Tight Rocks Research Articles

Visualisation and investigation of water retention in tight oil reservoir via real sandstone micro-models

Hydraulic fracturing is considered as an effective approach for the development of tight oil reservoirs. Unlike conventional reservoirs, after a large volume injection of the fracturing fluid, the flowback rate in tight oil reservoirs is considerably lower whereas the underlying mechanism explaining water retention remains unclear. Therefore, in this work, to investigate the water retention mechanism, fracturing fluid injection and particularly oil production process were emulated within real tight rock chips. Displacement and water retention events were directly visualised and captured using a microscope. As a result, the discrepancy between temporary and permanent residence of water inside the pore space was clarified. Additionally, nuclear magnetic resonance (NMR) scanning was incorporated to study the pore-scale fluid flow behaviours. Results show that a large portion of water was retained in smaller pores and water retention rate is positively correlated with oil recovery, implying invaded water replaced the oil and resided in the pore space therefore increasing the mobile oil in the formation as oil flowing back. This work proposed an interpretation of water retention mechanism in tight oil reservoir after hydraulic fracturing and provided an insight to optimise the development and production of tight oil reservoirs. [Received: January 20, 2020; Accepted: April 23, 2020]

A methodology to predict the gas permeability parameters of tight reservoirs from nitrogen sorption isotherms and mercury porosimetry curves

A methodology is suggested for the explicit computation of the absolute permeability and Knudsen diffusion coefficient of tight rocks (shales) from pore structure properties. The pore space is regarded as a pore-and-throat network quantified by the statistical moments of bimodal pore and throat size distributions, pore shape factors, and pore accessibility function. With the aid of percolation theory, analytic equations are developed to express the nitrogen (N2) adsorption/desorption isotherms and mercury (Hg) intrusion curve as functions of all pertinent pore structure parameters. A multistep procedure is adopted for the successive estimation of each set of parameters by the inverse modeling of N2 adsorption–desorption isotherms, and Hg intrusion curve. With the aid of critical path analysis of percolation theory, the absolute permeability and Knudsen diffusion coefficient are computed as functions of estimated pore network properties. Application of the methodology to the datasets of several shale samples enables us to evaluate the predictability of the approach.

Effect of Water Distribution on Spontaneous Imbibition of Tight Rocks: A Fractal Approach

The original water distribution characteristic plays an important role in the fracturing liquid retention in actual tight reservoirs. In this paper, an analytical model was proposed to characterize the water distribution and its effect on the spontaneous imbibition, based on the capillary tube model and fractal theory. Furthermore, the effect of the water film and the non-piston-like front related to the pore size are included in our model. The proposed model was successfully validated with the experimental results of core imbibition tests. Our work demonstrates that water distribution is influenced by displacement pressure and pore structure. For a small differential pressure, the porous media with richer large pores usually possesses a lower water saturation, and this difference will decrease with the increase of differential pressure. Moreover, compared with previous studies, the proposed imbibition model can not only distinguish the valid pores and invalid pores for imbibition but it can also predict the initial imbibition rate and equilibrium time of tight porous media with different water saturation. The results show that the equilibrium time is controlled by the minimum effective pore radius while the initial imbibition rate is mainly controlled by the large pores. Both of these two parameters will decrease with an increase of water saturation; the former is more sensitive to a low water saturation, while the latter decreases more quickly for a middle-high water saturation.

Study on Heterogeneity of Pore Throats at Different Scales and Its Influence on Seepage Capacity in Different Types of Tight Carbonate Reservoirs

