Gas Reservoir Rocks Research Articles

Experimental investigation on aqueous phase migration in unconventional gas reservoir rock samples by nuclear magnetic resonance

With the widely application of hydraulic fracturing treatment, formation damage caused by fracture fluid invasion has become a thorny problem in unconventional gas reservoirs. Experiences in field operation indicate that shut-in the well for a period of time after hydraulic fracturing stimulation can reduce formation damage to some extent. Research indicates that the migration of fracture fluid from high water saturation zone to low water saturation zone is one of the key mechanisms to the mitigation of formation damage during shut-in period. However, an in-depth understanding about the aqueous phase migration between pores of different size during shut-in period is still lacking. In this study, unconventional gas reservoir rock samples were selected to simulate fracture fluid invasion and migration, nuclear magnetic resonance (NMR) technique was used to monitor the migration of aqueous phase in rock samples, and spontaneous imbibition experiments were conducted to investigate the imbibition characteristics of the samples. Results show that amplitude difference, vertex value, vertex position and peak width of T2 spectrum can be useful parameters to characterize the direction, speed and scope of the aqueous phase migration between pores of different size in rock samples. Aqueous phase migration between pores of different size has two stages: in first stage, aqueous phase migrates from small pores to large pores; in second stage, it migrates from large pores to small pores, which decreases the water saturation in large pores, and that is another important mechanism of formation damage mitigation during shut-in period. The duration and migratory volume of each stage are closely related to the pore characteristics and clay mineral content, and the duration of the two stages could help determine the proper occurrence and duration of the shut-in operation. Capillary force and osmotic pressure play important roles in the aqueous phase migration in pores, samples with highly developed micropores and high clay mineral content get a longer second stage, and a longer shut-in period is required to mitigate formation damage.

The lithology and reservoir properties of the Lower Ordovician Majiagou formation at the Tabamiao gas field (Ordos Basin, China)

The Ordos Basin is known for rich natural gas, coal, and oil fields; it is an important mineral raw material and electric power base of China. Among the recently discovered gas fields within the Yimeng Monocline, the Sulige and Tabamiao gas fields, where gas reserves are found in Lower Ordovician carbonate rocks, are best known. We have identified five types of gas-reservoir rocks, which are confined to the ancient weathering crust of Ordovician carbonate deposits.

Evaluation of Various Pulse-Decay Laboratory Permeability Measurement Techniques for Highly Stressed Coals

The transient technique for laboratory permeability measurement, proposed by Brace et al. (J Geophys Res 73:2225–2236, 1968) and widely used for conventional gas reservoir rocks, is the preferred method when testing low-permeability rocks in the laboratory. However, Brace et al.’s solution leads to considerable errors since it does not take into account compressive storage and sorption effect when applied to sorptive rocks, such as, coals and shales. To verify the applicability of this solution when used to characterize fluid flow behavior of coal, an in-depth investigation of permeability evolution for flow of helium and methane depletion was conducted for San Juan coals using the pressure pulse-decay method under best replicated in situ conditions. Three permeability solutions, Brace et al.’s (1968), Dicker and Smits’s (International meeting on petroleum engineering, Society of Petroleum Engineers, 1988) and Cui et al.’s (Geofluids 9:208–223, 2009), were utilized to establish the permeability trends. Both helium and methane permeability results exhibited very small difference between the Brace et al.’s solution and Dicker and Smits’s solution, indicating that the effect of compressive storage is negligible. However, methane permeability enhancement at low pressures due to coal matrix shrinkage resulting from gas desorption can be significant and this was observed in pressure response plots and the estimated permeability values using Cui et al.’s solution only. Therefore, it is recommended that Cui et al.’s solution be employed to correctly include the sorption effect when testing coal permeability using the transient technique. A series of experiments were also carried out to establish the stress-dependent permeability trend under constant effective stress condition, and then quantify the sole contribution of the sorption effect on permeability variation. By comparison with the laboratory data obtained under in situ stress/strain condition, it was verified that accelerated CBM production can be achieved by reducing the horizontal stresses.

