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A large percentage of tight oil is trapped underground due to the lack of effective enhanced oil recovery methods. Direct current (DC) voltage flooding has become one of the emerging and promising methods for in situ enhanced oil recovery because of its economic and environmental advantages. Nevertheless, the effect of DC voltage on the enhanced oil recovery for tight sandstone reservoirs is still unclear. In this study, the effects of DC voltage, the concentration of brine water and flooding styles on enhanced oil recovery have been investigated. The experimental results show that there are an optimum DC voltage (∼10V) and an optimum concentration of brine water (∼0.7 mol/L). The oil displacement efficiency with the DC voltage (∼10V) increases by 50% compared with that the oil displacement efficiency of the conventional flooding with 0.1 mol/L sodium chloride. A low concentration of brine water would increase the oil displacement efficiency when the DC voltage is applied, while a high concentration of brine water would reduce the oil displacement efficiency. Moreover, the results of different flooding styles indicate that the sequential flooding obtains more oil than the simultaneous flooding and conventional flooding under the condition of a relatively high concentration of brine water. Several mechanisms of electrokinetics have been revealed in this study. Laboratory experiments indicate that electrokinetic flooding would be a promising enhanced oil recovery technique and needs to be investigated further. • The effects of DC voltage, concentration of brine water and flooding styles on EOR have been investigated. • The DC voltage can augment the displacement efficiency and boost the movement of oil. • An optimum DC voltage was measured at 10 V, and an optimum concentration of brine water was measured at 0.7 mol/L. • The performance of the flooding styles is related to the concentration of brine water. [ABSTRACT FROM AUTHOR]

Permeability is a vital petrophysical parameter in reservoir evaluation and productivity prediction. In this study, a new method is presented to estimate permeability in tight sandstone using integral transforms of the NMR echo data. Different permeability indicators are directly computed from the NMR echo data using integral transforms without obtaining T 2 distributions by inversion of the echo data which is usually an indispensable part in traditional NMR-based methods for permeability estimation. The forms of these permeability indicators are controlled by the parameter n. Furthermore, new empirical models are developed based on the permeability indicators to estimate the permeability of tight sandstone. Different from the fixed permeability characterization parameters used in traditional models, in the new models, more suitable parameters can be selected to characterize the rock permeability by optimizing the parameter n. The numerical simulation results show that the integral transform method is simpler, more stable, and more accurate than the traditional T 2 inversion-based methods for permeability indicator computation and is still effective for low signal-to-noise ratio echo data. The core experiments and permeability estimation results indicate that the proposed method is superior to the traditional Schlumberger-Doll Research (SDR) method for permeability estimation in tight sandstone. • A new method is presented to estimate rock permeability using integral transforms of the NMR echo data. • Different permeability indicators were directly computed from the NMR echo data using integral transforms. • The new method can effectively estimate permeability of tight sandstone even if the NMR echo data is at low SNR. [ABSTRACT FROM AUTHOR]

The Lower Cretaceous Bashijiqike Formation in Kuqa depression belongs to a continental red bed sandstone with poor reservoir quality, and is deeply buried to 5.5–7.0 km but some successions can host porosity >10% and permeability larger than 10 mD. Carbonate cements are important pore-filling constituents, and they control the reservoir quality and heterogeneity of Bashijiqike sandstones. Red hematite-bearing grain-coating clay minerals inhibit the pore occluding quartz cements and preserve intergranular pores. Here we investigate the ability of grain-coating clays to inhibit carbonate cements. Thin sections, scanning electron microscopy (SEM), X-ray diffraction (XRD), and cathode luminescence (CL) analysis were performed to investigate the petrography, pore systems, diagenesis and diagenetic minerals of the red bed sandstones. The results show the hematite-bearing grain coatings give the "red bed" colors of the sandstones. The sandstones are heavily mechanically compacted, and the predominant pore-filling cements include carbonates and clay minerals, while quartz cements are volumetrically not important in reducing porosity. The grain-coating clays are mainly hematite-bearing mixed-layer illite and smectite. The paragenetic sequences of various types and generations of diagenetic events were reconstructed. Sandstones containing effective mixed-layer illite and smectite coatings, in which the intergranular pores can be preserved, have high porosities. Carbonate cement is never found in sandstones with effective grain coating clays, and carbonate cement precipitates where there are no sufficiently thick and continuous grain coats. The clay coatings retard or inhibit eogenetic calcite cements and progressively restrict late-stage carbonate (dolomite) cementation during burial. The hematite-bearing grain-coating clays help the red bed sandstones retain good reservoir quality at great depths. • The diagenesis, diagenetic minerals of the red bed sandstones are investigated. • Carbonate cementation in red beds can be inhibited by grain-coating clays. • Red hematite-bearing grain-coatings help retain good reservoir quality at great depth. [ABSTRACT FROM AUTHOR]

Ultrasonic P-wave attenuation was measured in tight oil siltstones, carbonates and a tight sandstone with two independent estimation methods. The dependence on saturation in gas-water partially-saturated siltstones at in-situ conditions shows a different behavior compared to the other rocks. The siltstones in our experiments exhibit a behavior characterized by a gradual decrease of attenuation with increasing water saturation in the presence of gas, and full-gas saturation shows more attenuation than full-oil and full-water saturations. However, previous theoretical and experimental studies show that gas-water saturated carbonates and sandstones have the highest attenuation at high water saturations, and generally, a liquid-saturated rock shows more attenuation than a gas-saturated one. Poroelasticity theory shows that the two dominant loss mechanisms (due to fabric heterogeneity and patchy saturation) have peaks at different frequencies for siltstones, resulting in a gradual decrease of attenuation with water saturation, while these mechanisms overlap at ultrasonic frequencies for carbonates and sandstones, leading to an attenuation peak at high water saturations. The predicted attenuation dependence on fluid type agrees with the measurement for most samples. Regarding the tight oil siltstones, although the model fails to explain the experimental results for oil-water saturation, it can be concluded that for gas-water saturation the squirt flow caused by fabric heterogeneity dominates the attenuation, which differs from carbonates and sandstones. Experimental studies show that the attenuation dependence on saturation in tight oil reservoirs can be associated with fabric texture. The theory describes these behaviors, which can potentially improve the practices of detecting and monitoring multi-phase fluids in the reservoirs. • Ultrasonic P-wave attenuation decreases with water saturation in in-situ water-gas partially-saturated siltstones. • Attenuation behavior with fluid type and saturation in tight oil siltstones differ from those of carbonates and sandstone. • Poroelasticity modeling explains the observed phenomena in water-gas saturated siltstones. [ABSTRACT FROM AUTHOR]

Previous research has confirmed that substantial yield has been recovered in the soaking period after hydraulic fracturing. Spontaneous imbibition (SI) is the primary mechanism responsible for the enhanced oil production and has become an effective oil recovery method with regards to unconventional reservoirs. Despite the importance of SI, an in-depth understanding of the features of SI in tight reservoirs is still inadequate. In this article, nuclear magnetic resonance (NMR) T 2 was employed to study the dynamic behavior of imbibition in tight sandstone samples from Yanchang formation, Ordos Basin. Additionally, high-pressure mercury intrusion (HPMI) and the initial T 2 of a core sample were combined to characterize pore structures of tight rocks and oil distributions in various pores at different imbibition stages. Then, the effects of gravity, anisotropic pore structure, and non-wetting phase (NWP) viscosity on imbibition recovery were determined via the variations in T 2 spectra for each sample. The results show that the tight cores feature a multiscale pore structure. Sub-micropores is the dominant type providing the major contribution to oil recovery, while nanopores have largest imbibition efficiency due to the larger capillary force. Gravity of fluids has a non-trivial effect on SI and cannot be neglected in tight samples under two-ends-open (TEO) or one-end-open (OEO) conditions; this seemingly counterintuitive finding is because the capillary force is weakened by the resistance force caused by the intricate flow paths and other possible surface forces at the nanoscale. Imbibition performance in a tight medium is strongly related to its pore structure. The variations in directional permeabilities, relative permeabilities and capillary pressure functions resulting from highly anisotropic samples greatly affect both the ultimate oil recovery and imbibition rate for tight samples under TEO condition, but only impact imbibition rate under all-faces-open (AFO) condition. Furthermore, because tight oil has a narrow range of viscosity, the imbibition behavior in tight samples may not be sensitive to the oil viscosity. It would be hoped that the insights gained from this study can help to improve our understanding of imbibition characteristics in tight reservoirs and develop new scaling models for the predication of oil recovery. • Multiscale pore structure of the tight oil sandstone and its oil distribution were characterized. • The effect of gravity on SI in tight rocks was discovered. • The imbibition characteristics in samples with anisotropic pore structure were investigated. • The effect of NWP viscosity on SI was also explored. [ABSTRACT FROM AUTHOR]

Oil-Brine-Rock interaction appears to be an important physiochemical process, which governs multiphase flow and residual oil saturation during low salinity waterflooding in sandstone reservoirs. While it appears that electrostatic adhesion of oil polar components on clay edges and basal planes regulates oil-brine-rock interactions, relative contribution of adhesion on edge and basal planes remains unclear, thus presenting a substantial impediment to model and predict the low salinity effect. We thus coupled PEST and PHREEQC to model the quinoline adhesion against RezaeiDoust et al.,'s (Energy Fuels 2011, 25, 2151–2162) kaolinite-quinoline adsorption experimental data. We matched the experimental data by examining the adsorption capacity of quinoline on kaolinite basal and edges planes simultaneously. Our new calibrated model shows that basal adsorption (>Na + BaseH+ = >BaseH + Na+) dominates quinoline adsorption at low pH (pH = 5). Rather, edge adsorption controls adsorption mechanism at high pH (pH = 8). Furthermore, the model shows that salinity plays a minor role in adsorption at a controlled pH system. Our new model quantifies the relative contribution of basal and edge planes on basic component adhesion thus wettability at different pH and salinity, providing insights and new geochemical data to existing geochemical database, thereby better model and predict the wettability alteration during low salinity waterflooding. • Basal plane (>Na + BaseH+ = >BaseH + Na+) dominates quinoline adsorption at low pH (pH = 5). • Edge plane controls quinoline adsorption at high pH (pH = 8). • Relative contribution of basal and edge plane on basic component adsorption has been quantified. [ABSTRACT FROM AUTHOR]