The carbonate reservoirs in the middle Sichuan area have undergone complicated tectonics, resulting in various types of reservoir space, large secondary changes, and multiple complexities. Taking the tight carbonate gas reservoir of the Deng-4 member in this area as an example, based on casting thin sections, scanning electron microscopy, and high-pressure mercury injection experiments, the reservoir space and microstructural characteristics of the micropore throats were studied, and the influence of the microscale heterogeneity in different types of reservoirs on the seepage capacity was analyzed by applying fractal theory. The results showed that the reservoir space in the tight carbonate rock of the Deng-4 member in the study area could be divided into 3 types: pore-hole-fracture, pore-hole, and pore types. The distribution characteristics of the pore throat diameter were multimode wide type, double-mode high and low asymmetrical type, and single-mode concentrated type. The fractal dimension and seepage capability of the pore throat increased successively in sizes from less than 0.1 μm to 0.1~1.0 μm and greater than 1.0 μm. On the one hand, the development of karst caves and fractures controlled the percolation ability of tight carbonate reservoirs; on the other hand, it enhanced the heterogeneity of the micropore throat structure. However, the development degree of dissolved pores and microfractures has a weak contribution to the connectivity and seepage capacity of the reservoir space. Acidification, fracturing, and other measures can be adopted to enhance the connectivity between pores to improve the productivity of the gas reservoir. This study provides a scientific basis for the efficient exploration and development of tight carbonate reservoirs.

Low-Field Nuclear Magnetic Resonance Methodology for Analysis of Drill Cuttings from Unconventional Tight Reservoirs

A nuclear magnetic resonance (NMR)-based method was developed to quickly and accurately determine porosities and densities of tight reservoir rocks from drill cuttings. The method combines low-fiel...

Super basins—New paradigm for oil and gas supply

Super basins are sedimentary basins with more than 5 billion BOE cumulative production and at least 5 billion BOE remaining recoverable resources. Super basins are characterized by two or more source rocks, stacked reservoirs, mature infrastructure, established service sectors, large amounts of data, and access to markets. Super basins commonly have multiple operators that form a community whose competitive atmosphere helps drive efficiency and performance. In an effort to identify sources for future oil and gas supplies, studies of the geology, hydrocarbon richness, and above-ground factors for 400 global basins led to the super basin concept. Super basins have continuous organic-rich mud rocks and other tight reservoirs that heretofore were not considered commercial targets. Based on analogy with proven resource plays in North American super basins, it is now possible to unlock substantial hydrocarbon potential in these tight rocks by employing horizontal drilling and multistage fracturing technologies. Super basins exist both onshore and offshore. The largest super basins are onshore, dominantly in forelands and passive margins, and have both conventional and tight rock potential. This paper focuses on the top 25 onshore super basins that are estimated to have 859 billion BOE of incremental technically recoverable resources. Offshore basins do not have the massive tight rock potential as onshore basins because of higher infrastructure costs. The archetype for the onshore super basin is the Permian Basin (west Texas) with 37 billion BOE produced and 60 billion bbl of oil and 300 TCF gas remaining. With huge resources, super basins can serve as supply disrupters and act as a regulator for the global price of crude oil and natural gas. Super basin concepts have caused geoscientists to think differently about petroleum basins. Super basins should be viewed as ecosystems that have below- and above-ground questions and technology and market considerations that must be resolved to assure commercial success.

Quantitative Characterization, Classification, and Influencing Factors of the Full Range of Pores in Weathering Crust Volcanic Reservoirs: Case Study in Bohai Bay Basin, China

Weathering crust volcanic oil and gas reservoirs were revealed in the Bohai Bay Basin, and the physical properties changed considerably in different volcanic reservoirs. To understand better the pore structure of weathering crust volcanic reservoirs, it is important to characterize quantitatively the full-range pore size distribution (PSD). In this study, six Lower Cretaceous volcanic samples from the Bohai Bay Basin were measured by scanning electron microscopy, low-temperature nitrogen adsorption (LTNA), mercury intrusion porosimetry (MIP), and nuclear magnetic resonance (NMR) to uncover the full-range PSD of volcanic rocks. The results showed the following. Firstly, four types of pores were observed in the volcanic samples, and in ascending order of the pore size, these pores were devitrification pores, inter-crystalline pores, dissolution pores, and amygdales. Secondly, ink-bottle and slit-type nano-sized pores measured by LTNA generally accounted for 25% of the volcanic porosity, and in tight volcanic rocks with porosity lower than 5%, nano-sized pores accounted for more than 95%. Thirdly, LTNA was combined with NMR corrected by MIP to characterize the full-range PSD, and the pores were divided into three ranges according to boundaries of 0.05 and 1 µm, respectively. Fourthly, the clay-related inter-crystalline pores dominant in dacitic tuff and basalt reservoirs and the dissolution pores dominant in dacite and trachyte reservoir were characterized by “larger pores connected by narrow throats” and “honeycomb-like type,” respectively. Lastly, mafic minerals were prone to alteration under the weathering crust geological conditions, and the iron and magnesium ions promoted the spontaneous generation of clay minerals in the pores, thereby worsening the physical properties of the reservoir. Therefore, we propose that alkali-rich acidic volcanic lava is a favorable reservoir for oil and gas exploration.

