Pulse-decay Permeability Research Articles

Influence of fracturing fluids on shale matrix permeability and micro-mechanical properties after chemical interactions

Geochemical interactions between shale and hydraulic fracture fluids (HFFs), principally mineral dissolution and precipitation, can result in alteration of matrix permeability and tendency of proppant embedment, ultimately impacting hydrocarbon migration through the shale formation. This study aimed to quantify changes of core permeability and micromechanical properties after shale-HFF chemical interactions. Extent of chemical alteration of the solid phase was characterized by synchrotron X-ray fluorescence mapping, micro-computed tomography, and scanning electron microscopy. Post-reaction brine was evaluated for elemental concentrations. Both low-carbonate and high-carbonate shale exhibited carbonate dissolution, an iron oxidation zone, and barite precipitates partially infilling secondary porosity. These reactions were more obvious in the high-carbonate shale but extended further into the low-carbonate shale. Pulse-decay permeability measurements generally revealed increase in permeability after reactions, whereas hardness and modulus reduction were observed only in reaction zones of high carbonate shale. Inevitable heterogeneity of natural shale samples resulted in large deviations in hydromechanical measurements both on the core scale and on the microscale.

Liquid Permeability Determination from Vacuum Imbibition in Tight/Shale Core Plugs

Liquid permeability is a key petrophysical parameter that quantifies the ability of a liquid to flow through porous rock/soil and can be used in determining the efficiency of many subsurface processes, including enhanced hydrocarbon recovery, groundwater transport, carbon dioxide geostorage, underground hydrogen storage, etc. However, it is time-consuming (usually >16–240 h) and challenging to measure the liquid permeability for tight/shale rocks, particularly when the permeability is 100 nD or lower. The objective of this study is to develop a rapid and simple approach to determine liquid (brine or oil) permeability in tight siltstones/shales. Specifically, the developed method is based on the combination of one-dimensional (1D) vacuum imbibition experiments in tight/shale core plugs and a modified Lucas–Washburn model. For our proof-of-concept study, the results have demonstrated that (1) only 44–116 h are required to determine the liquid permeability (98–608 nD) for the analyzed samples from the Montney and Yanchang Formations; and (2) the acquired brine permeability was 28.3–28.5% lower than the slip-corrected nitrogen (N2) permeability derived from the pulse-decay permeability tests. This is the first attempt to determine the absolute permeability of a liquid according to a 1D vacuum imbibition experiment and theory. This study provides a promising technique for the fast characterization of ultratight formation permeability of around 100 nD.

Influence of Equation Nonlinearity on Pulse-Decay Permeability Measurements of Tight Porous Media

Influence of Equation Nonlinearity on Pulse-Decay Permeability Measurements of Tight Porous Media

Characterization of 3D pore nanostructure and stress-dependent permeability of organic-rich shales in northern Guizhou Depression, China

The three-dimensional (3D) pore structures and permeability of shale are critical for forecasting gas production capacity and guiding pressure differential control in practical reservoir extraction. However, few investigations have analyzed the effects of microscopic organic matter (OM) morphology and 3D pore nanostructures on the stress sensitivity, which are precisely the most unique and controlling factors of reservoir quality in shales. In this study, ultra-high nanoscale-resolution imaging experiments, i.e. focused ion beam-scanning electron microscopy (FIB-SEMs), were conducted on two organic-rich shale samples from Longmaxi and Wufeng Formations in northern Guizhou Depression, China. Pore morphology, porosity of 3D pore nanostructures, pore size distribution, and connectivity of the six selected regions of interest (including clump-shaped OMs, interstitial OMs, framboidal pyrite, and microfractures) were qualitatively and quantitatively characterized. Pulse decay permeability (PDP) measurement was used to investigate the variation patterns of stress-dependent permeability and stress sensitivity of shales under different confining pressures and pore pressures, and the results were then used to calculate the Biot coefficients for the two shale formations. The results showed that the samples have high OM porosity and 85% of the OM pores have the radius of less than 40 nm. The OM morphology and pore structure characteristics of the Longmaxi and Wufeng Formations were distinctly different. In particular, the OM in the Wufeng Formation samples developed some OM pores with radius larger than 500 nm, which significantly improved the connectivity. The macroscopic permeability strongly depends on the permeability of OM pores. The stress sensitivity of permeability of Wufeng Formation was significantly lower than that of Longmaxi Formation, due to the differences in OM morphology and pore structures. The Biot coefficients of 0.729 and 0.697 were obtained for the Longmaxi and Wufeng Formations, respectively.