The Upper Ordovician glaciogenic deposits are thought to have an important quantity of hydrocarbon across North Africa. Insight is provided about the IV-3 reservoir unit in the In-Adaoui-Ohanet field in the Illizi basin of south-east Algeria. The aim is to: 1) describe the lithofacies; 2) interpret the depositional environment; 3) describe the petrographic characteristics; 4) investigate the petrophysical properties; and 5) perform a biostratigraphic analysis of the unit IV-3 reservoir (Upper Ordovician) in the In-Adaoui-Ohanet field based on the core description and samples collected from the well IA-115. Lithofacies described in the study area are MT1, MT2, MT3, MT6, and MT9. Subglacial tillite is the depositional environment associated with lithofacies MT3, MT6, and MT9. These lithofacies are thought to be deposited medial to a distal fan, whereas lithofacies MT1 and MT2 are thought to be deposited in high-energy flows. Acritarch and Chitinozoan species are the most common biozones described in the study reservoir and they are thought to be affiliated with an Upper Ashgilian stage. Petrographic analysis shows that the study reservoir unit is formed by fine to coarse-grained sandstone. Quartz is considered to be the principal framework mineral (mean, 56.30%). Cementing minerals observed in this reservoir unit are quartz and carbonate. From a compositional point of view, the unit IV-3 reservoir in the In-Adaoui-Ohanet field is predominantly formed by quartz arenites, which are considered to be mature. Additionally, the tectonic setting of these arenites is most likely associated with a passive margin origin. The emphasis throughout this study is on the role of factors such as permeability, carbonate cement, and quartz overgrowth on the reservoir quality of unit IV-3 in the In-Adaoui-Ohanet field. The quality of this reservoir unit is highly influenced by the quartz overgrowth and pores that are plugged by carbonate cement, which dramatically reduces the pore network. An enhanced porosity was observed only in the MT3lithofacies (up to 22.3%). Additionally, from an economic point of view, the study reservoir unit is classified as a tight gas-bearing reservoir. • Glaciogenic deposits constitute reservoirs for hydrocarbons in sedimentary basins across the globe, with reservoir ages ranging from Neoproterozoic to Pleistocene. • The various glaciation episodes from the initial pre-glacial situation to the post-melting phases are recorded in the Upper Ordovician and Lower Silurian sequences from West and North Africa. • The quality of the Ordovician reservoir is mainly controlled by: mechanical and chemical compaction, fibrous illite content, quartz cementation, grain size, extent of clay coatings, availability of silica source, and the presence of heavy hydrocarbon to slow the rate of quartz cementation. • Five lithofacies associated to a high hydrodynamic flow system were described. Each lithofacies is composed of: (MT2) heterometric sandstone, (MT1) pebble log, shaly sandstone matrix at the base overlain by trough cross bedding medium sand (MT6) and layers with oblique lamination (MT3) or without bedding (MT9); respectively. [ABSTRACT FROM AUTHOR]

Fracture-based wellbore strengthening is a widely used preventive technique for lost circulation control. However, there were limited experimental studies on wellbore strengthening with an anisotropic stress state. In this paper, we describe an experimental investigation of fracture-based wellbore strengthening on cubic Berea sandstone samples (size of 12 in 3) using a large-scale true triaxial cell. The true triaxial cell allows fracture containment to simulate wellbore strengthening, which was not available using a traditional small-scale traixial cell. We used drill cuttings and Chevron loss prevention material (LPM) as wellbore strengthening materials (WSM). Three independent stresses were applied on the rock samples and bi-wing fractures were generated. The final fracture reopening pressure (FROP) exceeded the formation breakdown pressure (FBP) after plugging the WSM. Further comparison between the experimental results and modeling results from a numerical model shows a good match for the injection pressure profile. • Experimental investigation of fracture-based wellbore strengthening was conducted on a large-scale true triaxial cell. • Fracture reopening pressures were higher than formation breakdown pressures. • Results of induced and plugged fractures were shown. • Stress redistribution was observed with plugging of wellbore strengthening materials. [ABSTRACT FROM AUTHOR]

Spontaneous Imbibition (SI) is an important mechanism of enhancing oil recovery in tight oil reservoirs. Predicting core-scale oil flow rate by water imbibition from the pore-scale SI modelling is challenging due to the wide distributions of nano- and micro-pores in tight sandstone and huge amount of calculation of upscaling pore-scale modelling results for core-scale prediction. A semi-analytical mathematical model of characterizing co-current SI of water into oil-saturated tight sandstone has been proposed in this paper based on the capillary tube model and fractal theory. The non-uniform of water imbibition front due to the different imbibition rate in different sizes of pores can be dynamically characterized. Connate water and residual oil are considered and treated as immovable boundary-layers and coupled into the tortuous capillary tube model. The proposed model has been validated with the experiments results of core imbibition tests from literature. The key parameters of pore structures and fluid properties influencing imbibition flow rate have been quantitatively analyzed and identified. • A fractal model for predicting co-current SI rate is proposed. • Core-scale SI model coupled with pore-scale imbibition mechanism. • Connate water saturation and residual oil saturation are considered. • Key parameters influencing imbibition rate are identified. [ABSTRACT FROM AUTHOR]

Authigenic quartz is an important cementing material that can degrade storage capacity, whereas the effect of quartz cement on microscale pores and throats in tight sandstone is controversial. Therefore, it is crucial to verify the sources of quartz cement as well as the controls on microscopic storage. Toward this end, a variety of tests were performed on Permian Upper Shihezi Formation sandstones, and they are the vital exploration and development interval for gas in the northern Ordos basin. We found that quartz cement is the most abundant interstitial mineral in the Upper Shihezi Formation tight sandstones, which forms at approximately 55 °C to 188 °C with a continuous process. All the samples can be divided into pore dominated and throat dominated types, and there is an increase in micropores and a decrease in macropores as the quartz cement content decreases. Chemical compaction and transformation of clay minerals were the main sources of silica. This work shows that although quartz cement would occupy the void space and lead to a loss of porosity, it could retard the compaction and preserve the pores, which is attributed to the limited compressibility of quartz cement supported rocks. Thus, the difference in the pore radius and throat radius is diminished, resulting in the decrease in pore-throat size heterogeneity in tight sandstones. • Chemical compaction was expected to be the most significant silica source. • Quartz cement can reduce the porosity but retard the mechanical compaction. • The combination of pore and throat threshold radius can better appraise quartz cement. [ABSTRACT FROM AUTHOR]

As the first external liquids that are introduced into a reservoir rock, suitable drill-in fluids not only prevent phase trapping-induced permeability reduction (also referred to as phase trapping damage) caused by the drill-in fluid itself but also minimize any phase trapping damage caused by the invasion of subsequent working fluids. An ultra-deep tight sandstone reservoir in the Tarim Basin, NW China is considered as a case study, and this paper presents the results of an extensive series of phase trapping damage investigations that were carried out to determine the permeability reduction in the reservoir rock that comes into contact with different working fluids during the processes of drilling, drill stem tests, completion and well tests. Both the pore microstructure and surface properties were also investigated. The experimental results showed that the integrated phase trapping damage ratio (PDR) of water-based drill-in fluids (WBDF)-organic salt completion fluids (PDR = 0.99) was greater than that of oil-based drill-in fluids (OBDF)-organic salt completion fluids (PDR = 0.88). The analysis suggests that the OBDF is more effectively in inhibiting the absorption of the filtrate of the completion fluids compared with WBDF. A procedure for reducing phase trapping damage by OBDF is presented, and a numerical simulation model is developed to validate the procedure. The results could be useful in understanding and selecting the best drill-in fluids and completion fluids to minimize phase trapping damage in ultra-deep tight gas reservoirs. • Novel method was developed to evaluate integrated phase trapping damage considering drilling, DST, completion and well tests. • A systematic study of the phase trapping damage factors of ultra-deep fractured tight sandstone gas reservoir was presented. • A procedure for reducing phase damage by OBDF is presented and validated by numerical simulation modelling. [ABSTRACT FROM AUTHOR]

The Upper Triassic Yanchang Formation Chang 6 Member (C6 Member) in the Ordos Basin is the typical crude oil-rich sandstone in China, and its density restrict the exploration and development potential of hydrocarbon as well as their evaluation accuracy. Reservoir characteristics was studied using thin section (TS) associated with particle and pore size image analysis, X-ray diffractions, scanning electron microscopy (SEM) and mercury intrusion porosimetry (MIP). Time was taken as the main axle combined with diagenetic history, burial history, thermal history and structure. Thus, formation mechanism of tight reservoir was discussed by building the porosity evolution model and calculation method using "diagenesis simulation" and "geological effect simulation". Results show that after strong evolution and reconstruction, micro-nano pore throat system has developed and ultralow-low porosity-super low permeability tight sandstone reservoir has formed. Porosity evolution of Well H53 of C6 Member has revealed the correlations between the hydrocarbon charging and the porosity. Tight sandstone reservoir quality is affected by the maximum intergranular point-counted porosity, maximum compaction rate, maximum cementation rate, pore evolution of sample and the oil saturation, reasons for the formation of tight sandstone reservoir as well as its quality have been found out. • The microscopic properties in Upper Triassic Yanchang Formation reservoirs show distinct characteristics. • Diagenesis are the key factors differentiating reservoir quality. • The reservoir qualities of tight sandstones are dominated by porosity evolution pathways and hydrocarbon filling sequences. • The condition of residual porosity more than 10% before hydrocarbon filling is in favor of hydrocarbon accumulation. [ABSTRACT FROM AUTHOR]

Abstract This paper reports measurements of relative permeability to methane (CH 4) and carbon dioxide (CO 2) in hydrate-bearing sandstone core samples. The CH 4 (or CO 2) permeability was measured at reservoir conditions for different hydrate and brine saturations. The saturation span ranged from 0.18 to 0.60 (frac.) for CH 4 gas and from 0.37 to 0.70 (frac.) for liquid CO 2. The hydrate saturation ranged from 0.18 to 0.61 (frac.). The growth of hydrates within sandstone pores reduced the permeability for both the CH 4 and CO 2 system significantly, and the relative reduction was more pronounced for lower gas saturations. This effect is currently not included in numerical models of relative permeability in hydrate-bearing sediments and should be considered. The reported measurements are relevant to production-forecasting of methane gas from hydrate reservoirs and CO 2 storage schemes where CO 2 hydrates may provide self-sealing in cold aquifers. Highlights • Measurements of relative permeability to CH 4 and CO 2 in hydrate-bearing Bentheim sandstone cores at reservoir conditions. • The relative permeability to CH 4 (or CO 2) decreased when hydrate formed in the pore space. • No correlation between permeability and hydrate saturation was found for constant CH 4 (or CO 2) saturation. [ABSTRACT FROM AUTHOR]