Investigating the effects of stress creep and effective stress coefficient on stress-dependent permeability measurements of shale rock

Rock permeability is an essential factor for production prediction and economic evaluation, which is often measured based on core samples in laboratory. However, several phenomena such as stress creep and path-dependent stress still present difficulties in correctly measuring and interpreting permeability under varying compaction stresses for core measurements. In this study, an improved stress-dependent permeability model is proposed to consider the effect of time-dependent compaction behavior on permeability measurements by incorporating the stress creep mechanism. Besides, how to correctly interpret stress-dependent permeability results with effective stress coefficient is introduced in detail. A coupled flow-geomechanics model is also developed to investigate the impact of effective stress coefficient on permeability change and cumulative production. Due to the stress creep phenomenon, rock permeability could be significantly overestimated if not enough measurement time is provided. The creep strain is highly related to the content of clay and kerogen. This is because the increasing creep strain over time is mainly from the closure of pre-existed micro-fractures and the compression of Nano-pores inside the soft materials, such as clay and kerogen. The creep strain model and improved stress-dependent permeability model were validated by comparing with multiple experimental data. Effective stress coefficient cannot be simply assumed one for organic-rich or clay-rich shale reservoirs, especially when pore pressure is changed to alter net effective stress in permeability measurements. A large effective stress coefficient amplifies the sensitivity of pore pressure change on the variation of both effective stress and permeability. The simulation results show a larger effective stress coefficient could provide higher cumulative production because of stronger compression from effective stress. The improved knowledge of stress creep and effective stress coefficient enables the development of best practices for permeability measurement of tight rock and provides more accurate permeability results for reservoir management and field development.

Surfactant-EOR in tight oil reservoirs: Current status and a systematic surfactant screening method with field experiments

Tight oil reservoirs typically have an estimated ultimate recovery of less than 10% after hydraulic fracturing, where enhanced oil recovery (EOR) technique is needed. Comparing to the gas-EOR, the surfactant-EOR neither alters the current fracturing procedure nor requires special injection facilities, and thus can be economically-viable under the current environment of low oil prices. However, tight rocks have small pores and large specific surface areas, which can make the adsorption rate of surfactants significant and thus limit the penetration depth of surfactants and its enhancement on oil recovery. In the published studies on the surfactant-EOR for shales and other tight reservoirs, this key parameter is only measured with the crushed rock samples, which can be underestimated comparing to that in the intact rock. Moreover, the dispersion coefficient that determines the penetration speed of a surfactant has never been directly measured in the tight rock, and the potential interaction between the surfactant and the friction reducer has neither been studied. In this study, a new form of surfactants is introduced, in which the wettability-alteration surfactants are firstly synthesized into oil-in-water microemulsions and then diluted to a designed concentration in the fracturing fluid. The thermodynamically-stable structure of microemulsion can minimize the adsorption rate of surfactants when transporting in the tight rock. Using coreflood experiments with UV–vis spectroscopy, the adsorption rate and dispersion coefficient of this form of surfactants are directly measured in tight rocks with a range of permeabilities, which are key parameters to modeling the EOR process and further scaling up laboratory findings for designing a field operation. To ensure the success of the surfactant-EOR technique in the field, the chosen surfactant needs to pass the preliminary screening including the aqueous stability test, the emulsion tendency test, the oil-water IFT measurement, and the shearing test; besides, it is also crucial to examine the compatibility between the slickwater and the wettability-alteration surfactant with different electric charges, which is seldom reported yet. In the end, the chosen surfactant is tested in two pairs of horizontal wells on one pad site, whose flowback water is collected and analyzed for better understanding the behavior of this surfactant.