Laboratory Investigation of Impact of Slickwater Composition on Multiphase Permeability Evolution in Tight Sandstones

Summary Fracturing fluid filtrate that leaks off during injection is imbibed by strong capillary forces present in low-permeability sandstones and may severely reduce the effective gas permeability during cleanup and post-fracture production. This work aims to investigate the role fracturing fluid filtrate from slickwater has on rock-fluid and fluid-fluid interactions and to quantify the resulting multiphase permeability evolution during imbibition and drainage of the filtrate by means of specialized core laboratory techniques. Three suites of experiments were conducted. In the first suite of experiments, a fluid leakoff test was conducted on selected core samples to determine the extent of polymer invasion and leakoff characteristics. In the second suite, multigas relative permeability measurements were conducted on sandstone plugs saturated with fracturing fluid filtrate. A combination of controlled fluid evaporation and pulse decay permeability technique was used to measure liquid and gas effective permeabilities for both drainage and imbibition cycles. These experiments aim to capture dynamic permeability evolution during invasion and cleanup of fracturing fluid (slickwater). The final suite of experiments consists of adsorption flow tests to investigate, identify, and quantify possible mechanisms for adsorption of the polymeric molecules of friction reducers present in the fluid filtrate to the pore walls of the rock sample. Imbibition tests and observations of contact angles were conducted to validate possible wettability changes. Results from multiphase permeability flow tests show an irreversible reduction in endpoint brine permeability and relative permeability with increasing concentration of friction reducer. Our results also show that effective gas permeability during drainage/cleanup of the imbibed slickwater fluid is controlled to a large degree by trapped gas saturation than by changes in interfacial tension. Adsorption flow tests identified adsorption of polymeric molecules of the friction reducer present in the fluid to the pore walls of the rock. The adsorption friction reducer increases the wettability of the rock surface and results in the reduction of liquid relative permeability. The originality of this work is to diagnose formation damage mechanisms from laboratory experiments that adequately capture multiphase permeability evolution specific to a slickwater fluid system, during imbibition and cleanup. This will be useful in optimizing fracturing fluid selection.

Pulse-decay permeability measurements and influencing factor analysis in marine shale formation in South China

Pulse-decay permeability measurements and influencing factor analysis in marine shale formation in South China

Characterization of the weathered basement rocks in the Dongping field from the Qaidam Basin, Western China: significance as gas reservoirs

