A workflow to estimate shale gas permeability variations during the production process

Jia, Bao; Tsau, Jyun‐Syung; Barati, Reza

doi:10.1016/j.fuel.2017.11.087

Cited by 58 publications

(21 citation statements)

References 23 publications

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“…In addition, compared with other penetration fluid methods, such as GRI porosity, LTNA, MIP, and MNR methods, the CCP method is less affected by fluid (gas or water) adsorption. For the shale reservoir samples, the porosities derived from the penetration fluid methods are apparent porosities because of adsorption of OM and clay, as well as the permeability behaviors [36][37][38].…”

Section: Advantages Of the Ccp Methodsmentioning

confidence: 99%

Total Porosity Measured for Shale Gas Reservoir Samples: A Case from the Lower Silurian Longmaxi Formation in Southeast Chongqing, China

Chen

Duan

et al. 2018

Minerals

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Measuring total porosity in shale gas reservoir samples remains a challenge because of the fine-grained texture, low porosity, ultra-low permeability, and high content of organic matter (OM) and clay mineral. The composition content porosimetry method, which is a new method for the evaluation of the porosity of shale samples, was used in this study to measure the total porosity of shale gas reservoir samples from the Lower Silurian Longmaxi Formation in Southeast Chongqing, China, based on the bulk and grain density values. The results from the composition content porosimetry method were compared with those of the Gas Research Institute method. The results showed that the composition content porosimetry porosity values of shale gas reservoir samples range between 2.05% and 5.87% with an average value of 4.04%. The composition content porosimetry porosity generally increases with increasing OM and clay content, and decreases with increasing quartz and feldspar content. The composition content porosimetry results are similar to the gas research institute results, and the differences between the two methods range from 0.05% to 1.52% with an average value of 0.85%.Minerals 2019, 9, 5 2 of 12 and fossil fragment pore [15]. At present, the techniques available for the measurement of micro-pore characteristics of shale samples are divided into two categories: the radiation method and the penetration fluids method [16].The radiation methods include scanning electron microscopy (SEM), field emission scanning electron microscopy (FE-SEM), backscatter mode (BS), transmission electron microscopy (TEM), small-angle neutron scattering (SANS), ultra-small-angle neutron scattering (USANS), three-dimensional (3D) reconstruction technology, and computed tomography (CT). Most provide direct visual observation of microscopic features in shale samples [17][18][19][20][21]. 3D image reconstruction technology can be used to investigate shale microstructure and analyze the characteristics of pores. For the radiation methods, a higher resolution corresponds to a smaller sample size [22], and the smaller samples are less representative given shale's heterogeneity [16,19]. The penetration fluid methods include low temperature nitrogen adsorption/desorption (LTNA), mercury intrusion porosimetry (MIP), and nuclear magnetic resonance (NMR). The first two methods refer to injecting non-wetting fluid into a shale sample and recording the fluid volume and injection pressure. Then, the pore size distribution and specific surface area are calculated using several theoretical models [17,[23][24][25]. Due to the differences in experimental environment (temperature and pressure) and injected fluid properties, LTNA and MIP methods have different detection ranges. The nanometer-to micrometer-scale pore systems in shale samples were evaluated by combining their results [17,23]. However, LTNA and MIP methods can only reflect interconnected pores, as the injected fluids cannot access isolated pores [16]. The result of the MIP method reflects the pore volu...

