Factors controlling prolific gas production from low-permeability sandstone reservoirs: Implications for resource assessment, prospect development, and risk analysis

Shanley, Keith W.; Cluff, Robert M.; Robinson, John W.

doi:10.1306/03250403051

Cited by 354 publications

(213 citation statements)

References 73 publications

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“…The above-zero intersection of the plots in Figure 45 makes them different from the computed relative permeability curves reported in [64]. The latter means that the permeability jail phenomenon [15,57] is pertinent to matrix porosity and is less likely to occur in fractures. Figure 46 shows results of flow simulation with slippage boundary conditions, as described in Section 4.2.…”

Section: Evaluation Of the Permeability Tensor By Subsamplingmentioning

confidence: 87%

“…Thus, v * can be computed for a given v n using Equation (57). The computation of v n+1 is performed in two steps.…”

Section: A Discretization Of the Stokes Equationsmentioning

confidence: 99%

“…Updating velocities at each iteration requires an evaluation of the Laplacian, see Equation (57). The latter can be done by introduction of ghost velocity values at the next-to-boundary faces of the boundary pore voxels.…”

Section: Boundary Conditionsmentioning

confidence: 99%

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Digital Rock Studies of Tight Porous Media

Silin¹

2012

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Abstract. This technical report summarizes some recently developed approaches to studies of rock properties at a pore scale. Digital rock approach is complementary to laboratory and field studies. It can be especially helpful in situations where experimental data are uncertain, or are difficult or impossible to obtain. Digitized binary images of the pore geometries of natural rocks obtained by different imaging techniques are the input data. Computer-generated models of natural rocks can be used instead of images in a case where microtomography data are unavailable, or the resolution of the tools is insufficient to adequately characterize the features of interest. Simulations of creeping viscous flow in pores produce estimates of Darcy permeability. Maximal Inscribed Spheres calculations estimate two-phase fluid distribution in capillary equilibrium. A combination of both produce relative permeability curves. Computer-generated rock models were employed to study two-phase properties of fractured rocks, or tight sands with slit-like pores, too narrow to be characterized with micro-tomography. Various scenarios can simulate different fluid displacement mechanisms, from piston-like drainage to liquid dropout at the dew point.A finite differences discretization of Stokes equation is developed to simulate flow in the pore space of natural rocks. The numerical schemes are capable to handle both no-slip and slippage flows. An upscaling procedure estimates the permeability by subsampling a large data set. Capillary equilibrium and capillary pressure curves are efficiently estimated with the method of maximal inscribed spheres both an arbitrary contact angle. The algorithms can handle gigobytes of data on a desktop workstation. Customized QuickHull algorithms model natural rocks. Capillary pressure curves evaluated from computer-generated images mimic those obtained for microtomography data.

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Section: Evaluation Of the Permeability Tensor By Subsamplingmentioning

confidence: 87%

“…Thus, v * can be computed for a given v n using Equation (57). The computation of v n+1 is performed in two steps.…”

Section: A Discretization Of the Stokes Equationsmentioning

confidence: 99%

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Digital Rock Studies of Tight Porous Media

Silin¹

2012

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“…Due the complex flow in shale gas reservoirs, gas desorption in the matrix, gas diffusion from the matrix to natural fractures, Darcy flow in natural fractures and non-Darcy flow in hydraulic fractures are considered in the simulation. In this study, the water and gas flow in shale matrix and fractures are described with two different sets relative permeability curves based on the previous study (Deghmoum et al, 2001;Shanley et al, 2004), as shown in Fig. 2.…”

Section: Simulation Model Descriptionmentioning

confidence: 99%

Numerical simulation of gas and water flow mechanism in hydraulically fractured shale gas reservoirs