Reservoir quality is a critical risk factor in basement reservoirs. Researches into basement reservoirs by petrographic analysis combined with X-ray diffraction, log identification, electron microscopy, field emission scanning electron microscopy, porosity and pulse-decay permeability and core analysis have provided insights into the characterization of the commonality, diversity and difference of the weathered basement rocks as gas reservoirs in the Dongping field. Geological structures, lithology and near-surface processes control the reservoir physical property together. From Wellblock Dp 3 to Wellblock Dp 17, the high uplift gradually transforms into the low slope area towards the center of basin, with the lithology changing as well, which results in different degrees of fracture development in the bedrock in different wellblocks. The basement lithologies are granite, granitic gneiss, and limestone with slate in Wellblock Dp3, Dp1 and Dp17, respectively. Though they all provide effective reservoir space for gas accumulation, the productivity of nature gas shows significant differences. Fractures are the main store space in the three wellblocks. The development of fractures gives rise to secondary porosity around them because of physical weathering and chemical dissolution, but they generate many inhomogeneous fractures and secondary solution pores, whether on the planar distribution or in vertical. In Wellblock Dp3, high angle fractures were generated under the action of structural stress mechanism, with a large number of secondary pores. The porosity is between 0.1 and 23.2%. In Wellblock Dp 1, low angle fractures were the main storage space, with plenty of solution pores mainly in melanocratic minerals. The porosity is between 0.1 and 18.8%. In Wellblock Dp 17, where short and dense fractures developed, the porosity is between 0.1 and 10.3%. The data indicate that the granite in the uplift in Wellblock Dp3 has better reservoir properties due to the stronger physical weathering and chemical dissolution. As the porosity gradually decreases towards the slope and low-lying area, the more favorable exploration area should be the uplift and slope area in the depression area. However, the effective caprock developed locally in Wellblock Dp3, which affected the gas accumulation. Meanwhile, the reservoirs’ petrophysical properties showed distintive variation with different depths in different wellblocks. High productivity layers are under the 200 m, 100 m and 200 m depths from the top of the basement rocks in Wellblock Dp 3, Wellblock Dp 1 and Wellblock Dp 17, respectively. This suggestion in this study will be of significance for guiding oil and gas exploration in front of the Altun Mountains.

Finite-difference simulation of coreflooding based on a reconstructed CT scan; modeling transient oscillating and pulse decay permeability experiment

Numerical simulation and experimental research of fluid flow in porous media enhance the practices of petroleum reservoirs' management. Experiments on acquired reservoir-rock samples are conducted for accurate characterization and realization of the insitu hydrocarbon reserves. Implementing precise numerical simulation of those experiments is crucial to acquire accurate conclusions from the obtained experimental results. Coreflooding experiments quantify reservoir rock's storage capacity, measure its transport connectivity, and evaluate recovery methods' effectiveness for that rock. In this paper, a reconstruction image-processing workflow of cores' CT scan is developed to build a finite difference numerical model for simulating coreflooding experiments. In a transient coreflooding experiment, a controlled pressure pulse with a known frequency and amplitude is transmitted to the rock sample. Rock permeability can be quantified by analytically solving the diffusivity flow equation for that experiment. Simulating the transient permeability experiment is very sensitive to the level of details of the pores' structure described in the numerical model. A transient permeability experiment with two different transient modes, sinusoidal oscillation, and pulse decay, was conducted on a standard Berea core sample. The Berea CT scan was image-processed to reconstruct the static porosity and permeability model in Petrel software using a 3D variogram geostatistical population. Injection and production sources were assigned to the finite gridblock, which correspond to flow nozzles of injection and production coreflooding setup's heads. Scheduled flow and controlled-pressure boundary-conditions were imposed on the dynamic model. Eclipse simulator was used to solve the dynamic model and calculate the pressure in each gridblock. The outlet pressure was calculated at each time step by three different realization approaches for porosity and permeability, i.e., from experiments, from statistical analysis for the CT scan, and by the proposed image processing workflow. The simulated outlet pressure from the prosed workflow matched ideally, with a Pearson correlation coefficient of 0.98 and 0.99, the recorded one in the two experiments compared to underestimated or overestimated outlet pressure from the other two traditional realization approaches, i.e., statistical or experimental.