Evaluation of surface diffusion in microporous/mesoporous media using a numerical model applied to rate-of-adsorption data: Implications for improved gas permeability estimation in shales/tight rocks using drill cuttings

Adsorbed-phase surface diffusion has been recognized as an important controlling factor on gas apparent permeability in micropores and smaller mesopores. However, for the estimation of surface diffusion coefficients of shales, the commonly used empirical methods cannot account for the complexity of rock fabric in the matrix system of tight rocks. Further, the small sample sizes and amounts (<5 g) of drill cuttings, which are usually the only reservoir samples available from horizontal wells, significantly limit the feasibility and reliability of current experimental methods for the direct quantification of surface diffusion coefficients. The primary objectives of this study are therefore to: 1) establish an integrated experimental and modeling approach to evaluate surface diffusion and permeability using drill cuttings, and 2) investigate the significance of surface diffusion in different adsorbate/adsorbent systems. In this work, a bidisperse numerical model is developed to extract surface diffusion coefficients and permeability/diffusivity values from porous materials by matching the pressure transient data recorded during gas adsorption. A high-resolution gas adsorption apparatus is employed to measure gas sorption kinetics under low-temperature (N2, −196 °C; CO2, 0 °C), low-pressure (<0.1 MPa) conditions, using small amounts (<2 g) of powdered/crushed samples. The proposed model successfully matched rate-of-adsorption (ROA) pressure transient data on two synthetic micro/mesoporous materials (Activated Carbon and SBA-15) and five organic-rich shale samples. It was observed that surface diffusion is a dominant flow mechanism and enhances permeability/diffusivity in micropores and smaller mesopores. The new model improves upon the results of a previously-developed ROA model.

Diagenetic alteration, pore-throat network, and reservoir quality of tight gas sandstone reservoirs: A case study of the upper Paleozoic sequence in the northern Tianhuan depression in the Ordos Basin, China

The Sulige gas field in the Ordos Basin is the largest gas field in China. The studied area, the northern Tianhuan depression, is located west of the gas field and is considered as a potential gas-producing area. The complex diagenetic alteration history and its effects on the pore-throat network and reservoir quality of the tight gas sandstones are explained. The upper Paleozoic first member of the Shanxi Formation and eighth member of the Shihezi Formation tight gas reservoir rocks are composed of coarse- to medium-grained sandstones and are dominated by sublitharenites. The most important diagenetic factor for porosity reduction was compaction, followed by cementation. Diagenetic mineral phases include quartz overgrowth, calcite cement and replacement, and kaolinite cement and replacement, with minor heulandite and chlorite. Pressure dissolution of quartz grains and quartzite fragments is the main source of silica for the early and late quartz overgrowth cementation (formed mainly from 120°C to 140°C). The hydrolysis and alteration of volcanic material and mica flakes released some silicon, calcium, and aluminum ions. Calcium and carbon in calcite cements could be derived from surrounding mudstones. Calcite replaced the quartz overgrowths. The formation of kaolinite, as cement and replacements, was controlled by the interactions of silica, aluminum, pH, and temperature (140°C). Because of deformation of detrital components (mica flakes and ductile rock fragments) and diagenetic replacement, clear negative correlations between reservoir quality and contents of the diagenetic minerals are lacking. A complex and isolated pore-throat network was created by strong diagenetic transformation. Based on analysis of thin sections, three-dimensional x-ray micro–computed tomography, and constant-rate mercury injection data, the samples with relatively good reservoir quality (porosity >10% and permeability >0.5 md) are characterized by dissolution pores and primary intergranular pores and commonly contain more and larger pore throats both in volume (counts >1800 and size >0.02 per unit volume) and diameter (>1.20 μm) than the samples with poor reservoir quality. The intercrystalline pores of kaolinite are very widespread and considered favorable for oil and gas accumulation because some asphalt was found within these pores. This study may be used, by analogy, to better understand diagenetic factors controlling the formation of tight gas sandstone reservoirs and predict the development of pore-throat systems.