Abstract Understanding the interactions between the injected enhanced oil recovery (EOR) fluids and sandstone reservoir rock minerals during the flooding processes requires special attention due to the presence of several types of highly reactive clays and non-clay minerals with different concentrations which interact with the injected non-native solutions and affect the effeciency of the oil recovery process. In this study, four coreflood experiments were carried out using two different sandstone core samples namely Gray Berea and Gray Bandera sandstone having clay contents of 8 wt% and 12 wt%, respectively, to evaluate the integrity of the clayey sandstone rocks flooded with 5 wt% and 10 wt% EDTA solutions with pH of 12. To study the presence and distribution of the clay and non-clay minerals into these sandstone rocks, x-ray diffraction (XRD), scanning electron microscope (SEM), and nuclear magnetic resonance (NMR) were used to characterize the core samples before the coreflooding tests. After the coreflooding experiments, XRD analysis was used to identify the precipitated minerals, and the alteration in the flooded rocks integrity was investigated through application of NMR, computed tomography (CT) scan analyses, and permeability measurements. The exchangeability of the chelated iron from the sandstone rocks to the EDTA solutions was studied by analyzing the produced effluents through inductively coupled plasma (ICP) analyses. The pressure drop observed during the coreflooding experiments revealed the compatibility of the injected solutions and the core samples. The results of this study dominates that Gray Berea sandstone is compatible with the 5 wt% and 10 wt% of the EDTA solutions as confirmed by the permeability measurements, CT scan analysis, NMR results, and the pressure drop during the flooding tests; which indicates that there was no fine migration, clay minerals swelling, and/or non-clay minerals dissolution caused by the interaction of Gray Berea with the EDTA solutions. On the other hand, Gray Bandera core samples were found to exhibit incompatibility with a solution of more than 5 wt% of EDTA as indicated by the CT scan and the high permeability enhancement because of the interaction of EDTA with ankerite mineral. Highlights • The integrity of two different sandstone core samples flooded with EDTA solutions was evaluated. • The relationship between the increase in oil recovery and the chelated iron was studied. • The effect of the iron source in the integrity of the sandstone reservoirs was investigated. [ABSTRACT FROM AUTHOR]

Abstract Permeability stress sensitivity and aqueous phase trapping have significant effects on the gas well production. An experimental study was conducted to investigate the individual and the combined impacts of the increasing effective stress (i.e., permeability stress sensitivity effect) and the formation water saturation (i.e., aqueous phase trapping effect) on the permeability of the rock samples obtained from two different tight sandstone gas formations. Results have shown that increasing effective stress and near well formation water saturation can both cause significant formation damage. Moreover, we have found that the increasing water saturation made the rock more susceptible to damage due to the permeability stress sensitivity. Similarly, as the effective stress increased, the degree of the formation damage due to the aqueous phase trapping also increased. Overall, the mutual interaction between the permeability stress sensitivity and the aqueous phase trapping synergetically created even higher formation damage effect. From the field operation point of view, both the proper selection of the drawdown pressure across the completion and the use of the suitable aqueous phase trapping removal techniques are equally critical for sustaining the productivity of the tight sandstone gas wells at the economical level in the middle and the later stages of the field development. The use of a single solution approach towards the remedy of only one of the two effects may not improve the gas well productivity very effectively. Highlights • Investigate the individual and combined impacts of permeability stress sensitivity and aqueous phase trapping. • Permeability stress sensitivity and aqueous phase trapping synergetically created even higher formation damage effect. • Decreasing pore throat size (increasing permeability stress sensitivity and aqueous phase trapping) caused formation damage. [ABSTRACT FROM AUTHOR]

Abstract Genetic type, source, charging history and reasons for secondary biogenic transformation of tight sandstone gas in the Linxing area in China's Ordos Basin have been studied through a combined analysis of gas compositions, isotopes of alkane and carbon dioxide, fluid inclusions and basin simulation. Tight sandstone gas in this area is predominated by methane, and the dryness coefficient is between 0.864 and 0.997 (average = 0.969). The δ13C 1 values of methane and ethane in this area range from −44.5‰ to −33.2‰ (average = −39.4‰) and from −27.5‰ to −24.4‰ (average = −25.9‰), respectively. The non-hydrocarbon gases are nitrogen, followed by carbon dioxide and argon, and δ13C of carbon dioxide ranges from −14.6‰ to 8.6‰. The homogenization temperatures of gas and gas-liquid inclusions in P 2 s and C 3 t in Linxing range from 80 °C to 170 °C, which are concentrated at 120–130 °C. The identification of gas origin indicates that tight sandstone gas is coal-type gas, which is mainly due to thermal evolution, followed by the mixing of secondary biogenic gas. Geological conditions and gas geochemical characteristics suggest that tight sandstone gas was produced by coal seam and carbonaceous shale in Upper Paleozoic in the Linxing area. The homogenization temperature of inclusion reflects the continuous accumulation process of tight sandstone gas, and the Cretaceous was the main period for gas charging. The monoclinal structure, maturity of source rocks and activity of underground water in this area are the important factors for secondary biogenic gas formation. Highlights • First data on composition and isotopic analyses of gases from Linxing, Ordos Basin. • The C 3 t and P 2 s gases were derived from C 3 t-P 1 s source rocks. • The Cretaceous is the main period for gas charging. • Thermal genetic gas has been transformed by microorganism. [ABSTRACT FROM AUTHOR]

Abstract Multiphase displacement in tight sandstone is fundamental and critical for tight oil production. Micropores dominate the pore space in tight sandstone. Microscopic mineral components in micropores substantially influence the multiphase displacement behavior. Pore size distribution exhibits a self-similar or fractal property, similar to inorganic mineral grains. Utilizing fractal theory eases the rebuilding of the flowing space and calculation of relative permeability. As an improvement of previous work, we successfully extended the 3D intermingled fractal model (3D IFM). The extended 3D IFM can evaluate multiphase flow behavior in tight sandstone, considering fractal characteristics of pore size distribution and mineral grain distribution. The fractal information of pores and mineral properties are obtained by scalable scanning electron microscopy (SEM) and energy dispersive spectroscopy(EDS) images, respectively. This method is useful and reliable for calculating relative permeability and residual saturation. The method is also successfully used to evaluate the influence of oil-water viscosity ratio, mineral components and formation depth on multiphase displacement behavior, proving its convenience and potential in rapidly evaluating multiphase displacement behavior in tight sandstone. Highlights • Developed a 3D intermingled fractal model suitable for tight sandstone. • Introduced probabilistic capillary connectivity method into multiphase calculation. • The provided model is convenient and promising for multiphase behavior investigation. [ABSTRACT FROM AUTHOR]

Abstract When sandstone rocks are exposed to CO 2 -saturated brine, their transport and mechanical properties can change due to brine/CO 2 -induced chemical reactions. The present study investigates the change in the flow-through characteristics, porosity, and the mechanical behavior of Mt. Simon Sandstone samples caused by exposure to brine/CO 2. The cores, extracted from a depth interval of 2110.4–2111.4 m (6924–6927 ft) in the Mt. Simon formation, were first characterized for their mechanical and transport properties, and then aged in CO 2 -saturated brine at pressures of 17.24 MPa (2500 psi) and temperature of 50 °C for one to two weeks. Following that, the changes in the transport and mechanical properties of the samples were analyzed using He pycnometry, flow perporometry and triaxial testing. Our experiments show that the porosity of the Mt. Simon samples slightly increases after exposure to CO 2 /brine, while the permeability increases more substantially depending on the stress state. Measurements of the flow-through pore size distribution (PSD) are indicative of the changes occurring and are consistent with the observed increases in permeability. Nitrogen adsorption tests (BET), before and after incubation, show a significant loss of pore volume in the mesoporous range that is indicative of clay dissolution. Weakening of the materials was observed based on the mechanical properties studied, a result that is consistent with the observed dissolution of clays that play a central role in the cementation of the quartz grains. Finally, the analysis of the brine compositions reveals an increase in concentration of most cations after incubation with the Mt. Simon cores. This is also consistent with mineral/clay dissolution, confirmed by the porosity, transport, and mechanical property measurements as well as electron microscopy analysis of the same samples. Highlights • Brine/CO 2 /rock interactions change transport and mechanical properties of Mt Simon sandstone. • Porosity increases slightly, while the permeability increases more substantially. • Weakening of the sandstone is observed from mechanical testing. • Changes in brine composition, BET and SEM imaging point to mineral/clay dissolution. [ABSTRACT FROM AUTHOR]

Abstract To keep the stability and integrity of wellbore, it is required to figure out the interaction between clays, water and rock strength in the drilling process. As revealed in available literatures, a high content of clays usually leads to a low value of rock strength and can easily result in the deformation of rocks. However, few studies can succeed in taking the mineral composition and the cement type of clays into consideration. By combining scanning electron microscope (SEM), X-ray diffraction (XRD) analysis with the Brazilian tests, this research can explain the overall effects of clays on the rock strength and deformability behaviors in three kinds of sandstones. The results indicate that the content contrast cannot be a determinant factor in specifying the rock strength. When compared with a lower value, a higher clay content can also exhibit high tensile strength due to a difference in the cement and mineral composition characteristics of clays. Moreover, chlorites were found to contribute more to the strength loss when encountered with water than montmorillonite and illite. This is most likely due to its undulatory surface which can trap much water and thus locally cause massive expansion of clays. According to the cement types, the fracture patterns can be classified into three groups: (1) Grain sliding occurs when abundant clays cement the matrix. The fracture goes through the soft clay cement and the contact surface between clays and grains. (2) Grain fracturing occurs when the clays cannot prohibit the quartz overgrowth, and the fracture can run across the silica-cemented grains. (3) Grain shearing occurs when the rock matrix is unconsolidated and is filled with few clays between grains. The fracture tends to break the rock grains apart in an irregular behavior. Meanwhile, the strengthening mechanism of lost circulation materials was also studied by tracking their migrations through porous media using energy-dispersive system (EDS). Highlights • A low clay content does not always mean a high rock strength. • The clay cement and mineral composition affect the rock deformability. • Chlorite plays a more important role in the strength loss caused by water. • Two kinds of cement were identified as chlorite cement and silica cement. • Fractures can occur as grain sliding, grain fracturing, and grain shearing. [ABSTRACT FROM AUTHOR]