Effect of well shut-in after fracturing operations on near wellbore permeability

After hydraulically fracturing of shale gas wells, theoretical and experimental studies showed that over 75% of the injected water-based fracture fluids left unrecovered. The trapped water causes permeability damage and productivity impairment. The flowback water also tends to be highly saline, often with TDS contents of as much as 200,000 ppm. This study aims to investigate the effect of well shut-in before flowback stage (the soaking process) on the production of shale and tight sandstone formations.Shale and sandstone samples were analyzed by X-ray diffraction (XRD). Marcellus shale and Kentucky sandstone cores were used. A modified core flood setup was used to allow porosity measurements by gas expansion method, then pulse decay permeability measurements, and fluid injection during the leak-off process. Nitrogen was used for gas expansion and permeability measurements, while 5 wt% KCl brine was used as representative of the leak-off fracturing fluid. The fracturing fluid was injected under a constant pressure gradient (300 in the case of sandstone cores and 1500 psi in the case of shale cores. After removing the pressure gradient, gas permeability was measured at different soaking times. Computed tomography (CT) was used to scan the cores during the experiment to observe the propagation of fracturing fluid in the core with time.The results show that the regained permeability for sandstone formation was 60% of its initial value directly after the leak-off stage. Then, the regained permeability decreased with increasing the soaking time 38% of its initial value after the core completely invaded with leak-off fluid. The propagation rate of water saturation front from CT-scan data decreased with time until reaching the core outlet. The regained permeability on shale cores was 15% of its initial value and decreased with soaking time, due to depressed relative permeability curve on this tight pore-space cores.This study addresses the mechanism of production enhancement or reduction as a result of the soaking process for shale and tight sandstone formations.

Image-based core-scale real gas apparent permeability from pore-scale experimental data in shale reservoirs

This paper presents a new upscaling method to derive the core-scale apparent gas permeability from an improved pore-scale permeability model and experimental data, with more rigorous incorporation of varying gas storage/transport mechanisms in nano/micro pores. First, in use of SEM images of a gas-rich shale field example in Sichuan Basin from our lab, pore network models of inorganic-matter (IOM) and organic-matter (OM) are characterized by using a digital-core technique. Next, an improved pore-scale real gas apparent permeability is modeled rigorously for both IOM/OM, respectively, with 1) bulk gas transport, gas adsorption, surface diffusion, pore-size confined phase behavior, and stress-dependent rock properties and 2) an additional reduction in inorganic pore sizes by water film adhered on pore surfaces. Core-scale permeability is then derived by assembling the permeabilities of stochastically distributed IOM/OM patches with different pore network models properties using the Monte Carlo sampling method. The new core-scale permeability model is validated by pulse-decay permeability experiment. Moreover, the representative elementary volume (REV) size is determined by analyzing the relative standard deviation of apparent gas permeability in cases with different sample sizes. The contributions of different gas transport mechanisms are discussed, and the impacts of stress-dependence for several field examples (i.e., Sichuan, Pierre and Barnett Basins) and water film with varying relative humidity (RH) on core-scale apparent permeability are analyzed. This work provides an effective approach to determine the core-scale shale permeability by directly using pore-scale experimental data, which is a common challenge in the unconventional resources.

Pressure pulse-decay tests in a dual-continuum medium: An improved technique to estimate flow parameters

The pressure pulse-decay permeability (PDP) measurement is a well-established technique to measure the permeability of tight rock samples such as shale. The conventional applications of the PDP measurement almost exclusively treat shale samples as a single-continuum system, even though the gas flow in some shale samples may be more accurately characterized by a dual-continuum, which is due to the large range of pore size distribution and chemical/mineralogical difference between organic and inorganic matters. However, studies about measurements of flow parameters for dual-continuum shale rock samples are very limited in literature. Liu et al. (2016) proposed a new analytical technique to characterize the dual-continuum behavior of a test sample using the PDP measurement with the same upstream and downstream reservoir volumes. In this study, a more general analytical technique is proposed and allows for using different upstream and downstream reservoir volumes in the PDP setup. With this new technique, all the existing PDP systems in laboratories can be conducted to characterize the dual-continuum behavior of a test sample without the need of modifying the upstream and downstream reservoir volumes, and the measured flow parameters of samples can be used as input parameters in the reservoir simulation of the dual-continuum system. The validity and practical usefulness of the new technique is demonstrated by the successful identification and characterization of the dual continuum behavior of test samples in laboratory.

