ATCE: Unconventional Oil & Gas Abstracts

SPE Technical Papers: Unconventional Oil & Gas

Technical papers, referencing CMG software, presented at the 2016 SPE Annual Technical Conference & Exhibition, Dubai UAE

How to Correct the Petro-Physical Properties for Simulating Shale Gas Production using Current Commercial Simulators
Paper: SPE181321

Numerical simulation is important to understand and predict the development of oil and gas reservoirs. Existing commercial simulators, such as CMG, ECLIPSE and VIP, have been widely used in the past several decades for their robust performance in computing and scaling. In these reservoir simulators, the fluid flow models are based on Darcy's law or its extended form; the volume of the adsorbed phase or component is overlooked as well. While this is acceptable for conventional oil/gas reservoirs or chemical flooding reservoirs, the gas flow regimes such as slippage flow, transition flow, and molecular-free flow significantly is deviated from Darcy flow for shale gas reservoirs. Besides, a large portion of the gas is stored in the pore in the form of adsorbed gas. If the volume of the adsorbed gas is still overlooked, the volume of free gas and original gas in place (OGIP) will be seriously overestimated. For the above reasons, it is commonly thought that existing commercial simulators could not be ideally used to simulate the development of shale gas reservoirs. Hence, it is desirable to attain a feasible approach to correct the petro-physical properties of shale gas effectively within the commercial simulators, in order that one can use them to accurately simulate the development of shale gas reservoirs. In this paper, we first derived the correction formulas for the bulk porosity, free gas saturation, and connate water saturation used for correcting the disregarded volume of adsorbed gas in commercial simulators. Then, we derived the models of permeability and porosity multipliers in matrix considering gas adsorption/desorption, geomechanics, non-Darcy flow regimes, and diffusion of adsorbed layer. Finally, the above models were used to attain the corrected petro-physical properties for simulating gas production based on the practical properties of shale gas reservoirs using commercial simulators.

© Copyright 2016. Society of Petroleum Engineers
Presented at the SPE Annual Technical Conference & Exhibition, 26 – 28 September 2016, Dubai UAE

Upscaling of Pore Connectivity Results from Lab-Scale to Well-Scale for Barnett and Haynseville Shale Plays
Paper: SPE181433

This study evaluates impacts of connectivity and pore distribution on gas transport through matrix of Barnett and Haynesville shale plays. Gas molecules are stored as compressed phase in pore space or as a desorbed phase on the surface of the pores. At the early stage of production, gas decompression within networks of induced/natural fractures "immediately" connected to the production stream is the dominant production mechanism; however, after some time dispersive flux is triggered in response to the pressure drop realized at matrix-fracture interface. In this study, we compare the connectivity between two shale samples at lab-scale and verify the results with the production performance for few selected wells.

Using MICP porosity values measured at the laboratory for different sample size, we evaluate pore connectivity in Barnett and Haynesville shale plays in lab-scale. Next, we develop a new analytical solution to study the contribution of dispersive flux. In this model, we use a new set of boundary conditions as opposed to traditional Dirichlet and Neumann types of boundary conditions. Our transient flow model for gas transport through shale matrix accounts for the volume of connected pores and their abundance in the shale matrix. To verify the pore connectivity in large-scale, we choose few wells from gas producing parts of Barnett and Haynesville shale plays. We used conventional production data analysis (rate transient analysis) to identify the matrix contribution. Using the new analytical model, we compared the matrix contribution of Barnett and Haynesville shale plays for those selected wells.

We found an excellent match between connectivity results from MICP data and well production performance. Results indicate that higher connectivity, the greater the gas flux, everything else being equal. For that reason, matrix contribution to total recovery of Barnett wells are considerably higher than those of Haynesville. Results indicate that the connectivity of connected pores in the shale matrix has significant effect on the matrix contribution.