Abstract Typical laboratory Nuclear Magnetic Resonance (NMR) measurements for core analysis are made at a frequency of 2 MHz, principally to verify downhole logging measurements with frequency ranging from 0.7 to 2 MHz. However, higher frequencies have been introduced in measuring shale properties. In this study, we investigate the differences between low frequency (2 MHz) NMR and higher frequency (12 MHz) NMR responses with different TE (Echo Time) ranging from 114 to 300μs in various rock types including sandstones and shales. We found that 12 MHz instrument attains a greater SNR (Signal to Noise Ratio) ranging from 7.3 to 9.8 times higher with fewer scans than the 2 MHz instrument. While this is an insignificant factor for highly porous rocks, it is very important when measuring shales, which requires numerous scans to achieve an acceptable SNR levels. This is also significant while tracking time dependent fluid changes in rocks. We demonstrate novel technique of the dynamic monitoring for a CO 2 displacement of oil experiment with 12 MHz NMR instrument. T 2 spectra were obtained every 20 min to document the oil saturation profile. From this saturation profile, breakthrough time and residual oil saturation were determined to be 340 min and 54%, respectively. Total porosity measurements were almost identical between 2 MHz and 12 MHz with an average difference of ±0.38 p.u. For shale samples only, the difference in porosity measurement was much less, i.e., ±0.16 p.u. Our results suggest that higher frequency NMR produces similar total porosity estimates, T 2 geometric means, and T 2 spectra for some conventional sandstones with low paramagnetic mineral content and shale lithologies. Highlights • 12 MHz instrument attains a great SNR ranging from 7.3 to 9.8 times higher with fewer scans than the 2 MHz instrument. • Porosity measurement from 2 MHz NMR and 12 MHz NMR were almost identical with an average difference of ±0.38 p.u. • High frequency NMR induces internal field gradients, which cause spectra shift to the left compare to lower frequency NMR. • High frequency NMR allow us to dynamically monitor the saturation profile of CO 2 injection test. • 12 MHz NMR can be used for routine core analysis measurements of shale and sandstones with low paramagnetic content. [ABSTRACT FROM AUTHOR]

Abstract Wettability alteration appears to be an important mechanism for low salinity water flooding, but two major challenges in predicting the low salinity effect are (1) to understand the contribution of ion exchange, surface complexation, and albite dissolution mechanisms, and (2) to quantify how the three mechanisms contribute to pH increase during low salinity water flooding. We thus modelled one-dimensional (1D) reactive transport, examining the ion exchange, surface complexation, and albite dissolution using PHREEQC, and compared with RezaeiDoust et al.'s [Energy and Fuels. 2011; 25(5):2151–62.] experimental pH profiles during low salinity water injection. We reasonably matched RezaeiDoust et al.'s experimental pH profiles. We found that ion exchange, and albite dissolution significantly contribute to pH increase, and surface complexation mechanism plays a minor role in pH increase. Our results suggest that basal charged clays (e.g., illite, smectite, chlorite) and albite are minerals to trigger pH increase which decreases the bridging number (>-NH + >-COOCa) for basal charge clays, and also decrease the bonds ([>AlOH 2 +][-COO-]+[>Al:SiO−][-NH+]+[>Al:SiO−][-COOCa+]+[>Al:SiOCa+][-COO-]) for edge charged clays (e.g., kaolinite). Our results provide insights to characterize the geochemical features of oil/brine/sandstone and shed light on constraining the intrinsic uncertainties of low salinity water EOR in sandstone reservoirs. Highlights • Basal-charged clays significantly contribute to pH increase due to ion exchange process during low salinity water flooding. • Albite is an important mineral which promotes pH increase during low salinity water flooding due to albite dissolution and ion exchange process. • Surface complexation mechanism plays a minor role in pH increase during low salinity water flooding. • pH increase due to ion exchange, albite dissolution and surface complexation may be quantified by 1D reactive transport. [ABSTRACT FROM AUTHOR]

Abstract Tight sandstones of the late Permian Willespie Formation constitute an important reservoir rock in the Whicher Range gas field of the Perth Basin. The sandstones under the effect of sedimentary conditions and diagenesis show some degree of heterogeneity reflecting in reservoir properties and production history. The Willespie Formation consists of fine to coarse-grained and gravelly feldspathic sandstones intercalated with shale, siltstone and coal, deposited in a meandering river system. Different diagenetic processes including compaction, cementation (authigenic clays, calcite and siliceous) and dissolution have severely affected the pore system properties of the reservoir sandstones, as they are considered as tight sandstones. In this study, three-dimensional modeling of reservoir sandstones has been performed using stochastic modeling algorithms for facies and porosity properties. A preliminary facies analysis of the main reservoir rocks based on core and well logs data provided the basis for reservoir zonation and modeling. Regarding the close relationship between acoustic impedance with depositional/diagenetic characteristics of reservoir facies and their porosity, this seismic attribute was used as a secondary parameter in porosity modeling. The results indicate a close relationship between sedimentary characteristics and reservoir properties. Based on the extracted models, most of the porous zones are related to the clean and coarse sandstones of the fluvial channels accumulating in the upper parts of the reservoir. In fact, initial sedimentary characteristics have the main impact on the distribution of reservoir zones, their thickness and continuity in the field and controlling large-scale reservoir heterogeneity which has been enhanced by the effect of diagenetic processes on the pore system properties and controlling the internal reservoir heterogeneity in next stages. Distinctive variability in reservoir properties towards the upper reservoir units and also among different wells can be considered for optimizing exploration and development targets of the field. Highlights • Reservoir properties of tight sandstones show intimate relationship with depositional facies and diagenetic features. • Coarse grained facies of fluvial channels contribute to the main reservoir units of the field. • 3D modeling unravels the reservoir heterogeneity related to sedimentary facies and diagenesis. • Depositional characteristics have the main control on distribution, continuity and thickness of reservoir zones. • Diagenesis has the main control on internal reservoir heterogeneity related to pore system properties. [ABSTRACT FROM AUTHOR]

Abstract Since the dynamic process of drilling operation often cannot be duplicated realistically in laboratory environment, the methodology to evaluate drilling induced formation damage using the core plug is still open to question. By using a multifunctional physical simulation system of drilling mud invasion, this paper introduces a novel experimental methodology which organically combines large-sized model flow experiment and NMR measurement to investigate drilling induced formation damage in sandstone reservoir. A large-sized sandstone formation module (55.9 cm in radial depth, and 10 cm in thickness) instead of the conventional core plug is proposed. This new type of experimental aliquot is able to provide enough space for observing a relative greater damage depth in a long-term drilling mud invasion. The effects of formation permeability and overbalance pressure on the damage are analysised. The patterns of permeability impairment and pore structure change caused by the fresh water-based mud invasion are summarized. The results show that the formation permeability plays a negative leading role in both the damage depth and the damage degree. The damage depth of the drilling mud in the sandstone reservoir with a lower permeability is greater than that with a higher value. The former formation damage degree is also more severe than the latter one. For the same sandstone reservoirs, a higher overbalance pressure results in a greater damage depth and a more severe damage degree at the same radial depth. The decrease ratio of movable water based on NMR T 2 distribution is an excellent index for describing the relationship between macroscopic performance and microcosmic essence of the formation damage. An obvious positive correlation between the permeability damage rate and the decrease ratio of movable water is observed. With the variation of decrease ratio of movable water, the permeability damage rate changes faster in the sandstone reservoir with a lower permeability. The results obtained in this paper provide some helpful insights for enlightening new laboratory evaluation methodologies, improving numerical simulation of drilling induced formation damage and researching formation damage caused by any other working fluids, such as completion, workover, and stimulation fluids. Highlights • Sandstone formation module is introduced as a new type of experimental aliquot. • A new large-sized model flow experiment is combined with NMR measurement. • The experimental conditions are closer to the actual downhole conditions than before. • The effects of two factors on drilling induced formation damage are quantified. • The relationship between damage degree and pore structure change is established. [ABSTRACT FROM AUTHOR]

Abstract Replicating sedimentary rocks using three-dimensional (3D) printing can support routine reservoir rock analysis in petrophysical and geomechanical experiments, which is done limited in scope due to lack of suitable printing materials and achievable resolution. Following our previous studies on gypsum powder with binder, a new printing material, silica sand, is used and characterized in this study to demonstrate the microstructure and its similarity to Berea Sandstone. Binder jetting printing system was specifically utilized to bond silica sand particles to create intact cylindrical samples without digital porous model as input. Created samples were first scanned by Backscattered Scanning Electron Microscope (BS-SEM) and Energy Dispersive Spectroscopy (EDS) to identify the particles, the packing mode and cement (binder). Next, micro-computed tomography (CT) was used to determine the microstructure of the samples, including the size and the shape of both particles and pores, in the 3D space. In addition, anisotropy that was found to originate from the pore structures was quantified by comparing the characteristics of pores in different directions. Fractal dimensions from different sample sizes, 6 mm and 12 mm in diameter, were also calculated for pore structure analysis in order to illustrate the effect of sample size on pore heterogeneity in 3D printed samples with silica. The results demonstrated the feasibility of substituting 3D-printed sandstones for natural rocks regarding pore structures for experimental validation of petrophysical models. Highlights • The pore structure of a new 3D printing material, silica sand, was characterized. • The majority of pores belongs to spherical shape rather than disc shape. • Anisotropy of pore structure exists in 3D-printed silica sand rocks. • The pore size distribution of this rock analogue is comparative to Berea sandstone. [ABSTRACT FROM AUTHOR]

Abstract NMR T 2 measurements are widely used to determine various petrophysical properties of rock cores. Internal magnetic field gradients, which occur in rock cores during NMR measurements due to magnetic susceptibility differences between the rock matrix and the pore fluid, can however distort these T 2 measurements. Here we implement a FEM simulation of these internal magnetic field gradients on 3D digital μCT images for five different sandstone rocks, coupled with a random walk simulation of the T 2 NMR signal relaxation process. The FEM simulations required the magnetic susceptibility of each sandstone, this was directly measured using a SQUID magnetometer over a range of magnetic field strengths. The resultant probability distributions of internal magnetic field gradients were then compared against equivalent experimental measurements; they were generally in reasonable agreement, however the simulations failed to capture the larger magnetic field gradients that were observed experimentally. By consideration of various potential reasons for this, we identify the assumption of a single mean magnetic susceptibility as being the primary source of the variation between simulated and measured results. Simulations of 2 MHz T 2 relaxation process are shown however to be in good agreement with experimental measurements across the five sandstones studied. Highlights • 3D simulation of internal magnetic field gradients in sandstones. • Comprehensive comparison of measured and simulated internal gradients and NMR T2 relaxation distributions. • Pore scale magnetic susceptibility shown to significantly affect internal gradients. [ABSTRACT FROM AUTHOR]