Frost Damage in Tight Sandstone: Experimental Evaluation and Interpretation of Damage Mechanisms.

Low-porosity tight rocks are widely used as building and engineering materials. The freeze–thaw cycle is a common weathering effect that damages building materials in cold climates. Tight rocks are generally supposed to be highly frost-resistant; thus, studies on frost damage in tight sandstone are rare. In this study, we investigated the deterioration in mechanical properties and changes in P-wave velocity with freeze–thaw cycles in a tight sandstone. We also studied changes to its pore structure using nuclear magnetic resonance (NMR) technology. The results demonstrate that, with increasing freeze–thaw cycles, (1) the mechanical strength (uniaxial compressive, tensile, shear strengths) exhibits a similar decreasing trend, while (2) the P-wave velocity and total pore volume do not obviously increase or decrease. (3) Nanopores account for >70% of the pores in tight sandstone but do not change greatly with freeze–thaw cycles; however, the micropore volume has a continuously increasing trend that corresponds to the decay in mechanical properties. We calculated the pressure-dependent freezing points in pores of different diameters, finding that water in nanopores (diameter <5.9 nm) remains unfrozen at –20 °C, and micropores >5.9 nm control the evolution of frost damage in tight sandstone. We suggest that pore ice grows from larger pores into smaller ones, generating excess pressure that causes frost damage in micropores and then nanopores, which is manifested in the decrease in mechanical properties.

Coupling Between Poromechanical Behavior and Fluid Flow in Tight Rock

Proper characterization of the mechanical and flow properties of participating rock formations is crucial for subsurface geo-energy projects, including hydrocarbon extraction, geologic carbon storage, and enhanced geothermal systems. Application of mechanical and hydraulic pressures changes the porosity of rock and modifies flow paths. For low-permeable or “tight” rock that mainly contains nanoscale pores and serves as the confining layer for underground storage operations, a significant change in permeability may occur due to a small change in porosity. The pore volume changes in nanoporous geomaterials are extremely difficult to measure directly, but can be assessed from the knowledge of the hydro-mechanical response. Experimental methods to measure the stress-dependent permeability and poroelastic parameters of fluid-saturated tight rock are introduced. Eau Claire shale, Opalinus clay (claystone), and Charcoal granite are selected as representative materials for tight rock and their pore structure and material properties are carefully investigated. The porosity–permeability relationship for tight rock is established by adopting a power-law dependence with the exponent value in the range of 15–17, thus being significantly larger than that for a porous reservoir rock. Consequently, even small perturbations of porosity can cause orders of magnitude changes in permeability possessing a risk on the sealing capacity of the tight formations.

Controls on Pore Structures and Permeability of Tight Gas Reservoirs in the Xujiaweizi Rift, Northern Songliao Basin

As significant components of tight gas reservoirs, clay minerals with ultrafine dimensions play a crucial role in controlling pore structures and permeability. XRD (X-ray diffraction), SEM (scanning electron microscopy), N2GA (nitrogen gas adsorption), and RMIP (rate-controlled mercury injection porosimetry) experiments were executed to uncover the effects of clay minerals on pore structures and the permeability of tight gas reservoirs, taking tight rock samples collected from the Lower Cretaceous Dengloukou and Shahezi Formations in the Xujiaweizi Rift of the northern Songliao Basin as an example. The results show that the pore space of tight gas reservoirs primarily comprises intragranular-dominant pore networks and intergranular-dominant pore networks according to fractal theory and mercury intrusion features. The former is interpreted as a conventional pore-throat structure where large pores are connected by wide throats, mainly consisting of intergranular pores and dissolution pores, and the latter corresponds to a tree-like pore structure in which the narrower throats are connected to the upper-level wider throats like tree branches, primarily constituting intercrystalline pores within clay minerals. Intragranular-dominant pore networks contribute more to total pore space, with a proportion of 57.79%–90.56%, averaging 72.55%. However, intergranular-dominant pores make more contribution to permeability of tight gas reservoirs, with a percentage of 62.73%–93.40%. The intragranular-dominant pore networks gradually evolve from intergranular-dominant pore networks as rising clay mineral content, especially authigenic chlorite, and this process has limited effect on the total pore space but can evidently lower permeability. The specific surface area (SSA) of tight gas reservoirs is primarily derived from clay minerals, in the order of I/S (mixed-layer illite/smectite) &gt; chlorite &gt; illite &gt; framework minerals. The impact of clay minerals on pore structures of tight gas reservoirs is correlated to their types, owing to different dispersed models and morphologies, and chlorite has more strict control on the reduction of throat radius of tight rocks.