Identification of clay minerals in reservoir rocks by FTIR spectroscopy

Clay minerals including kaolinite, montmorillonite and bentonite in oil and gas reservoir rocks are identified by absorption spectra obtained via Fourier Transform Infrared (FTIR) spectroscopy. Bands around 3695, 3666, 3650 and 3630 cm-1 and bands around 3620 and 3400 cm-1 are the most diagnostically reliable for kaolinite and montmorillonite, respectively; also absorption bands in the region of 1200...955 cm-1 are equally diagnostic for all the clay minerals studied.

Formation and destruction mechanism as well as major controlling factors of the Silurian shale gas overpressure in the Sichuan Basin, China

Taking the Well JY1 and Well PY1 in the Eastern Sichuan Basin as examples, the formation mechanism of shale gas overpressure was studied by using the cross plot of acoustic versus density logging data. During the processes of hydrocarbon generation and the uplifting, the pressure evolution of fluids in shale gas layers was reconstructed by fluid inclusions and PVTSIM software. The major factors controlling the evolution of shale gas overpressure were established according to the study of fracture, the timing of the uplifting, and episodes of tectonic deformation. Our results showed that the main mechanism of overpressure in the Silurian shale gas reservoirs in the Sichuan Basin was the fluid expansion, which was caused by hydrocarbon generation. Since the Yanshanian, the strata were uplifted and fluid pressure generally showed a decreasing trend. However, due to the low compression rebound ratio of shale gas reservoir rocks, poor connectivity of reservoir rocks, and low content of formation water and so on, such factors made fluid pressure decrease, but these would not be enough to make up the effects of strata erosion resulting in a further increase in fluid pressure in shale gas reservoirs during the whole uplifting processes. Since the Yanshanian, the Well PY1 zone had been reconstructed by at least three episodes of tectonic movement. The initial timing of the uplifting is 130 Ma. Compared to the former, the Well JY1 zone was firstly uplifted at 90 Ma, which was weakly reconstructed. As a result, low-angle fractures and few high resistance fractures developed in the Well JY1, while high-angle fractures and many high resistance fractures developed in the Well PY1. In totality, the factors controlling the overpressure preservation in shale gas reservoirs during the late periods include timing of late uplifting, superposition and reconstruction of stress fields, and development of high-angle fractures.

Development of Porosity Measurement Method in Shale Gas Reservoir Rock

The pore scales have impacts on transport mechanisms in shale gas reservoirs. In this research, digital helium porosity meter is used for porosity measurement by considering real condition. Accordingly it is necessary to obtain a good approximation for gas filled porosity. Shale has the typical effective porosity that is changing as a function of time. Effective porosity values for three different shale rocks are analyzed by this proposed measurement. We develop the new measurement method for characterizing porosity phenomena in shale gas as a time function by measuring porosity in a range of minutes using digital helium porosity meter. The porosity of shale rock measured in this experiment are free gas and adsorbed gas porosoty. The pressure change in time shows that porosity of shale contains at least two type porosities: macro scale porosity (fracture porosity) and fine scale porosity (nano scale porosity). We present the estimation of effective porosity values by considering Boyle-Gay Lussaac approximation and Van der Waals approximation.

Numerical simulation of the electrical properties of shale gas reservoir rock based on digital core

In this paper we study the electrical properties of shale gas reservoir rock by applying the finite element method to digital cores which are built based on an advanced Markov Chain Monte Carlo method and a combination workflow. Study shows that the shale gas reservoir rock has strong anisotropic electrical conductivity because the conductivity is significantly different in both horizontal and vertical directions. The Archie formula is not suitable for application in shale reservoirs. The formation resistivity decreases in two cases; namely (a) with the increase of clay mineral content and the cation exchange capacity of clay, and (b) with the increase of pyrite content. The formation resistivity is not sensitive to the solid organic matter but to the clay and gas in the pores.

Dehydration Effect on the Pore Size, Porosity, and Fractal Parameters of Shale Rocks: Ultrasmall-Angle X-ray Scattering Study

The characterization of pore networks is extremely important in understanding transport and storage phenomena in unconventional gas and oil reservoir rocks. An ultrasmall-angle X-ray scattering (USAXS) measurement has been performed on Silurian black shales from the Baltic Basin, Poland, from a wide range of depths along a burial diagenetic sequence. This study provides insight into the nature of the pore structure, including the pore size distribution, total porosity, and fractal dimensions of the rocks. Samples were measured in both their air-dried state, equilibrated at ∼50% relative humidity, and prior to dehydration by drying at 200 °C to make a comprehensive comparison of the pore structure changes induced by dehydration. Two trends were observed: porosity values decreased with depth as expected from the models of porosity evolution with burial and increased upon sample dehydration. The USAXS-measured porosity values show very good correspondence with the measurements by immersion porosity methods. ...