Abstract This study investigates the regional and outcrop-scale fracture system within the Wajid Group exposures in Wadi Al-Dawasir, southwest Saudi Arabia. The Wajid Group is a Cambro-Permian siliciclastic succession that forms the main groundwater aquifers in the study area and is considered as a potential hydrocarbon reservoir in the Rub' Al-Khali Basin. The succession is composed of fluvial, marine, and glacial to glaciofluvial deposits. This study aims to characterize and model the fracture system within the Wajid Group in the Wadi Al-Dawasir area using satellite imagery and direct field measurements. A further study objective is to define the geological factors controlling the fracture distribution within the Wajid Group succession. Five sets of regional-scale fractures (lineaments) were defined: N000°, N015°, N035°, N075°, and N135°. In addition, five sets of the outcrop-scale fractures were delineated: N015°, N035°, N075°, N135°, and N165°. The N135°- and N035°-oriented fracture sets are predominant at the regional scale. At the outcrop scale, however, the N165°- and N075°-oriented fracture sets are predominant. The trace-length of the regional-scale fractures is distributed according to the negative exponential distribution. The fractures within the Wajid Group outcrops are vertical to sub-vertical extensional fractures (mode 1). Those fractures are open, however, and at some localities, they are sealed or coated with calcite or iron oxides. Fracture swarms with an orientation of N015° were also observed in the southeastern part of the study area. Hierarchical outcrop conceptual models of two fracture sets are proposed. The proposed models show that the regional-scale fractures are not influenced by stratigraphic or lithological variations. In contrast, the outcrop-scale fractures are controlled by the stratigraphic, lithological, and diagenetic variations in the fracture-hosting sandstone. The diagenetic characteristics (cementation and dissolution), bed thickness, and porosity of the fracture-hosting sandstone play a key role in the fracture distribution within the Wajid succession. The results of this study contribute to the understanding of groundwater flow behaviour within fractured aquifers in the study area and will help to enhance gas production from fractured hydrocarbon reservoirs in the Rub' Al-Khali Basin. Highlights • The N135°- and N035°-oriented regional-scale lineaments are predominant throughout the entire Wajid Group outcrops in the study area. • At the outcrop scale, the N165°- and N075°-oriented fractures are predominant throughout the Wajid Group succession. • Conceptual models of the fracture system have been proposed to illustrate the origin and distribution of fracture within the Wajid Group outcrops. • No lithological and stratigraphic controls on the regional-scale fracture distribution. • The outcrop-scale fractures are mainly controlled by the stratigraphic and diagenetic, properties of the fracture-hosting sandstone. [ABSTRACT FROM AUTHOR]

Abstract The reservoirs of the Lower Permian He8 formation are typically tight sandstones, which have geologic features such as rapid lateral changes, strong heterogeneities and complex pore structures. Rock physics characteristics are similar between tight sandstones and mudstones, mean while fluid AVO characteristics are unclear. These factors make reservoir prediction and hydrocarbon detection become difficult. The keys to successful exploration are the effective elimination of non-reservoirs, including mudstones and ineffective tight sandstones, and the successful discovery of favorable areas. Rock physics analysis indicates that tight sandstone can be identified by V P /V S , while gas-bearing can be distinguished by fluid compressibility. In order to improve inversion accuracy, a new method of favorable area prediction is proposed. Firstly, predict sandstone boundary by V P /V S inversion under the control of sedimentary setting. Secondly, distinguish effective reservoirs and gas-bearing areas with porosity inversion and fluid compressibility inversion under the control of sandstone boundary. Finally, confirm favorable areas according to V P /V S , porosity and fluid compressibility. The tight sandstones of the He8 formation can be divided into three types. Favorable area Ⅰ is the first choice of exploration, target followed by the favorable area Ⅱ, whereas the unfavorable area Ⅲ is not chosen as exploration target. The new method has achieved excellent results in the favorable area prediction of tight sandstone in the Kangning area and has significant implications for late exploration. Highlights • Propose a new method for favorable areas prediction of tight sandstone. • Pre-stack parameter inversion with facies control improves inversion accuracy. • Determine the favorable area of He8 formation in the Kangning area. [ABSTRACT FROM AUTHOR]

Abstract After testing proposed models in the literature on sandstones and carbonates, we propose a mechanistic surface-complexation-based model that quantitatively describes observations for ionically treated waterfloods. We model wettability change by directly linking wettability to brine chemistry using detailed colloidal science. Brine has charged ions that interact with polar acidic/basic components at the oil-water interface and rock surface and therefore oil/brine and rock/brine interfaces are charged and exert both Van der Waals and electrostatic forces on each other. If the net result of the forces is repulsive, the thin water film between the two interfaces is stable (i.e., the rock is water-wet) otherwise, the thin water film is unstable and the rock becomes oil-wet. We describe a ratio of electrostatic force to Van der Waals force with a dimensionless group, called "wetting film stability number," where rock wettability is water-wet for values greater than one and oil-wet for values less than one. For sandstones, the zeta potentials of oil/brine and rock/brine interfaces become more negative/less positive by diluting or softening the brine and/or increasing pH. Similarly, for carbonates, dilution and/or sulfate enrichment of brine makes surface potentials more negative. Such brine modification can therefore be used to improve oil recovery. We implemented the improved wettability change model in a comprehensive coupled reservoir simulator, UTCOMP-IPhreeqc, in which oil/brine and rock/brine zeta potentials are modelled using the IPhreeqc surface complexation module. Surface potentials obtained from the geochemical model are used to calculate the dimensionless group controlling wettability change, which is dynamically modelled in the transport simulator. The model is validated in sandstones and carbonates by simulating an inter-well test, and several corefloods and imbibition tests reported in the literature. For sandstones, we model Kozaki (2012) and BP's Endicott trial. For simple dilution in carbonates we model experiments by Shehata et al. (2014) and Yousef et al. (2010). For enrichment with sulfate we model Zhang and Austad (2006) and for increasing total ionic strength via sodium chloride enrichment, Fathi et al. (2010a). Highlights • The first surface-complexation-based model that fully describes ionic compositional dependency of rock wettability. • We model wettability change by directly linking wettability to brine chemistry using detailed colloidal science. • Describe a ratio of electrostatic force to Van der Waals force with a dimensionless group as rock wettability criteria. [ABSTRACT FROM AUTHOR]

Abstract Volumetric strain and permeability are strictly interconnected properties and important controlling parameters for deformation patterns in rock masses. Under reservoir conditions, stresses may be highly inhomogeneous and anisotropic, leading to porosity changes and consequently affecting fluid flow. Therefore, it turns out be a challenging issue in rock mechanics to evaluate volume change based on traditional soil mechanics background, originally intended for soft materials under low and mostly isotropic pressures. In this respect, triaxial compression tests were carried out to describe the interplay between physical properties, volume change and permeability of two hard sandstones by quantifying porefluid volume change with fully water saturated rock specimens (14 cm length and 7 cm radius). The investigated sedimentary rocks are (1) the greyish Trendelburg beds, a silica cemented subarkose Bunter Sandstone of Triassic age (porosity of ca. 12%), and (2) the red-brownish Rotliegend Sandstone (Bebertal), a carbonate and silica cemented sandstone of Permian age, clearly less porous (ca. 6% of effective porosity) and less permeable (3.5 × 10−10 m/s) than the Bunter Sandstone. Both materials present a pronounced brittle behaviour influenced by coring direction: permeability, volumetric strain and fracture pattern are direction-dependent. Effective porosity and pore pressure level affect the fracturing development, which therefore influences the permeability after stress fall. For the Bunter Sandstone, increasing porefluid pressure leads to an earlier microcraking stage, which shortens the forestage of compaction and induces a more pronounced dilatant behaviour with decreased compressive strength. For the Rotliegend, the increase of pore fluid pressure enhances compaction. Altogether, this examination is valuable to understand the combined effects of pore pressure change and pore space quality on the mechanical behaviour of rock masses. Highlights • Bunter Sandstone and Rotliegend have an inverse anisotropic behaviour and therefore they accomodate strain differently. • Strength, permeability and volume change are direction dependent and highly affected by the pore pressure level. • Fracture pattern have their development strongly associated with effectice porosity and effective pressure. [ABSTRACT FROM AUTHOR]

Abstract Low salinity water (LSW) flooding is a commonly used technique to recover remaining oil. Efficiency of this method can be improved by decreasing salinity of the injected fluid during LSW flooding. However, the environment of low salinity is unfavorable for fine-sized particles retention, and may result in fines migration and formation damage. In most sandstone reservoirs, migration and production of fines along with fluid is a major problem in oil and gas industry. Several methods can be used to control migration of fine-sized particles. One effective treatment is to use nanofluids. Nanofluids can affect surface charges and increase the attraction between the particles and sand surface. Fines are negatively charged while nanoparticles usually have positive charge. By attracting nanoparticles to surface of the sand, sand surface becomes more positive which leads to retention of fines. In previous studies, effect of nanoparticles on fines migration in aqueous media was investigated. Another parameter which can influence surface charges is presence of hydrocarbon. Crude oil is an organic substance which is negatively charged just like other organic substances. And this charge difference explains why the presence of oil can affect the performance of nanoparticles in fine migration control. The purpose of this experimental study is to investigate the effect of using SiO 2 nanoparticles on controlling fines migration caused by LSW injection in presence of hydrocarbon. In addition, the effect of fine particles stabilization on oil recovery was analyzed. A mixture of paraffin and decane was used as hydrocarbon. Experiments have been conducted in three different series. The first series of experiments aimed to select the best nanoparticle among Al 2 O 3 , SiO 2 , and MgO. The results showed that silica nanoparticles had a great potential to control fines migration during LSW flooding. In the second series, the impact of injected nanofluid concentration on fines migration was investigated. And, in the third series, the effect of soaking times of 6, 12, 24, and 48 h was investigated. In addition, recovery of oil is measured in all tests. Silica oxide nanofluid in 0.1% wt. concentration shows the best performance in controlling fines migration and reducing the pressure drop in the porous media. In the third series of experiments, the soaking time of 24 h for the SiO 2 nanofluid showed the best results for controlling fines migration. Also, our experiments showed that migration of fines cannot be considered as an effective mechanism of enhanced oil recovery during LSW flooding. Highlights • In this experimental study the effect of nanoparticles on fines migration control in two-phase systems is investigated. • Low salinity brine leads to fines migration and pore blockage. • Nano-SiO2 can effectively reduce fines displacement during LSW flooding. • Controlling migration of fines by using SiO2 nanoparticles can help enhance oil recovery in a homogenous porous media. [ABSTRACT FROM AUTHOR]