© Copyright 2016. Society of Petroleum Engineers
Presented at the SPE Annual Technical Conference & Exhibition, 26 – 28 September 2016, Dubai UAE

Further Discuss the Roles of Soaking Time and Pressure Depletion Rate in Gas Huff-n-Puff Process in Fractured Liquid-Rich Shale Reservoirs
Paper: SPE 181471

Cyclic gas injection (CGI), also known as huff-n-puff process, has been demonstrated as the most effective and promising IOR solution in shale reservoirs. Such process involves many operating parameters that can affect the recovery performance in different degrees. As soaking time and pressure depletion rate (PDR) are the two crucial factors, this study aims to further investigate their roles in the oil recovery process of CGI experimentally and numerically.

A total of ten series of the N2 huff-n-puff tests were performed on oil-saturated Eagle Ford shale plugs in a matrix-fracture system […]. Lab-scale simulation models were built and tuned to history match the experimental data.

The experimental results show that recovery factor (RF) from a single cycle increases with soaking time within a certain range, and a longer time has no effect on improving oil recovery. For 1,000 psi Pin, during the soaking phase, the system pressure declined rapidly at the first 3 hr and then became stabilized. The pressure drop was relatively low (10 psi) in the first cycle compared with the following cycles. It tended to increase with the number of cycles performed, which was caused by the decrease of oil saturation thus more gas can be injected into the core sample. It reveals that a soaking period is necessary to the oil recovery process. On the other hand, increasing the pressure depletion rate can raise the incremental RF from each cycle. The blowout condition showed the highest cumulative RF. The performance of N2 huff-n-puff with 5,000 psi Pin outperforms the case of 1,000 psi, which can increase the ultimate RF with less cycles. The well-tuned simulation models were used to analyze and optimize the CGI recovery process.

© Copyright 2016. Society of Petroleum Engineers
Presented at the SPE Annual Technical Conference & Exhibition, 26 – 28 September 2016, Dubai UAE

Analytical Study of Flowing and In-Situ Compositions in Unconventional Liquid-Rich Gas Plays
Paper: SPE 181567

Liquid-rich gases in unconventional reservoir environments can exhibit complex phase and flow behavior due to gas condensation and re-vaporization and differences in phase mobilities that results in compositional variations inside the system. To date, the analysis of in situ and flowing composition variation in unconventional liquid-rich wells has been largely limited to numerical modeling. This work uses an analytical approach to study the in situ and flowing fluid composition of gas condensate wells producing under infinite-acting linear flow—a commonly observed flow regime in hydraulically-fractured horizontal wells in unconventional formations. We propose a semi-analytical solution to the governing partial differential equations (PDEs) written in terms a compositional fluid formulation. The proposed solution is developed using Boltzmann's transformation and is validated by both analytical development and numerical simulation data. Results corroborate that when hydraulically-fractured horizontal wells are producing against a constant bottomhole pressure (BHP) constraint, the producing wellbore fluid composition remains constant as long as the system remains infinite acting, leading to a constant producing gas-oil ratio (GOR). This constant wellstream composition is shown to be very different from in situ composition, which varies according to pressure and production condition inside the reservoir.

© Copyright 2016. Society of Petroleum Engineers
Presented at the SPE Annual Technical Conference & Exhibition, 26 – 28 September 2016, Dubai UAE

Compositional Rate Transient Analysis in Liquid Rich Shale Reservoirs
Paper: SPE 181699

Conventional rate transient analysis (RTA) is based on the solution of single-phase diffusivity equation, derived from mass balance with an assumption that fluid and rock compressibility are small and constant. The conventional technique also provides accurate practical results for gas and black oil reservoirs in engineering applications because (1) the mass balance is conducted at standard conditions of pressure and temperature, and (2) it is assumed that the gas and oil composition remains the same at standard conditions—thus, the viability of volume balance technique. On the other hand, for reservoirs with highly composition-dependent fluids, the invariance of composition at standard conditions is not accurate. For example, oils produced from liquid-rich shale reservoirs exhibit large variation in produced oil and associated gas composition with production time. In this paper we address these issues and present a compositional model for liquid-rich unconventional reservoirs using an improved compositional volume balance technique. Specifically, we reduce the component flow equations to a single pressure equation using partial molar volumes as weighting factors. This pressure equation is the unique feature of this paper and is used to analyze pressure and rate transient tests (RTA) to determine various flow regimes and reservoir properties in liquid-rich shale reservoirs. […]