Viscous relaxation model for predicting least principal stress magnitudes in sedimentary rocks

Abstract We propose a new method for estimating stress magnitudes as a function of depth in sedimentary formations based on a laboratory constrained viscous rheology and steady tectonic loading. We apply this method to a well drilled in the Barnett shale in the Fort Worth Basin, Texas. Laboratory experiments show that shale gas reservoir rocks exhibit wide range of viscoplastic behavior mostly dominantly controlled by its composition. Stress relaxation in these formations is described by a simple power-law (in time) rheology. We demonstrate that a reasonable profile of the principal stress magnitudes can be obtained from geophysical logs by utilizing (1) the laboratory power-law constitutive law, (2) an estimate of the horizontal tectonic loading, and (3) the assumption that the ratio of principal stress differences ([S2−S3]/[S1−S3]) is relatively uniform with depth. Profiles of the principal stress magnitudes generated based on our proposed method for a vertical well in the Barnett shale generally agree with the occurrence of drilling-induced tensile fractures in the same well. Also, the predicted decrease in the least principal stress (fracture gradient) in the limestone formation underlying the Barnett shale appears to explain the downward propagation of hydraulic fractures observed in this region. This stress change is not captured by the extended Eaton (instantaneous loading) model even when incorporating formation anisotropy. We believe our approach is more consistent with the time-dependent processes associated with stress accumulation over the course of geological time and thus may provide a new method to predict vertical hydraulic fracture growth in targeted reservoirs.

Time-dependent deformation of shale gas reservoir rocks and its long-term effect on the in situ state of stress

Laboratory testing of shale gas reservoir rocks reveal varying amounts of time-dependent viscous deformation in response to applied differential stress. The time-dependent deformation is an inherent property of the dry rock as it occurs in the absence of pore fluid. The contribution of the time-dependent deformation is generally larger for rocks with more clay and organic content. The time-dependent behavior can be modeled as a power-law function of time. Its magnitude is approximately linear with the magnitude of the applied differential stress and nearly insensitive to the confining pressure. By applying linear viscoelastic theory and using laboratory constrained constitutive parameters, we evaluated the effect of the time-dependent deformation in modifying the in situ differential stress over time. Modeling suggests that a significant proportion of a differential stress change would be relaxed over time-scales on the order of days. Because of this short time scale, the composition of the rock (as it influences the time-dependent behavior) may influence the in situ differential stress magnitudes stronger than the formation׳s geological loading history for these reservoirs.

Литолого - геофизические свойства сланцевых пород с повышенным содержание керогена

The key features of unconventional shale hydrocarbon accumulations include the following: a) all source rocks act as low permeability oil and gas res-ervoir rocks requiring no cover rock; b) effective pore space is distributed within the bulk of mature kerogen resulting from katagenetic transformations in organic material. Evaluating the properties of reservoir rocks with a high content of kerogen attracts a lot of interest due to new approaches to unconven-tional hydrocarbon exploration and the challenge of applying the technology of hydraulic fracturing in low-permeability formations. This research into the lithological and physical properties of facies with a high kerogen content was prompted by a correlation between the sedimentary features of the proven productive shale formations and similar formations of different ages in the Dnieper-Donets basin. The sedimen-tary conditions of shale formation in DDb being similar to those of forming oil and gas producing shales with a high content of kerogen in Utica/Point Pleasant paleobasins, the highest kerogen content was assumed to be associated with certain lithotypes holding interest for further study. Mathematical equations were derived to describe the correlation between radioactivity, uranium content, bulk density, electrical resistivity and organic carbon content for shales from the Utica formation and the DDb shales. There were clarified mathematical dependences of bulk density on organic carbon content for a number of Lower Carboniferous formations in DDb. As using separate mathematical expressions is likely to pro-duce results of doubtful validity, preference should be given to a system of equations to describe the nature of changes in different physical prop-erties of shales depending on the organic component content. That will provide accurate data on the share of kerogen in the studied reservoir rocks. Values of hydrogen and oxygen indices only predict low molecular weight products and their subsequent extraction. The findings on the lithological properties and mathematical relationships have been reported and discussed at international conferences.