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Section: Advantages Of the Ccp Methodsmentioning

confidence: 99%

Total Porosity Measured for Shale Gas Reservoir Samples: A Case from the Lower Silurian Longmaxi Formation in Southeast Chongqing, China

Chen

Duan

et al. 2018

Minerals

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“…The low-temperature N 2 adsorption isotherms of the samples with varied Sc-CO 2 injection time (0 day, 10 days, 30 days) are shown in Figure 5. According to the isotherm classification from the International Union of Pure and Applied Chemistry (IUPAC) [24,25], all the curves obtained are following the Type III Adsorption Isotherm curve. At the beginning under the extremely low P/Po applied, the pores of the both samples present micro-pore filling behavior and micro pore volume is related to the adsorption amount.…”

Section: Pore Structure Alterationmentioning

confidence: 99%

Investigation of Properties Alternation during Super-Critical CO2 Injection in Shale

et al. 2019

Self Cite

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The low recovery of oil from tight liquid-rich formations is still a major challenge for a tight reservoir. Thus, supercritical CO2 flooding was proposed as an immense potential recovery method for production improvement. While up to date, there have been few studies to account for the formation properties’ variation during the CO2 Enhanced Oil Recovery (EOR) process, especially investigation at the micro-scale. This work conducted a series of measurements to evaluate the rock mechanical change, mineral alteration and the pore structure properties’ variation through the supercritical CO2 (Sc-CO2) injection process. Corresponding to the time variation (0 days, 10 days, 20 days, 30 days and 40 days), the rock mechanical properties were analyzed properly through the nano-indentation test, and the mineralogical alterations were quantified through X-ray diffraction (XRD). In addition, pore structures of the samples were measured through the low-temperature N2 adsorption tests. The results showed that, after Sc-CO2 injection, Young’s modulus of the samples decreases. The nitrogen adsorption results demonstrated that, after the CO2 injection, the mesopore volume of the sample would change as well as the specific Brunauer–Emmett–Teller (BET) surface area which could be aroused from the chemical reactions between the CO2 and some authigenic minerals. XRD analysis results also indicated that mesopore were altered due to the chemical reaction between the injected Sc-CO2 and the minerals.

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“…A practice that can be used to avoid this misinterpretation is to measure several permeability values under different pressures. High-pressure might be more indicative of fluid phase permeability [48][49][50]. Figure 4 provides the movable fluid saturations in different pores of each core.…”

Section: Study On Oil Saturation and Movable Fluid Saturationmentioning

confidence: 99%

Waterflooding Huff-n-puff in Tight Oil Cores Using Online Nuclear Magnetic Resonance

et al. 2018

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Given the difficulty in developing waterflooding in tight oil reservoirs, using waterflooding huff-n-puff is an effective method to improve oil recovery. Online nuclear magnetic resonance (NMR) can detect the change in internal oil and water during the core displacement process, and magnetic resonance imaging (MRI) in real time. To improve the tight oil reservoir development effectiveness, cores with different permeability were selected for a waterflooding huff-n-puff experiment. Combined with online NMR equipment, the fluid saturation, recovery rate, and residual oil distribution were studied. The experiments showed that, for tight oil cores, more than 80% of the pores were sub-micro-and micro-nanopores. More than 77.8% of crude oil existed in the sub-micro-and micropores, and movable fluids mainly existed in the micropores with a radius larger than 1 µm. The NMR data and the MRI images both demonstrated that the recovery ratio of waterflooding after waterflooding huff-n-puff was higher than that of conventional waterflooding, and, therefore, residual oil was lower. Choosing two cycles' of waterflooding, huff-n-puff was more suitable for tight oil reservoir development. The production of crude oil increased by 22.2% in the field pilot test, which preliminarily proved that waterflooding huff-n-puff was suitable for tight oil reservoirs.

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A workflow to estimate shale gas permeability variations during the production process

Cited by 58 publications

References 23 publications

Total Porosity Measured for Shale Gas Reservoir Samples: A Case from the Lower Silurian Longmaxi Formation in Southeast Chongqing, China

Total Porosity Measured for Shale Gas Reservoir Samples: A Case from the Lower Silurian Longmaxi Formation in Southeast Chongqing, China

Investigation of Properties Alternation during Super-Critical CO2 Injection in Shale

Waterflooding Huff-n-puff in Tight Oil Cores Using Online Nuclear Magnetic Resonance

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