Pore-Type Partitioning in Unconventional Tight Reservoirs: Impact on Formation Damage and Long-Term Production

SummaryWettability is an important petrophysical property, which governs irreducible fluid saturations, relative permeability, and fluid invasion in rocks. Unlike conventional reservoirs, which have relatively uniform pore surface properties, the concept of wettability is not clear in organic-rich tight reservoirs. These rocks do not only have a nanoporous system but also possess multiple pore types with different interfacial affinities. Previous studies have shown that the unconventional reservoirs consist of three major pore types: inorganic pores (assumed to be water-wet), organic pores (assumed to be oil-wet, controlled by organic matter and thermal maturity), and mixed-wet pores (controlled by organic-inorganic distribution) (Curtis et al. 2012).This study revisits the concept of pore-type partitioning in tight rocks. We propose and demonstrate a new workflow to evaluate pore partitioning. First, all the specimens were vacuum dried at 100°C for 6 days to remove the free fluids until the weight stabilized. Total porosity was estimated as the sum of residual liquid volume [using nuclear magnetic resonance (NMR)] and gas-filled volume [using helium high-pressure pycnometer (HPP)]. The companion specimens from two formations (Eagle Ford and Wolfcamp B) were subjected to multiple injection cycles: starting with imbibition, then counter imbibition, and finally step pressurization with the replacing phase. During this process, we used brine-then-dodecane and dodecane-then-brine as the injection fluid sequences. The companion samples were continuously monitored by both gravimetric and NMR measurements until equilibration. Relative fractions of both replaced and replacing phases were calculated from sample weights and pore-fluidvolumes.The new approach not only classifies the connected pore network into three categories—oil-wet,water-wet, and mixed-wet—but also quantifies their respective proportions. The mixed-wet pore is defined as the pore fraction, in which both oil and water can replace air under capillary suction. We observe that the behavior of mixed-wet pores is different among formations: they prefer brine over oil in Wolfcamp B shale, while they prefer oil over brine in the Eagle Ford Formation. Unlike conventional wettability assessments, from which an overall wettability is provided, the novelty of this method is to clearly classify different pore types and their distributions. The concept of fractional wettability is highlighted for organic-rich tight rocks, and the contribution of mixed-wet pores in relative flow is emphasized.Hydraulic fracturing is a necessary stimulation process for tight reservoirs, in which the usage of fracturing fluid can affect formation performance. During well completion, water blockage is more likely to happen in the Wolfcamp B Formation than Eagle Ford Formation. Due to the capillary preference of mixed-wet pores, the water blockage might aid the Wolfcamp Formation to boost initial production, however, at a later stage, damage the formation. The workflow thus is promising to fully describe the pore network in tight formations, in which pore-type partitioning is a more reasonable concept than wettability.

Revisiting the Concept of Wettability for Organic-Rich Tight Rocks: Application in Formation Damage–Water Blockage

Revisiting the Concept of Wettability for Organic-Rich Tight Rocks: Application in Formation Damage–Water Blockage

Hydrocarbon generation and expulsion of Middle Jurassic lacustrine source rocks in the Turpan–Hami Basin, NW China: Implications for tight oil accumulation