Abstract The lithology, mineralogy, texture, pore systems, and diagenesis of the Eocene –Oligocene Suweiyi Formation sandstones in Dina 2 Gasfield of Kuqa depression were investigated by integrating thin sections, scanning electron microscope (SEM) images with X-ray Diffraction and routine core analysis. The results reveal that carbonates and clay minerals are the dominant pore-filling constituents, while quartz cements and evaporate minerals occur in only minor amounts. Compaction played an important role in reducing intergranular porosity, especially in the clay-rich or poorly sorted successions. Framework grains dissolution greatly enhance total porosity. The pore systems consist of intergranular and intragraular dissolution porosity, micropores and minor intergranular pores. Four diagenetic facies are identified according to lithologic characteristics, diagenesis, as well as diagenetic minerals, and they are: (1) tightly compacted facies (high degree of compaction but low degree of cementation and dissolution); (2) carbonate (calcite) cemented facies; (3) clay mineral (illite and mixed-layer illite/smectite) filling facies; and (4) dissolution (of framework grains) facies. Diagenetic facies are correlated with the conventional well logs, and the well log expressions for diagenetic facies are summarized, then the diagenetic facies in uncored intervals and wells can be predicted based on the qualitative well log characteristics. Image logs were used to derive the porosity spectrum (porosity distribution histogram) by applying the typical Archie's formula to the flushed zone. Then the porosity spectrum is integrated with the conventional logs to predict the diagenetic facies, and the results can be evidenced by thin section observation, and SEM analysis. Dissolution facies, which has the highest reservoir quality, tend to have bi-modal porosity spectrum, and the porosity spectrum is very broad or even contains tail distributions. In contrast, the porosity spectrum of the carbonate cemented facies and tightly compacted facies are narrow and dominantly of uni-modal behaviors, indicating the absences of large pores and a poor reservoir quality. The porosity spectrum of clay mineral filling facies can be bi-modal or uni-modal, but the porosity spectrum is narrow and contains no tail distributions. The diagenetic facies and reservoir quality in sandstones can be predicted through correlating the diagenetic facies to conventional well logs integrated with image logs. Highlights • Diagenesis and diagentic facies of the Suweiyi sandstones are investigated. • Diagenetic facies are correlated to the well logs. • The porosity spectrum and conventional logs are used for predicting diagenetic facies. [ABSTRACT FROM AUTHOR]

Abstract Asphaltene deposition in oil reservoirs is a contentious issue affecting both well and reservoir productivity. Though the phenomenon has been previously studied in several laboratory experiments, the uniformity aspects of the asphaltene deposit are usually overlooked. We have previously developed an experimental workflow to create a uniform deposit of asphaltene inside the core sample. In this study, the impact of this uniform deposit on fluid flow is quantified through imbibition, corefloods and relative permeability experiments. In addition, the lab results are used in a field scale simulation to investigate the impact of deposition on field performance. The results exhibit a shift in the wettability state where a reduction in both water imbibition rate and capacity are observed after deposition. Besides, up to 25% reduction in absolute permeability is detected. Results of pressure drop experiments across the core conducted on the exposed rocks indicate a change in the wetting characteristics, with the exposed rocks becoming more mixed/intermediate wet and varying with the change in the initial brine saturation in the rock. Subsequently, the relative permeability set is affected where a shift in the oil residual saturation, a downgrade in the oil curve and an upgrade in the water curve are observed. Upscaling this new data to field scale indicated a loss of more than half of the well productivity and an earlier breakthrough if waterflooding is implemented. Highlights • Permeability impairment is up to 25% for continuous injection and 15% after vacuum saturating the core. • Meaningful relative permeability data must be collected using cores with uniform deposit. • Initial brine saturation greatly affects the impact of oil on rock wettability. • A reduction in clay swelling is observed in rocks exposed to crude oil. • A reduction in the width of the two-phase movable window is observed in cores exposed to oil. • Incorporating the formation damage in a reservoir simulator anticipates well's potential drops in half. • The effect of changes in relative permeability on productivity are more pronounced than that of absolute permeability. [ABSTRACT FROM AUTHOR]

Abstract Wettability of an oil/brine/sandstone system is an important petro-physical parameter, governing subsurface multi-phase flow and residual oil saturations. While how edge-charged clays (e.g., kaolinite) contribute to low salinity effect has been extensively investigated, few work have been done on basal-charged clays (e.g., illite, smectite, and chlorite), and few have look beyond the application of the low salinity effect in reservoirs bearing basal-charged clays. We thus integrated atomic force microscopy (AFM) (at a given pH = 7), disjoining pressure calculations, together with surface complexation modelling to understand the importance of basal-charged clays during low salinity water flooding in sandstone reservoirs. We found that low salinity effect can take place without pH increase, confirming that electrical double layer is at least one of the mechanisms to yield low salinity effect, which can be interpreted using disjoining pressure isotherm, whereas ion exchange between oil and basal charged clays leads to an opposite effect at a given pH. However, ion exchange likely favors low salinity effect without controlling pH due to the chemical reaction: >Na + H+ = >H + Na+, which in return decreasing the electrostatic bridges between NH+/clays, COOCa+/clays. Knowing the contribution of EDL and ion exchange on oil/brine/basal-charged clays interaction, the potential of low salinity effect in sandstone reservoirs can be quantified. Highlights • Electrical double layer expansion increases hydrophilicity when the zeta potential of the oil and rock are of like sign. • MIE likely promotes low salinity effect due to the chemical reaction: >Na + H+ = >H + Na. • Increasing pH leads to decrease of the electrostatic bridges between NH+/clays, COOCa+/clays. [ABSTRACT FROM AUTHOR]

Abstract Unconventional resource formations like tight sandstone reservoirs have complex pore and throat structure that are hard to characterize in micro scale. In this research, the pore and throat system of tight sandstones was characterized comprehensively, analysed qualitatively using scanning electron microscopy (SEM) techniques and quantitatively through combined high pressure mercury (HPM) and rate-controlled mercury (RCM) methods. First, the throat, distinguished from the pore, was divided in several types for tight sandstones and visualized through SEM imaging. Then, an integrated approach was proposed to combine the results from both HPM and RCM measurements, resulting in overall size distributions of the pore and the throat with scales from nanometer to micrometer. Both overall size distribution using the new combining method represented the pore and the throat more accurately in wider ranges. The results also showed that for tight sandstone core samples with different permeability, the difference of pore size distribution was less obvious than that of the throat. Therefore, the quantitative characterization of the throat size distribution was ultimately employed in developing a new permeability model together with physical considerations. The results demonstrated that the permeability of tight sandstones was in general depend on the size distribution of relatively larger throat, denoted as the macrothroat. However, for extreme low permeability (< 0.1 m D) formation, the small throats like microthroats and mesothroats mainly contributed to the permeability since the contents of macrothroats are really low. Highlights • The pore and throat of tight sandstones was characterized comprehensively and analysed qualitatively. • An integrated approach was proposed to combine the results from both HPM and RCM measurements. • Both overall size distribution represented the pore and the throat more accurately in wider ranges. • The quantitative characterization of the throat size distribution was ultimately employed in developing a new permeability model. • The permeability larger than 0.1 mD in general depends on the size distribution of macrothroat. • For the permeability smaller than 0.1 mD, microthroats and mesothroats mainly contributed to the permeability. [ABSTRACT FROM AUTHOR]

Abstract In this study, a robust and pragmatic technique has been developed to experimentally and theoretically evaluate the performance of high-pressure water jet (HPWJ) dynamics in tight formations by use of a new downhole pressurized drilling tool (DPDT). Experimentally, principles and structure of the new DPDT are described, while well-designed tests are conducted to examine the effects of water jet velocity, dwell time, incident angle, and rock type on the rock-breaking volume at pressures higher than 100 MPa. Numerically, the smoothed particle hydrodynamics coupled with the finite element method has been used to quantify the rock-breaking volume as a function of the 1st principal stress under various conditions. The experimentally measured and numerically simulated rock-breaking volumes are in good agreement under the same conditions. As for a marble specimen, there is a rapid increase in rock-breaking volume at nozzle pressures higher than 150 MPa and dwell times shorter than 40 s. The optimal incident angle for the rock-breaking efficiency is found to be 77°. With the same nozzle pressure and dwell time, the rock types can be ranked in terms of rock-breaking volume in the order of marble < sandstone < concrete < shale. Also, field tests of the DPDT have been successfully performed to enhance the rate of penetration (ROP) by 32.9–80.5% for different rock types compared with the traditional drilling methods. Highlights • Performance of HPWJ generated by a downhole pressurized drilling tool (DPDT) in a tight formation is evaluated. • A rapid increase in rock-breaking volume is achieved at nozzle pressure higher than 150 MPa and dwell time shorter than 40 s. • The optimal incident angle for the efficient rock-breaking is found to be 77°. • The rock types can be ranked in terms of rock-breaking volume in the order of marble < sandstone < concrete < shale. • The rate of penetration was increased by 32.9–80.5% for different rock types with the new DPDT. [ABSTRACT FROM AUTHOR]

Abstract To better understand gas migration and accumulation in tight sandstone reservoirs, we conducted an integrated petrographic and geochemical analysis of hydrocarbon and aqueous fluid inclusions. This analysis was combined with the burial and multistage hydrocarbon charging histories of the reservoir. The variability in the types of hydrocarbon inclusions in the tight sandstone reservoirs can be mapped to identify phase fractionation during burial and migration. The oil-bearing inclusions resulted from the heterogeneous capture of oil generated during the first hydrocarbon charging period, when the sandstones had not yet reached tight reservoir conditions. The gas-bearing inclusions in the tight sandstone reservoirs formed during the phase fractionation of dissolved and free gas due to unstable pressure conditions. The gas-bearing inclusions are characterized by a varying vapor volume fraction (φ vap). A higher proportion of gas-bearing inclusions with φ vap < 25% was observed near the source rock with TOC content >1.2%. In contrast, in structural highs, a higher proportion of gas-water inclusions with φ vap > 25% was observed, demonstrating that phase fractionation occurred during migration. The GOI data suggest that the dissolved gas migration mainly occurred in the reservoir near the source rock with TOC content >1.2%. The subsequent free gas separation in relation to upward migration and strata uplift caused free gas to migrate farther into the tight sandstone reservoir. Additionally, the gases displayed benzene/n-hexane ratio, methane and ethane δ13C values increasing initially, then decreasing along the migration pathway, recording the phase state evolution of the natural gas during the burial history of the reservoirs. Highlights • The paleopressure evolution has been reconstructed. • The geochemical fractionation effects in high and low surplus pressure zone are investigated. • Phase fractionation during the burial history is revealed by fluid inclusion petrography and microthermometry. [ABSTRACT FROM AUTHOR]