Shen

et al. 2016

Journal of Natural Gas Science and Engineering

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a b s t r a c tThe problem of the fracturing water remaining in hydraulically fractured shale gas reservoirs has become one of the major concerns in terms of gas productivity and operating costs. The fracturing water retention is influenced by reservoir properties and production parameters, such as matrix porosity and permeability, fracture porosity and permeability, Langmuir pressure and volume, diffusion coefficient, shut-in time, drawdowns and injection rate. In this study, a horizontal well with six-stage hydraulicfracturing treatment was constructed to understand the water retention and gas production performance in shale gas reservoirs. Gas diffusion, gas adsorption/desorption and Darcy flow as well as non-Darcy flow were considered in this model. The process of water retention and gas production performance was analyzed, and the effects of reservoir and production properties on this problem were performed. The results show that only 34% of the fracturing water can flow back to the surface, most of which remains in shale formations to interfere with gas production. The increasing of matrix porosity, fracture porosity, Langmuir pressure and drawdowns will reduce water retention while water retention in shale matrix will increase with the increasing of matrix permeability and Langmuir volume, and consequently impact gas production. But the trapped water and gas rate increase with the higher fracture permeability. Furthermore, the diffusion coefficient, shut-in time and injection rate do not have a significant effect on water retention and gas productivity. These results can provide insights into a better understanding of gas and water flow in the shale gas reservoirs and the effects of reservoir and production parameters on water retention and gas production.

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“…It has been deposited in a rapidly subsiding foreland setting, has rather tight reservoirs Shanley et al (2004).…”

Section: From Pollastro Et Al (2003)mentioning

confidence: 99%

Geoperspective Oil and Gas in the Netherlands – Is there a future?

Herber

Jager

2010

Netherlands Journal of Geosciences

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The impact of oil and, in particular, gas fields discovered in the Dutch subsurface has been very significant. However, 50 years after the discovery of the giant Groningen gas field the Netherlands has become very mature for exploration of oil and gas, and the gas volume left to be discovered in conventional traps is insignificant compared to what has been found already. The total portfolio of conventional prospects held by the industry contains several 100s of billions of cubic metres (bcm), as reported by the Ministry of Economic Affairs, but many of these prospects are unattractive to drill because of their small size or other geologically unfavourable aspects. Hence, for planning purposes of future national gas production the risk should be taken into account that the size of the conventional portfolio is overestimated. The major E&P companies have reduced their exploration efforts and the number of wells drilled as well as the size and total volume of discovered gas reserves has seen a steady decline over the last 10 years. Some surprises may still be in store and can occasionally add a welcome addition of gas. But the follow-up potential of new play and trapping concepts has been disappointing for many years now, and it is concluded that this is unlikely to be different in the future.Remaining conventional discoveries will mainly be in small near-field targets that as a result of technological advances made in the last few decades can be drilled with high confidence, despite their small volumes.This leaves the so-called unconventional gas (UG) resources for a real and significant increase in the exploration potential of the Netherlands.UG resources occur outside conventional structural or stratigraphic traps in tight (low permeability) rocks and are of regional or sub-regional extent, without well-defined hydrocarbon-water contacts. The potential for Basin Centred Gas, Shale Gas and Coal Bed Methane is reviewed. As, according to present-day technology, development of UG requires very dense drilling at low costs with well spacing of a few 100s of metres, only the onshore potential can be commercial, even in the longer term.Recent geological uplift is a characteristic for all North American commercial UG developments. Uplift helps bringing the resources close to the surface and facilitates development of fractures, which are essential for achieving commercial flow rates. This significantly reduces the area where commercial UG resources may occur in the Netherlands. In addition, sweet spots, where commercial flow rates and ultimate recovery per well can be achieved, represent only a fraction of the total 'play area'. The UG plays in the Dutch subsurface remain to be proven, and there is still a significant technical risk associated with these plays, on top of the commercial risk. Therefore, despite potentially enormous in-place gas volumes in these unconventional plays, recoverable volumes are much less. If UG resources can be proven and are commercially developable, their cumulative volume potential ...

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Factors controlling prolific gas production from low-permeability sandstone reservoirs: Implications for resource assessment, prospect development, and risk analysis

Cited by 354 publications

References 73 publications

Digital Rock Studies of Tight Porous Media

Digital Rock Studies of Tight Porous Media

Numerical simulation of gas and water flow mechanism in hydraulically fractured shale gas reservoirs

Geoperspective Oil and Gas in the Netherlands – Is there a future?

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