A new low-permeability reservoir core analysis method based on rate-transient analysis theory

Unconventional reservoirs such as shales (mudrocks) and coals may exhibit an ultra-low matrix permeability (<0.001 md) challenging conventional laboratory-based methods for permeability measurement. Small-diameter core plug or crushed rock samples, combined with unsteady-state methods, are currently favored to reduce measurement times for ‘tight’ rocks. For core plug analysis, unsteady-state pulse-decay permeability (PDP) or steady-state methods (SS) are commonly employed in commercial laboratories, with the core plug sample subjected to confining stress. Analysis times, particularly for SS methods, may be excessive for ultra-low permeabilities in the nanodarcy range. Another limitation of both PDP and SS experiments applied to core plugs is that they do not represent the boundary conditions typically used to produce hydrocarbons from unconventional reservoirs in the subsurface through wells.Rate-transient analysis (RTA) is a technique used to quantitatively analyze production data from wells drilled into unconventional reservoirs to extract reservoir (e.g. permeability, hydrocarbons-in-place) and hydraulic fracture (conductivity, fracture length) properties. Multi-fractured horizontal wells (MFHWs) producing from low-permeability reservoirs commonly exhibit the flow-regime sequence of transient linear flow, where hydrocarbons flow through the reservoir orthogonal to hydraulic fractures or the horizontal well, followed by boundary-dominated flow caused by pressure interference between adjacent hydraulic fractures or wells. Transient linear flow may be analyzed using RTA methods to extract fracture or well-length (if permeability is known); the end of linear flow can be used to estimate permeability of the reservoir, and boundary-dominated flow to estimate hydrocarbons-in-place.In this work, a new experimental procedure and set-up, applied to core plugs under stress conditions, is developed to mimic well operating conditions encountered in the field (i.e. producing from a subsurface unconventional reservoir). After injection of methane gas into one end of the core plug, and pressure stabilization, the gas is flowed out of the same end of the core plug at constant pressure (with the aid of a backpressure regulator), and flow rates are measured with a flow meter. This procedure is applied to a core plug extracted from a low-permeability siltstone of the Montney Formation (western Canada). Repeated testing consistently demonstrated a transient linear flow period, as the gas pressure transient propagated along the core plug, followed by boundary-dominated flow after the pressure transient reached the end of the core plug; this sequence is identical to what is commonly observed in the field. Permeability was estimated using both the slope of a square-root of time plot (a common RTA method used to analyze transient linear flow), and the time at the end of linear flow combined with the linear flow distance of investigation (DOI) equation. Permeability from both techniques is in good agreement (±5% for both experiments performed), providing an important redundancy to the analysis procedure. Pore volume (and hence porosity, with bulk volume known) may be estimated from the time at the end of linear flow and the slope of the square-root of time plot – the calculated value is in excellent agreement (±2% for both experiments performed) with that obtained from pore volume/porosity estimates using a helium pycnometer (combined with calipered dimensions). Finally, test times for the ∼0.0007 md core plug sample, after the initiation of the production phase, are on the order of only a few minutes to obtain the two independent estimates of permeability and pore volume, which is faster than that achievable from a PDP test.The new innovative experimental procedure is successful in reproducing the physics of flow in unconventional reservoirs, with the results being analyzable with the same techniques applied to field data.

A method for correcting low permeability laboratory measurements for leaks: Theory, methodology and algorithms

Pulse-decay permeability (PDP) measurement is a widely used technique to measure the permeability of tight rocks such as shales. However, the PDP measurement is so sensitive to gas leakage of the system that the leakage would significantly affect the experimental results. To address the impact of the gas leakage, this paper develops an analytical solution of the PDP measurement with gas leakage that applies to both fractured and un-fractured core samples. The PDP measurement on a fractured core sample can be treated as a two-stage pressure transient process that are dominated by gas flow in a fracture and the flow between the fracture and the matrix, respectively. The analytical solution shows that the linearity of curve of logarithm of the normalized pressure difference (between the upstream and downstream reservoirs in the PDP system) versus time in the first-stage would break up when gas leakage occurs, so does the linearity of logarithm of the pressure decline curve in the second-stage. For an un-fractured core sample, the analytical solution for the PDP measurement with gas leakage is similar to the first-stage process for a fractured core sample. Based on these observations, an effective method to detect and correct the impacts of leakage on the PDP measurements is proposed using the analytical solution. The practical usefulness of the method is demonstrated by its successful applications to simulated PDP permeability measurements for several core samples.

