Pore-scale mechanisms of gas flow in tight sand reservoirs

Silin, Dmitriy; Kneafsey, Timothy J.; Ajo‐Franklin, Jonathan; Nico, Peter

doi:10.2172/1001046

Cited by 3 publications

(2 citation statements)

References 66 publications

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“…A serious problem for gas production from tight sandstone reservoirs is blockage of gas flow, by either water or gas condensate. − Removing the blockage would both increase gas recovery and create greater space for CO 2 storage. As a secondary effect, the expelled gas condensate can be sold at higher prices than natural gas.…”

Section: Introductionmentioning

confidence: 99%

A Study for Using CO₂ To Enhance Natural Gas Recovery from Tight Reservoirs

et al. 2019

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A comprehensive study is presented on the interfacial behavior of all participating phases in a scenario of using carbon dioxide (CO2) to enhance the recovery of natural gas in tight sandstone reservoirs. Natural gas condensate is contacted with CO2 at an increasing pressure to determine the minimum miscibility pressure (MMP) by the vanishing interfacial tension method. Close to the MMP at a higher temperature, some compounds of the mixture are extracted, leaving a heavy oil fraction that remains immiscible. As the second reservoir liquid, formation water is extracted by CO2 from a tight sandstone sample and subsequently applied as a sessile drop for assessment of the wetting behavior inside the reservoir in the presence of injected CO2. The contact angle has been observed to increase with increasing CO2 pressure. It has been further observed that the water contact angle on a gas shale increased with increasing CO2 pressure more rapidly. The results suggest that CO2 could clear the gas flow path blocked by water and gas condensate. As a consequence, the recovery of natural gas would increase. This could also create greater potential for CO2 storage in gas-depleted reservoirs.

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Section: Introductionmentioning

confidence: 99%

A Study for Using CO₂ To Enhance Natural Gas Recovery from Tight Reservoirs

et al. 2019

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“…For tight sandstone, where water permeability is less than the Klinkenberg permeability, Eq. 7 is used to estimate the water permeability (K w ) from Klinkenberg permeability (K l < 1 mD) [23].…”

Section: Model Validationmentioning

confidence: 99%

Experimental study on the permeability jail range of tight gas reservoirs through the gas–water relative permeability curve

et al. 2022

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The permeability jail refers to a specific water saturation range in a tight gas reservoir, where almost no gas or water phase can flow effectively. In the process of drilling and fracturing, water saturation rises and falls into the permeability jail. To reduce or avoid falling into the permeability jail in the recovery process, a method for measuring gas–water relative permeability of tight sandstone is established here that considers salt sensitivity, gas slippage effect, stress sensitivity, and high bound water saturation. Then, the permeability jail range was determined to provide guidance and suggestions for field application. Considering a typical tight sandstone as an example, the proposed method was used to expand the measurement range of gas–water relative permeability and observe the permeability jail range, laying an experimental foundation for accurately determining the permeability jail range in a given formation. The Byrnes model can preliminarily predict the permeability jail range with accurate bound water saturation and residual gas saturation. When the permeability jail phenomenon occurs in the core, the larger the permeability is, the smaller the permeability jail range will be; and the larger the porosity is, the smaller the permeability jail range will be. When the permeability jail phenomenon occurs in the tight sandstone reservoir, the damage to the reservoir due to external fluid and solid phased particles should be strictly controlled. The damage is stronger, the permeability and porosity decline, and the permeability jail range is wider. Other gases or solvents can be used as fracturing fluids to minimize formation damage.

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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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Pore-scale mechanisms of gas flow in tight sand reservoirs

Cited by 3 publications

References 66 publications

A Study for Using CO₂ To Enhance Natural Gas Recovery from Tight Reservoirs

A Study for Using CO₂ To Enhance Natural Gas Recovery from Tight Reservoirs

Experimental study on the permeability jail range of tight gas reservoirs through the gas–water relative permeability curve

Digital Rock Studies of Tight Porous Media

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Pore-scale mechanisms of gas flow in tight sand reservoirs

Cited by 3 publications

References 66 publications

A Study for Using CO2 To Enhance Natural Gas Recovery from Tight Reservoirs

A Study for Using CO2 To Enhance Natural Gas Recovery from Tight Reservoirs

Experimental study on the permeability jail range of tight gas reservoirs through the gas–water relative permeability curve

Digital Rock Studies of Tight Porous Media

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Product

Resources

About

A Study for Using CO₂ To Enhance Natural Gas Recovery from Tight Reservoirs

A Study for Using CO₂ To Enhance Natural Gas Recovery from Tight Reservoirs