In recent years, new oil reservoirs have been discovered in the middle Jurassic tight mixed rocks of the Turpan–Hami Basin. However, the generation potential of the J2q2 source rocks remains poorly understood. Petrographic, petrological, and geochemical analyses were carried out to assess the quality of the J2q2 source and reservoir rocks. The hydrocarbon generation potential method was utilized to evaluate the hydrocarbon generation and expulsion potentials. The results indicated that the rocks can be classified as high-quality source rocks with a relative lower degree of maturity. The hydrocarbon bearing zones are classified as tight reservoirs (average porosity of 5.90% and permeability of 0.18 mD) with an average pore throat radius &gt;150 nm, which is higher than the cut-off pore-throat radius. The source rocks start to expel hydrocarbons when Ro% is 0.56%. Bulk hydrocarbon generation and expulsion intensities in the center of the study area were calculated with the values of 900 × 104 t/km2 and 400 × 104 t/km2, while the weights of these hydrocarbons were 48.8 × 108 t and 27.3 × 108 t, respectively. The tight oil reservoir-forming conditions are superior, and the hydrocarbon generation and expulsion intensities are more remarkable in controlling the tight oil distribution. This study provides an important example for the Jurassic source rocks in Western China, and indicates that middle Jurassic lacustrine source rocks deserve attention in future exploration.

Experimental quantification of formation damage caused by the cross-linked gel in tight gas reservoirs

Evaluating the formation damage in tight rocks caused by the cross-linked gel is essential to estimate the hydrocarbon production after hydraulic fracturing. However, the steady-state measurement using the conventional core flooding experiment can be time-consuming in tight rocks with permeabilities below 0.01 mD. In this study, the pressure transmission test, an unsteady-state measurement, was applied to quantify the formation damaged caused by the cross-linked gel after fracturing. The potential damage mechanism was studied using the scanning electronic microscope, wettability tests and imbibition tests. Besides, the particle size of the gel residue was analyzed, and the impact of gel on the wettability of the rock surface, surface tension, and imbibition of the fracturing fluid was evaluated to understand the cause of formation damage by the gel. Results showed that the permeability depends on the pore-throat size rather than the pore-body size in the tight rocks. The content of illite is high, which is sensitive to the aqueous phase and pressure. The average permeability damage is 12.6% after the filtered fracturing fluid invasion. The particle in the pore can be observed through the SEM. The manuscript provides a new method to evaluate the formation damage induced by the cross-linked gel fracturing fluid in tight gas reservoirs.

Genesis of solid bitumen

This paper presents a new schematic model for generation and timing of multiple phases of solid bitumen throughout the continuum of organic matter maturation in source and tight reservoir rocks. Five distinct stages in the evolution of solid bitumen are proposed: (1) diagenetic solid bitumen (or degraded bituminite), which is not a secondary maceral resulting from the thermal cracking of kerogen. Instead it is derived from degradation of bituminite in the diagenesis stage (Ro < 0.5%); (2) initial-oil solid bitumen, is a consolidated form of early catagenetically generated bitumen at the incipient oil window (Ro ~ 0.5–0.7%); (3) primary-oil solid bitumen is derived from thermally generated bitumen and crude oil in the primary oil window (Ro ~ 0.7–1.0%); (4) late-oil solid bitumen (solid-wax) is derived from the waxy bitumen separated from the mature paraffinic heavy oil in the primary- and late-oil windows; and (5) pyrobitumen, which is mainly a non-generative solid bitumen, is evolved from thermal cracking of the remaining hydrocarbon residue and other types of solid bitumen in the dry gas window and higher temperature (Ro > 1.4%). This model shows concurrence of multi-populations solid bitumen with oil, bitumen, and other phases of fluid hydrocarbon residue during most of the maturity continuum.

Headspace Isotope &amp; Compositional Analysis for Unconventional Resources: Gas in Place, Permeability and Porosity Prediction and Completions Planning

Cuttings/cores’ Headspace Isotope and Composition Analysis (HICA) provides an effective way to calculate the nano pore throat size and distributions much like nitrogen and CO2 adsorption BET/BJH analysis, and it could also provide information about the original pore pressure or gas in place. Tight gas and oil storage is different from conventional where a majority of oil and gas are stored in nanometer sized pores (nanopores). Therefore the nanofludics, i.e., nanometer scale capillary sealing and opening in nanopores of tight rocks, plays a key role in overpressure conservation and storage of oil and gas, and also the fracing process involves the opening of the nano pore capillary seals through rock-fluid interactions. The rock-fluid nanofluidics interactions during fracing could also be studied through HICA and the results could help the optimization of fracing designs.