PORE-THROAT STRUCTURE AND FRACTAL CHARACTERISTICS OF SHIHEZI FORMATION TIGHT GAS SANDSTONE IN THE ORDOS BASIN, CHINA

In order to better understand the impact of fractal features of pore-throat structures on effective physical properties of tight gas sandstones, this paper carried out constant-rate mercury injection tests, gas–water permeability analyses, helium-based porosity and nitrogen pulse decay permeability measurements, and SEM and casting thin-section analyses on 20 sandstone samples of the Shihezi Formation from 16 wells of the Sulige Gas Field in the Ordos Basin, China. The fractal dimensions of pores corresponding to two pore radius ranges, namely fractal dimensions [Formula: see text] and [Formula: see text], and those of throats also corresponding to two throat radius ranges, namely fractal dimensions [Formula: see text] and [Formula: see text], were then calculated using the constant-rate mercury injection data. Fractal dimensions [Formula: see text] and [Formula: see text] are negatively correlated with the average pore radius and pore volume as well as quartz content, and they are positively related to contents of clay minerals and lithic fragments. Compared with pore fractal dimensions, throat fractal dimensions have lower correlations with throat structural parameters, and show vague relations with mineral compositions. Although the effects imposed by mineral compositions upon throat structures are similar to those upon pore structures, the flake-like and curved shapes of throats result in irregularity of fractal dimensions. Tight gas sandstones, with smaller fractal dimensions [Formula: see text] and [Formula: see text], have larger effective porosity, indicating that more gas volumes can be replaced by liquids. As for tight gas sandstones with lower fractal dimensions [Formula: see text] and [Formula: see text], the effective gas permeability is relatively high. In such cases, gas can flow more easily through the reservoir.

New Insight into the Characteristics of Tight Carbonate based on Nuclear Magnetic Resonance

Abstract: In order to further our understanding of the physical properties of tight carbonate and to explore the use of NMR to identify different rock types. In this study, we used thin-section observations, SEM (scanning electronic microscopy) data, helium porosity, helium pulse decay permeability, MICP (mercury injection capillary pressure), and NMR (nuclear magnetic resonance) data to conduct petrographic and petrophysical characteristics of tight studies on 12 carbonate samples. Our results show that nano/micropores were widely distributed between the micrite and/or dolomite crystals. The correlation between the permeability and porosity of the tight carbonates was poor, while the rapex, which was the apex of the hyperbola in Pittman (1992), is well correlated with the threshold entry pressure, the maximum pore-throat radius, and the average pore-throat radius. Based on new cut-off values, we have identified three types of pores: nanopores, which mainly correspond to the intercrystalline pores; microp...

Effects of pore-throat structure on gas permeability in the tight sandstone reservoirs of the Upper Triassic Yanchang formation in the Western Ordos Basin, China