Abstract Roller cone drill bit efficiency time during drilling depends, to a large extent, on the properties of the materials from which the components of the roller cone bit are made. The faster the roller cone bit is worn, due to the effects of the rock material through which we drill and the drilling regimes used during the drilling, the worse is the efficiency of drilling and the higher is the number of drill bits needed to drill the well. The aim of our research was to determine the mechanisms of wear on roller cone bit materials according to the characteristics of the steel material of the roller cone bit and the characteristics of the rock material, in this case, sandstone on the drilling regime. The results of the discovered wear mechanisms help us to anticipate the possible improvement of the resistance of the unprotected roller cone bit steel material to excessive wear and, consequently, the longevity of the roller cone bit. For this purpose, we examined the steel materials of the roller cone bit, which we used during well drilling and the rock material, sandstone, through which we drilled with the roller cone bit under consideration. The results of our analysis present the mechanisms that result in the wear of the roller cone bit material under the given conditions of the rock material and the drilling regime. The results of the discovered wear mechanism can be used to improve the material of the roller cone bits in order to achieve a longer operating life and decrease the related costs of drilling. Highlights • The characterization of the wear of the drill bit, is a complex analysis of several factors. • The differences between the deformability properties of the steel material on drill bit are evident. • The carbide coating gradually disintegrate during the drilling process. • The abrasive components in drilling mud are forming the erosion channels. [ABSTRACT FROM AUTHOR]

Abstract The Upper Triassic Xujiahe Formation is a key target layer for development of tight sandstone gas reservoirs in the Sichuan Basin. Most of the previous work focused on the main reservoirs such as T 3 x2 and T 3 x4 with lack of research attention on T 3 x5, an equally important source-reservoir unit. Here we examine the organic matter and source rock distribution in the T 3 x5 using rock pyrolysis, asphalt extraction, and gas chromatography. The thickness of T 3 x5 source rocks reduces from west and northwest Sichuan Basin to east and southeast Sichuan Basin. The main sedimentary facies are salt lakes and deltas, of which the organic matter originated from aquatic organisms and a small amount of terrestrial matter. The abundance of total organic carbon (TOC) in T 3 x5 is relatively high, at values of 0.07%–7.2%. According to the vitrinite reflectance (R o), pyrolysis, and gas chromatography measurement results, the T 3 x5 source rocks are at the stage of mature to over-mature, and their hydrocarbon expulsion threshold and hydrocarbon expulsion peak correspond to Ro of 1.05% and 1.23%, respectively. Furthermore, a hydrocarbon generation center and a hydrocarbon expulsion center are formed horizontally, with the maximum hydrocarbon generation intensity of 50 × 108 m3/km2 and the maximum hydrocarbon expulsion intensity of 48 × 108 m3/km2. The natural gas resource is 3.19–5.36 × 1012 m3, indicating great exploration potential. Highlights • Evaluate of T 3 x5 source rocks in detail from 5 aspects: sedimentary environment, thickness and distribution, organic matter abundance, organic matter type and organic matter thermal maturity. • Clarify the hydrocarbon generation and expulsion features of T 3 x5 source rocks. • Predict resource potential of the T 3 x5 in Sichuan Basin. [ABSTRACT FROM AUTHOR]

Abstract Upscaling Klinkenberg-corrected gas permeability, k , in unconventional tight sandstones has numerous practical applications, particularly in gas exploration and production. In this study, we adapt the effective-medium approximation (EMA) model of Doyen – proposed first to estimate bulk electrical conductivity, σ b , and permeability in sandstones from rock images – to scale up σ b and k in tight-gas sandstones from pore to core. For this purpose, we calculate two characteristic pore sizes: an effective hydraulic and an effective electrical pore size from pore-throat size distributions – determined from mercury intrusion capillary pressure (MICP) curves – and pore-throat connectivity. The latter is estimated from critical volume fraction (or percolation threshold) for macroscopic flow. Electrical conductivity and permeability are then scaled up from the two characteristic pore sizes, tortuosity, and porosity by assuming two different pore geometries: cylindrical and slit-shaped. Comparison of results obtained for eighteen tight-gas sandstones indicates that the EMA estimates σ b and k more accurately when pores are assumed to be cylindrical. We also estimate k from the pore-throat size distributions and the measured electrical conductivity using the EMA and critical path analysis (CPA), another upscaling technique borrowed from statistical physics. Theoretically, the former is valid in relatively heterogeneous porous media with narrow pore-throat size distribution, while the latter is valid in heterogeneous media with broad pore-throat size distribution. Results show that the EMA estimates k more accurately than CPA and arrives within a factor of two of the measurements on average. [ABSTRACT FROM AUTHOR]

Abstract Petroleum exploration for tight sandstone reservoirs in the Ordos Basin has attracted much attention in recent years. However, the effective evaluation of the quality of tight sandstones is challenging due to their low porosity, low permeability, non-Darcy flow, continuously or quasi-continuously distribution and strong heterogeneity. Using constant velocity mercury injection, cathodoluminescence micrography, energy spectrum analysis, scanning electron microscopy and casting thin sections, a set of parameters, including the clay mineral index, Lorentz coefficient, compositional maturity, and plane porosity are tentatively proposed to evaluate the quality of tight reservoir rocks. Coupled with statistical methods, i.e., Principal Component Analysis, Grey Correlation Analysis, Analytic Hierarchy Process and Hierarchical Cluster Analysis, a comprehensive quantitative reservoir evaluation model is established. Then, the evaluation index (REI) is calculated, and the thresholds of various types of reservoirs are determined. The case study based on the above evaluation model shows that most of the type I reservoirs are petroleum-enriched, which are favourable targets for exploration and development. By contrast with sedimentary microfacies, the sandbodies in favourable targets were deposited in ancient subaqueous distributary channels, and they show a large herringbone-like distribution. Whereas the poor type-III reservoirs and non-prospective layers are mainly located in the southeastern part of the study area. The case evaluation based on the statistical methods is consistent with the results of previous multi-parameter evaluations, which has important implications for further exploration in the study area as well as other tight sandstone reservoirs. Highlights • The abnormal characteristics of Chang 8 tight oil sandstones were analysed. • A comprehensive quantitative reservoir evaluation model was established. • The favourable exploration targets were determined. • The model may provide important implications for exploration of the tight sandstone reservoirs. [ABSTRACT FROM AUTHOR]

Abstract The combination of low salinity water with gas in the form of water alternating CO 2 injection (CO2-LSWAG) is a promising EOR method that could simultaneously benefit from gas mobility control and also rock wettability alteration to more water-wet as consequence of geochemical interaction between rock and reservoir fluids. This paper aims to investigate the EOR potential of CO 2 -LSWAG under miscible conditions in a sandstone oil reservoir by coupling fluid flow and geochemical modeling. The wettability alteration of the rock surface was described by a series of relevant geochemical reactions between rock and low salinity water in a compositional simulator. The concept of ion equivalent fraction was used as the wettability index during CO 2 -LSWAG injection. It consists mainly of the effects of ion exchange and clay properties on oil-water relative permeability functions. Also, the effect of calcite mineral dissolution was studied as result of interaction with low salinity water and CO 2 gas using relevant geochemical reactions. Results showed that salinity difference between injected and formation water triggers ion exchange processes between water and rock. Also, the rate of calcite dissolution increased due to the CO 2 partitioning into the aqueous phase. The calcite dissolution caused the increase of calcium ions in the reservoir leading to more water-wet condition. However, results indicated that the rate of calcite dissolution decreased far from the injection well most likely due to reduced interaction time between low salinity water with dissolved CO 2 and the reservoir rock. The oil recovery results showed that CO 2 -LSWAG is capable of producing incremental oil as much as 10% of the initial oil in place on top of high salinity CO 2 -WAG. The results of this numerical study support the potential application of CO 2 -LSWAG as an efficient EOR method in sandstone reservoirs. Highlights • LSW triggers a series of ion exchange processes between aqueous phase and rock surface that cannot be found during HSW. • As to CO 2 -LSWAG, partitioning of more CO 2 in aqueous phase promotes calcite dissolution reaction more than LSW injection. • Rate of calcite dissolution reaction decreases far from the injection well. • As calcite dissolution reaction is considered, more oil is produced by promoting ion exchange processes. • Demonstrating incremental oil recovery by CO 2 -LSWAG injection. [ABSTRACT FROM AUTHOR]

Abstract Formation damage is an inevitable problem during drilling in the sandstone gas reservoir. The invasion of drilling fluid could cause the decreasing of permeability of the formation and induce the reduction of gas production. In this paper, one kind of microemulsion is designed to improve the performance of drilling fluid in Sulige gas field, China. The fundamental chemical/physical properties and damage mechanism of targeted tight sandstone formation is analyzed using a combination of several experimental methods, including X-ray diffraction, scanning electron microscopy, core inhibition test, and etc. It shows that the formation rock is composed of medium to coarse particles and massive sensitive minerals, distributed with tiny connected pore throats. The rock has a high potential for water blocking damage and shows a medium to a strong performance of water sensitivity and stress sensitivity. Aiming to avoid these damages, one protective additive (microemulsion) is specifically designed. Through adsorption morphology test and core inhibition test, it shows that the newly developed microemulsion (0.5% concentration) could effectively weaken the inhibition effects induced by capillary pressure and decrease the flow back resistance of drilling fluid. Finally, a new drilling fluid using this new additive is designed and evaluated. The new drilling fluid works effectively in preventing water blocking by decreasing surface tension and transforming the wettability of tight sandstone from hydrophilic to intermediate wet. This contributes to the significant recovery of formation permeability (more than 92.1%) and the increasing of gas production. Highlights • The damage mechanism of tight sandstone gas reservoir has been explored. • Highly efficient protective agent of microemulsion has been designed and evaluated. • The new protective drilling fluid can protect tight sandstone gas reservoir. [ABSTRACT FROM AUTHOR]

Abstract Relative permeability of multiphase flow through porous media plays a vital role in the petroleum industry, especially in enhanced oil recovery (EOR) processes. In this study, models were developed based on a combination of Least-Square Support Vector Machine and Couple Simulated Annealing (CSA-LSSVM) algorithm to predict oil-water relative permeability in sandstone and carbonate porous media. Comparing the model to thousands of experimental data resulted in overall squared correlation coefficients (R2) of 0.9866 and 0.9965, and minimum squared errors (MSEs) of 0.0014 and 0.000143 for K ro and K rw , respectively. In addition, Model predictions were found to agree excellently with experimental data. The results of CSA-LSSVM model were compared with some of the well-known mathematical equations including the Purcell, Burdine, Brooks and Corey, Corey, and some empirical correlations for predicting the oil-water relative permeability in a heterogeneous carbonate core sample. The models developed in this study outperform the mathematical equations and empirical correlations yielding an overall squared correlation coefficients of 0.9987 and 0.9994, and minimum squared errors of 0.0003 and 0.0049 for K ro and K rw , respectively. Finally, leverage value was introduced to analyze the whole dataset from which 19 points were diagnosed as possible outlier experimental data. Highlights • CSA-LSSVM models have been developed to predict water-oil relative permeability. • CSA-LSSVM models have been compared to well-known mathematical models and empirical correlations. • Developed models in this study outperform all the other modeling approaches. • Outliers of the implemented experimental data have been diagnosed. [ABSTRACT FROM AUTHOR]