Because of the explicit nature of the phase saturation calculations, we introduce a molar mass balance correction term to minimize the material balance errors of the computation. Furthermore, we validated our partial molar volume algorithm against published experimental data of Wu and Ehrlich (1973) and with the CMG GEM compositional simulator. Finally, unsteady state permeability measurements of several unconventional shale reservoirs were performed. These measurements show that tighter core with abundant micro and nano fractures exhibit a more stress dependent matrix permeability characteristics.

An Innovative Approach to Model Two-Phase Flowback of Shale Gas Wells with Complex Fracture Networks
Paper: SPE 181766

Two-phase flow has generally been of more concern in the hydraulic treatment design of shale gas reservoir, especially, during the flowback period. Investigating the gas and water production data is important to evaluate the stimulation effectiveness. We develop a semianalytical model for multi-fractured horizontal wells by incorporating the two-phase flow in both matrix and fracture of the shale-gas wells. We employ the node-analysis approach to discretize the complex fracture networks into a given number of fracture segments, depending on the complexity of fracture system. The two-phase flow is incorporated by iteratively correcting the relative permeability to gas and water phase and capillary pressure for each fracture segment with the fracture depletion. The model is validated by numerical model and field observation. A good match between them was obtained. […]

The improved network fracture conductivity and complexity especially the connections between hydraulic fracture and natural fractures can enhance the gas production and shorten the dewatering time, illustrating that the effective stimulation could facilitate the fractures to clean up more quickly. The gas/water supply from natural fractures and their flow dynamics controlled by two-phase relative permeability effects could be the major reasons for the formation of "V-shape" behavior on the plot of gas/ water ratio vs. cumulative gas production. This work, for the first time, extends the semianalytical model from single-phase flow to two-phase flow in shale gas reservoir with complex fracture networks. The method is simple and gridless, but is capable of capturing the complex fracture system and gas/water transport mechanisms. Also, it provides an efficient technique to evaluate the hydraulic fracture treatment design in multi-fractured horizontal wells for shale gas reservoirs at early production times.

Experimental and Numerical Investigation of Oil Recovery from Bakken Formation by Miscible CO2 Injection
Paper: SPE 184486

Unconventional liquid reservoirs are characterized by small matrix permeability that is several orders of magnitude lower than conventional oil reservoirs. The combination of multi-stage hydraulic fracturing and horizontal drilling has improved the overall profitability of these tight-oil reservoirs by enhancing the wellbore - matrix connectivity. Under primary production, however, the recovery factor remains in the range of only 5% to 10% of original oil in place (OOIP). Considering such a large resource base, even small improvements in productivity could lead to millions of barrels of additional oil. Therefore, the need to develop a viable enhanced oil recovery technique for unconventional oil reservoirs is evident.

This study investigates technical feasibility of carbon dioxide as an enhanced oil recovery agent for tight-oil reservoirs. Above minimum miscibility pressure (MMP), CO2 and oil are miscible leading to reduction in capillary forces and therefore high local displacement efficiency. The miscibility pressure of CO2 is also significantly lower than the pressure required for other gases, which makes CO2 miscible injection attainable under a broad spectrum of reservoir pressures.

[…] To decipher the oil recovery mechanisms in the coreflood experiment, a numerical compositional model was constructed to reproduce the laboratory results. Vaporization of light hydrocarbon components into CO2 is shown as a major recovery mechanism. Other controlling factors include re-pressurization, oil swelling, viscosity and interfacial tension reduction. History matching with the laboratory experiment introduces additional complexities such as rock heterogeneities and presence of a fracture that promotes flow perpendicular to the core length. The above issues need to be addressed to match the displacement process exactly.