The effects of pore throat structure on gas permeability in tight sand reservoir were investigated using helium-measured porosity, pulse decay permeability, casting thin sections, scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), and constant-rate mercury injection for five sandstone samples from the Upper Triassic Yanchang Formation in the Western Ordos Basin, China. Results show that permeability values are in the range of 0.474–2.290 mD. The strong variation may be due to the effect of mineral composition and pore-throat structure. Generally, sandstone samples of higher content of quartz, chlorite film, and slit-shaped throat tend to have higher permeability. The movable fluid porosity numerically equals to the product of porosity and the movable fluid saturation based on the film bound water, which can comprehensively reflect the influence of fluid flow channels on porosity while neglecting the influence of bound fluids in the fine pores of clay minerals in the tight reservoirs. Larger movable fluid porosity values mean larger pore spaces for the movable fluids, which contribute to larger permeability. It is more reasonable to analyze the movable fluid pore-throat radius as a range. The homogeneous pore throat structure lead to a narrow lower limit range of the movable fluid pore-throat radius, which is favorable for the fluid flow. Meanwhile, if the lower bound of the lower limit range of the movable fluid pore-throat radius is small, pores and throats are less plugged, and thus make the conditions favorable for fluid flow. The contribution of throats to the pore volume is critical in influencing reservoir permeability as it can directly control the lower limit of the movable fluid pore-throat size. The pore-throat radius where throats account for the smallest amount in the pore space increases with the permeability, which indicates that larger proportions of large throats result in larger throat radius and higher pore connectivity, leading to higher permeability.

Imbibition characteristic of shale gas formation and water-block removal capability

Large scale hydraulic fracturing is one key technology for shale gas development. Thousands of liquids are pumped into shale formation. However, fluids flow-back rate is surprisingly low for same cases, which is always lower than 30%. The production is not influenced too much by the low flow-back rate and some of these wells even have higher productivity. This phenomenon cannot be interpreted by conventional theory, in which gas will be blocked seriously by the water. It indicates that shale formation has water-block removal capability. Experiments are proposed around this fracturing imbibition issue including water imbibition and solution conductivity online test, nuclear magnetic resonance tests with water imbibition and pulse decay permeability tests with water imbibition. The interaction between water and shale and the dynamic effect are analyzed to make clear the relationship between water imbibition and water block removal. Fracturing fluids are imbibed into the formation matrix and complicated physical and chemical effects happen between fluids and shale. There are huge differences between different shales including the imbibition capacity, diffusion capacity and ion exchange capacity. The imbibition capacity, diffusion capacity and fracture induced capacity are the main factors affecting water block removal capability. Pressure enhancement, Liquid diffusion into deeper matrix and micro-fracture induced by water-rock reaction are treated as the main mechanisms of water block removal through the study. A water block removal potential valuation methodology is proposed taking account the initial water saturation, imbibition capacity, diffusion capacity, fracture induced capacity and clay chemistry effect. The water block removal potential can be evaluated by the water imbibition, nuclear magnetic resonance and plus-decay permeability tests. A grading evaluation of typical shale gas formation is proposed based on this method. The work is the pioneer study analyzing the water block removal mechanism and controlling facts, and it is valuable to make clear the shale gas productivity factors and put forward guidance to shale gas reservoir stimulation.

Microstructural controls on reservoir quality in tight oil carbonate reservoir rocks