Lacustrine algal limestone reservoir in western Qaidam Basin, China

Compared to marine carbonate around the world, lacustrine carbonate is relatively scarce. Much less attention has been paid to it. Lacustrine carbonate, a product of mixed deposition of continental clastics and carbonate under special conditions, can be both important source rocks, and oil and gas reservoir rocks. Qaidam Basin is a large salt lake basin on the Tibetan Plateau where oil and gas flow has recently been discovered in lacustrine algal limestone. Study of the algal limestone is a potentially valuable target of exploration, and is of great significance to the exploration and development of mixed carbonate formations.

Mechanical properties of shale-gas reservoir rocks — Part 1: Static and dynamic elastic properties and anisotropy

Understanding the controls on the elastic properties of reservoir rocks is crucial for exploration and successful production from hydrocarbon reservoirs. We studied the static and dynamic elastic properties of shale gas reservoir rocks from Barnett, Haynesville, Eagle Ford, and Fort St. John shales through laboratory experiments. The elastic properties of these rocks vary significantly between reservoirs (and within a reservoir) due to the wide variety of material composition and microstructures exhibited by these organic-rich shales. The static (Young’s modulus) and dynamic (P- and S-wave moduli) elastic parameters generally decrease monotonically with the clay plus kerogen content. The variation of the elastic moduli can be explained in terms of the Voigt and Reuss limits predicted by end-member components. However, the elastic properties of the shales are strongly anisotropic and the degree of anisotropy was found to correlate with the amount of clay and organic content as well as the shale fabric. We also found that the first-loading static modulus was, on average, approximately 20% lower than the unloading/reloading static modulus. Because the unloading/reloading static modulus compares quite well to the dynamic modulus in the rocks studied, comparing static and dynamic moduli can vary considerably depending on which static modulus is used.

Scattering imaging method in transmission x-ray microscopy

We present a x-ray microscopy technique based on structured illumination in a microscope that characterizes the size of the subresolution-limit features. The technique is effective for characterizing fine structures substantially beyond the Rayleigh resolution of the microscope. We carried out optical experiments to demonstrate the basic principle of this new technique. Experimental results show good agreement with theoretical predictions. This technique should find a wide range of important imaging applications with a feature size down to nanometer scale, such as oil and gas reservoir rocks, advanced composites, and functional nanodevices and materials.

Characteristics of the Shale Gas Reservoir Rocks in the Lower Silurian Longmaxi Formation, East Sichuan Basin, China

The Sichuan basin is an oil-bearing and gas-rich basin with extensive development of the Lower Silurian Longmaxi Formation shale in southwestern China. The gas shows in the shale were identified in exploration wells mainly located between southeastern Sichuan basin and Western Hubei-Eastern Chongqing. The thickness of the Lower Silurian Longmaxi Formation shale ranges from 65 to 516 m. The base of the Longmaxi Formation shale is graptolite-rich transgressive black shale. Its thickness increases eastward in the study area, similarly as the sand content in the formation, with the latter also increasing stratigraphically upward. The Longmaxi Formation is comprised by eight lithofacies, including laminated and nonlaminated mudstone/shale, dolomitic siltstone, laminated lime mudstone/shale, argillaceous siltstone, laminated and nonlaminated silty mudstone/shale, fine grained silty sandstone, calcareous concretions and nonlaminated shale enriched organic matter. The biota in the formation is dominated by graptolites, ostracods, echinoderms, brachiopods, trilobites and radiolarian. Longmaxi Formation contains 0.2% to 6.7% of organic carbon ( TOC). The organic matter is overmature, with Ro 2.4%−3.6% and dominated by Type II-kerogen. Quartz silt, which is the second important component of the shale gas reservoir quality, occurs as laminae and/or disseminated and varies from 2% – 93% in the shale. The size of quartz silt ranges from 0.03 to 0.05mm, with terrigenous origin. Porosity measured on the core samples of the shale from the Longmaxi Formation in exploratory wells ranges from 0.58% to 0.67%. The microporosity observed in the thin sections of the shale is about 2%, and dominated by the intercrystal and intragranular pores, with the pore size ranging from 100nm to 50μm. The other pore types are related to fractures, with the width of ranging from 2 to 5μm. The formation mechanism of the shale reservoir rocks includes favorable mineral composition, diagenesis and thermal cracking of organic component. There are some differences between Longmaxi Formation shale and Barnett shale in USA. The former is buried deeper, higher degree of thermal evolution, lower gas content, denser, more quartz of terrigenous origin. The prevailing low content of organic matter and highly variable quartz content in the Longmaxi Formation shale suggests there are only marginal conditions for exploration of shale gas resource. However, the high variability in both the content of TOC and quartz in the shale indicates that locally, particularly in the southeastern part of the basin, favorable conditions for shale gas may have developed. More detailed paleogeographic, burial history, gas content and quartz origin studies are needed to better access shale-gas potential of the Lower Silurian Longmaxi Formation shale.

