pressure-drawdown management and validates the field-observed trends that the penalty of lower initial production rates in unconventional shale gas reservoirs can yield substantially higher ultimate recovery. 

In an attempt to find an optimal drawdown strategy that minimizes the pressure-dependent effects and maximizes the cumulative recovery for the synthetic case presented, the authors investigated a set of drawdown strategies. 

The results suggest that the optimal long-term drawdown strategy should be determined above an economic optimization. Nevertheless, it is important to emphasize the value of this integrated reservoir simulator, which enables execution of intensive parametric studies aimed at determining whether the rapid production declines can be minimized with proper drawdown management to improve the ultimate cumulative recovery.

Conclusion and Recommendations

The primary objectives of this paper were to address all the known causes of abnormal productivity decline in unconventional shale gas formations and to develop a fully coupled geomechanical/flow simulation model to predict and study these production conditions.

For this purpose, an integrated reservoir simulator was developed that accounted for various pressure-dependent phenomena. The effects of non-Darcy flow, reservoir compaction, and adsorption-layer factors on reservoir-matrix-permeability evolution with depletion were incorporated. The effects on hydraulic-fracture conductivity of proppant crushing, proppant deformation, and proppant embedment with changes in in-situ stress were investigated and modeled. Last, variations in natural-fracture permeability with depletion-induced changes in in-situ stress were considered. Numerical solutions for simplified hydraulic-fracture planar geometries were then obtained using a finite-element method.

An opportunity to improve the presented model might reside in the incorporation of early-time flowback drawdown management. This would involve feeding the integrated reservoir simulator with flowing-bottomhole-pressure schedules corresponding to the critical drawdown as a function of production time and rate.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 181365, “Production Pressure-Drawdown Management for Fractured Horizontal Wells in Shale Gas Formations,” by Ankit Mirani, University of Houston; Matteo Marongiu-Porcu, SPE, Schlumberger; HanYi Wang, SPE, The University of Texas at Austin; and Philippe Enkababian, SPE, Schlumberger, prepared for the 2016 SPE Annual Technical Conference and Exhibition, Dubai, 26–28 September. The paper has not been peer reviewed.

Production Pressure-Drawdown Management for Fractured Horizontal Shale Gas Wells

01 November 2017

Volume: 69 | Issue: 11


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