In carbonate reservoir rocks the complex interaction between the petrophysical properties corresponds to the various depositional microstructures which are modified by various diagenetic processes that ultimately define the reservoir quality, and pose challenges to the prediction of permeability. The permeability heterogeneity in the carbonate oil reservoirs of northern Iraq varies widely and is thought to be controlled by a number of different factors. In this work, controls of matrix permeability for the Cretaceous Kometan formation selected from five oil fields in Kirkuk embayment zone have been investigated. Helium porosity, helium pulse decay permeability, brine permeability, Nuclear Magnetic Resonance (NMR), Mercury Injection Capillary pressure (MICP), Scanning Electronic Microscopy (SEM), X-Ray diffraction (XRD), and photomicrography of thin section have been used to investigate the effect of microstructure on the variation of permeability in the Kometan Formation. The formation has porosities and permeabilities which range from 0.5 ± 0.5% to 29 ± 0.5% and from 0.65 ± 0.08 μD to 700 ± 0.08 μD respectively. Three types of pore systems have been investigated using pore type, pore size and pore-throat size as characterizing parameters. We have recognized three microstructural types: (i) matrix composed of nano-intercrystalline pores (pore diameter dp smaller than 1 μm and a nanoporous pore-throat size), (ii) matrix composed of micro-intercrystalline pores (1<dp < 10 μm with a corresponding micron-scale pore-throat distribution), and (iii) meso-intragranular and moldic pores (dp > 10 μm) also with microporous pore-throat radii. The nano-intercrystalline pore system is common across northern Iraq and represents the effective pore system type in the reservoirs of the Kirkuk embayment zone. For these tight carbonate reservoirs, the mineralogy, especially of quartz and clay minerals (illite and smectite), has little relationship with the measured Klinkenberg-corrected permeability. Consequently, mineralogy is not a useful controlling factor for permeability. Diagenetic processes have altered the depositional texture significantly, resulting in changes to the pore size and pore-throat size distribution and affecting the permeability. In addition the matrix permeability is sensitive to stress, with permeability decreases between −4 × 10−4 mD/psi and −4 × 10−5 mD/psi in the effective stress range from 0 psi to 4000 psi. It has been found that of the three microstructure pore types the nano-intercrystalline pore system is more sensitive to increasing effective stress compared to the micro-intercrystalline and meso-intragranular pore systems. Laboratory experiments have shown that stylolisation resulting from regional fluid movements has also affected matrix permeability, with the stylolites acting as barriers to fluid flow and considered to be an important source of tightness of the Kometan formation in the Kirkuk embayment fields.

Effect of Water Imbibition on Shale Permeability and Its Influence on Gas Production

Large volume water filtrates into the shale formation during multi-stage fracturing. The influence of water imbibition to shale permeability, which still needs further investigation, is crucial to gas production. This paper presents a series of experiments to investigate the shale permeability change during water imbibition in comparison to typical sandstone and volcanic samples using the pulse-decay permeability technique. The permeability greatly fluctuates with the water imbibed into the shale, which is far different from that of sandstone and volcanic rock. Factors such as water blocking, stress sensitivity, and clay swelling are discussed. Five typical permeability changes are put forward, which are conducive to understand the effect of water imbibition on gas flow post- fracturing. The work indicates that the shale permeability enhancement by water imbibition may be one of the reasons of obtaining shale gas well productivity to increase by soaking after fracturing. The results and conclusions are fu...

Gas flow mechanisms under the effects of pore structures and permeability characteristics in source rocks of coal measures in Qinshui Basin, China

The gas flow mechanisms in source rocks of coal measures under the effects of the pore structures and permeability characteristics were investigated by field-emission scanning electron microscopy, low-pressure nitrogen gas adsorption, high-pressure mercury intrusion, and pressure pulse decay permeability method. Various flow regimes were distinguished in the pores and fractures of differing scales, and the mass fluxes through the same were calculated using the data obtained by the numerical and experimental investigations. Results indicated that mesopores predominated in shale, while coal contained well-developed mesopores and macropores. In addition, the permeabilities of coal and shale were observed to be significantly anisotropic and highly stress dependent. The cross-sectional area proportions of the pores per unit cross-sectional area of the matrix in the free molecular, transition, and slip flow regimes in shale and coal were determined to be, respectively, 0.2:0.7:0.1 and 0.15:0.6:0.25. In the free molecular and transition flow regimes, the mass flux decreased with increasing reservoir depth, while the reverse was the case in the slip flow regime. Further, in the continuum flow regime, the mass flux was unimodally distributed with respect to the reservoir depth. The total mass flux in coal was greater in the direction perpendicular to the bedding compared to the direction parallel to the bedding, while the reverse was the case in shale. In addition, the continuum flow regime predominated in coal in both the directions perpendicular and parallel to the bedding, but only in the direction parallel to the bedding in shale. This work presents a comprehensive model for the analysis of all the flow regimes in pores and fractures of differing scales, as well as the anisotropy. Findings of the study are meaningful for establishing the coupling accumulation mechanism of the Three Coal Gases and developing a unified exploration and exploitation program.