NMR Facies Definition for Permo-Triassic Kangan/Dalan Carbonate Formation by Use of Core/Log and Pore-Scale Measurements

Summary An integrated and quantitative approach is taken here to the Permo-Triassic Kangan/Dalan carbonate formation. We apply pore-network characterization to the problem of the classification of these complex carbonate gas-reservoir rocks. We start with the useful and convenient nuclear-magnetic-resonance (NMR) data on 28 samples to define NMR facies (NMRF). The NMRF grouping is performed with both the relaxivity constant (ρ2) and the specific-surface-volume (Sgv) data. Seven NMRF have been defined with a combination of core/log NMR data, petrographic image analysis, and mercury-injection examinations for two wells. The advantage of evaluation of the pore spaces rather than grain properties is to discover trends that are not apparent when one uses a conventional sedimentological facies definition. Lithology-independent NMRF exhibit properties that are associated with pore geometry. This should have special importance for the formation evaluation of carbonates.

The Impact of Irreducible Water on Stress-Sensitivity of Gas Reservoir Rocks

According to many researches, the presence of stress-sensitivity has been confirmed in reservoir rocks. Because it will create huge damage to the permeability of reservoirs, sufficient attention should be made. In this paper, through the experiment, the permeability value change with effective pressure in the condition of saturated with irreducible water and dry environment were compared. The study showed that the stress-sensitivity of core sample was more obvious in the condition of saturated with irreducible water.

Studies of the anisotropy of the microstructure of oil and gas reservoir rocks by electron microscopy methods

The paper presents the features of applying the scanning electron microscopy method for studying the anisotropy of the pore space of carbonate rocks in oil and gas reservoirs. The results of studies into the horizontal anisotropy of the microstructure and pore space are presented. The significance of the pore space horizontal anisotropy for filtration properties, which should be taken into account during the development of 3D-hydrodynamic models of hydrocarbon deposits, has been experimentally found for rocks with a complex structure.

Study of different factors affecting the electrical properties of natural gas reservoir rocks based on digital cores

The effects of the wettability and solubility of natural gas in formation water on the electrical properties of natural gas reservoir rocks are studied using the finite element method based on digital cores. The results show that the resistivity index of gas-wet reservoir rocks is significantly higher than that of water-wet reservoir rocks in the entire range of water saturation. The difference between them increases with decreasing water saturation. The resistivity index of natural gas reservoir rocks decreases with increasing additional conduction of water film. The solubility of natural gas in formation water has a dramatic effect on the electrical properties of reservoir rocks. The resistivity index of reservoir rocks increases as the solubility of natural gas increases. The effect of the solubility of natural gas on the resistivity index is very obvious under conditions of low water saturation, and it becomes weaker with increasing water saturation. Therefore, the reservoir wettability and the solubility of natural gas in formation water should be considered in defining the saturation exponent.

A rock physics model for tight gas sand

Tight gas reservoirs are often defined as gas-bearing sandstones or carbonates having in-situ permeabilities to gas less than 0.1 mD (Holditch, 2006; Smith et al., 2009). Tight gas reservoir rocks can be at different in-situ physical conditions: deep or shallow; over- or underpressured; high temperature or low temperature; and under different stress states. The reservoir-forming rock can have different textures such as shaley and silty unconsolidated sandstones or clean-cemented sandstones. These different rocks produce gas at low rates. Tight reservoir rocks can be blanket or lenticular, homogeneous or heterogeneous, and can contain a single layer or multiple layers, be fractured or unfractured, and mainly produce dry natural gas.