Abstract Understanding the dielectric properties of reservoir rocks has important applications in various aspects in the petroleum industry. Fractures are common features in sedimentary porous rocks that not only provide space for the hydrocarbon to accumulate and reside but also are important pathways for the hydrocarbon to flow and therefore have a controlling impact on the formation and distribution of the hydrocarbon reservoirs. However, the dielectric properties of fractured reservoir rocks are still poorly understood. We investigated, through dedicated laboratory experiments, the dielectric behaviors of synthetic porous sandstones with aligned fractures and their relationships with the salinity of the electrolyte saturating the samples, the measurement frequency of the applied electrical field and the directions relative to the fractures. It showed that the fractures have significant effects on the dielectric properties of porous sandstones and their dependence on the brine salinity and measurement frequency reveals the various polarization mechanisms occurring at different frequency ranges. The results offer a preliminary basis for the characterization of fractured rocks using the dielectric properties, which has great potential applicability in oil and gas exploration and exploitation. Highlights • The dielectric properties of synthetic porous sandstones with aligned fractures are studied. • The fractures have great effects on the dielectric behaviors of porous sandstones. • The results reveal various polarization mechanisms occurring at different frequency ranges. [ABSTRACT FROM AUTHOR]

Abstract For tight sandstone reservoirs, the pore structure is sensitive to the stress variations during the production process. The alternation of pore structure influences the petrophysical properties and therefore the dynamic flow of tight sandstone reservoirs. In this research, Nuclear Magnetic Resonance (NMR) technique is employed to quantitatively study the pore volume variation under different confining pressures. Not only during the compression process, this research also investigated the sandstone pore sensitivity to stress during the recovery process of rock samples, which is equally important and happens during the production process when the formation pressure is building up due to the temporary well shut-in or water injection. The core samples selected from Ordos basin are first tested routinely for basic parameters like porosity, permeability and detrital components, and then through both compression and recovery processes where the pressure decreases and increases, respectively. It is found that the core samples with high permeability show stronger stress sensitivity of pores than those with low permeability due to the higher content of large pores. Besides permeability, detrital components and interstitial material can also affect the stress sensitivity of pores. During the recovery process, the low recovery degree of pore volume is related to the recoverable pore size (mainly smaller size pores) and the narrow distribution range of recovered pores. Furthermore, the power function relationship and the exponential relationship are suggested to evaluate the variation of pore volume in compression and recovery process, respectively. The results demonstrated that the compressibility of larger pores is bigger than that of smaller pores. During the compression process, the higher permeability rocks, containing a higher content of larger pores, are easier to be compressed, and has a greater decrease in permeability. Besides, the recoverability of the total pore volume after compression is mainly controlled by smaller pores, which results in the lower recoverability of the total pore volume and the permeability for the higher permeability core samples. Highlights • Using Nuclear Magnetic Resonance (NMR) technique to quantitatively study stress sensitivity. • High permeability cores show stronger stress sensitivity than that in low permeability. • Detrital component and interstitial material can affect stress sensitivity of pores. • Power function relationship can be used to evaluate the variation of pore volume. • Exponential relationship can be used to estimate the recovery degree of pore volume. [ABSTRACT FROM AUTHOR]

Abstract This paper is devoted to studying the parameters of acoustic signals induced by fluid flow in porous media. The setup design and technique of acoustic measurements are described in detail. Sound induced by nitrogen flow in different types of carbonate rocks and sandstones is measured and analyzed. Limestone samples generate acoustic signals within a frequency range from 2 to 30 kHz. Sound in sandstone is significantly different from that in the limestone samples and occurs in a frequency range from 1 to 5 kHz. For limestone samples, sound generation is observed at lower flow rates than for sandstone due to earlier transition to a non-Darcy flow regime. From complementary analysis of hydrodynamic parameters of experiments, it is inferred that acoustic signals in rock samples appear only when the Forchheimer number exceeds values in the range 0.3–0.4. It is demonstrated that the recorded sound is mainly produced in the relatively thin near-surface zone of rock samples. Highlights • Acoustic signals induced by single-phase nitrogen flow in rocks were measured. • Intensity of acoustic signals were studied as function of flow rate. • The acoustic signals in rocks appear when the Forchheimer number exceeds 0.3 to 0.4 [ABSTRACT FROM AUTHOR]

Abstract Proppants play an important role in propping fractures open after pumping ceases during horizontal drilling and hydraulic fracturing. However, some proppant degradation mechanisms, mainly proppant embedment, cannot be avoided in deep underground reservoirs, and greatly reduce hydraulic conductivity and production. To make the situation even worse, rock shearing associated with fault activation during the hydraulic fracturing process inevitably generates shear stress or even causes rock shear slip, which may enhance proppant embedment. Although no study to date has focused on this area, it is vital to investigate the influence of shear stress and the corresponding movement on proppant embedment. Therefore, a series of tests was conducted for rocks with two joint roughnesses. After the experiments, rock samples were scanned and joint surface profiles were plotted in 3-D Surfer. The results show that embedment increases with horizontal displacement for both types of rock joint due to rock dilation. Furthermore, embedment increases with increasing shear stress after the stress limit is exceeded. In addition, the proppant greatly reduces rock shear resistance, including peak shear strength and shear stiffness. The addition of proppant can also lead to the reduction of peak and residual friction angles, and accelerate the reduction of dilation angle. Quantitative analysis was conducted utilizing three correlation coefficients to measure the relationship between rock shear strength and influencing factors (proppant addition, surface roughness and fluid effect). The results extend the understanding of rock shear performance and proppant behaviour optimization during horizontal drilling and hydraulic fracturing. Highlights • Proppant embedment variation under various conditions during direct shear testing is studied. • Rock surface asperity degradation after direct shearing is presented by 3-D Surfer. • The introduction of proppant significantly alters rock dilation pattern and rock shear performance. • Quantitative analysis is utilized to precisely estimate shear strength influencing factors. [ABSTRACT FROM AUTHOR]

Abstract Primary and secondary porosity in sandstones possess different pore geometry characteristics, but these are not well quantified. The pore surface area in 2 suites of sandstones exhibiting only primary porosity (Permo-Triassic, Northern Ireland) and only secondary porosity (Cambrian, England) were measured using JMicrovision software. The data show pore surface areas per unit pore volume ∼2.5 times as great in the secondary porosity compared to the primary porosity. This difference is great enough to have a significant impact on properties dependent on pore surface area, including oil production and capacity for microbial colonization in the deep biosphere. Highlights • Secondary pores after feldspar dissolution in sandstones has high pore surface area. • Sandstone secondary porosity has about 2.5 x the surface area in primary porosity. • If 40% of the total porosity is secondary the pore surface area is increased by 60%. [ABSTRACT FROM AUTHOR]

Abstract Fixed-point multistage fracturing can effectively increase the stimulated reservoir volume (SRV) in tight sandstone reservoir. In different geological and engineering conditions, how to explain the geometric form of fracture propagation in fixed-point multistage fracturing has not been reported yet, and the propagation mechanism of hydraulic fracture is ambiguous. To clarify this mechanism, fourteen large-scale triaxial tests were deployed in this study to investigate the fracture propagation behavior in fixed-point multistage fracturing, and the influences of various factors on fracture geometries were studied. The results show that there are six types of fractures in the horizontal plane when the fixed-point multistage fracturing are carried out in a vertical well in tight sandstone reservoir: bi-wing planar fracture; bi-wing non-planar fracture; L-type fracture; X-type fracture; bi-wing turning fracture and re-orientation turning fracture. Fixed-point multistage fracturing can increase the SRV mainly because it is equivalent to carry out refracturing in the reservoir, so it can form a complex fracture system similar to refracturing. The research proves that it is difficult to form a complex fracture system through the fixed-point of multistage fracturing when the stress difference is more than 6 MPa in the horizontal direction. The fracturing fluid injection rate has an obvious effect on the formation of multi-fractures, and the multi-fracture can not form when the injection rate is too large. The enhancement of rock heterogeneity will lead to more energy consumption in fracturing process, which is not conducive to the initiation and propagation of fractures. Therefore, the in-situ stress, rock heterogeneity, injection rate and other factors should be comprehensive considered when designing the fixed-point multistage fracturing scheme for vertical well in tight sandstone reservoir. Highlights • Large-scale triaxial tests were deployed to analyze the fracture propagation behavior in fixed-point multistage fracturing. • The influences of various factors on fracture geometries were studied. • There are six types of fractures in the horizontal plane when the fixed-point multistage fracturing are carried out. • Fixed-point multistage fracturing can increase the SRV because it is equivalent to carry out refracturing in the reservoir. [ABSTRACT FROM AUTHOR]

Abstract Inspired by the successful implementation in acid fracturing, a fiber-loaded suspension system was designed to investigate inlet injectivity, in-depth mobility and overall plugging effect in unconsolidated high permeability sandpacks. In this paper, a series of experiments were conducted to screen suitable fiber suspension, including additives selection and dynamic plugging tests. Results showed that the formulation of 0.02 wt% citric acid+0.1 wt% YC regulator+0.1 wt% sodium tetraborate+0.12 wt% HPG displayed satisfactory dispersity. Sandpacks equipped with three pressure gauges to detect pressure changes were used for physical experiments. Four parameters (fiber length, fiber concentration, injection rate and permeability) that influenced the plugging efficiency were under discussion. The results revealed that relatively slow injection helped stabilize inlet pressure below upper limit. Three pressures increased in sequence during the subsequent water flooding, indicating that fibers moved forward with permeability reduction in sandpacks. The pressure dropped down but maintained at a high level after the operation finished. By comparison, 0.3 wt% 1000 μm-long fiber injected at the rate of 1 mL/min was found to achieve the best performance under the permeability of 4000–7000mD. And the more serious the heterogeneity was, the more significant the diversion ability of the high permeability layer was. Noticeably, the fluctuations were observed in pressure curves, which was further interpreted by the dynamic plugging mechanism of fiber in four transport processes: "migration-capture-redirection-recapture". With unique slender shape, fibers were flexible enough to bridge and create a compact three-dimensional network structure along the flow direction. Due to high plugging strength and strong penetrability, the new fiber suspension system proves its potential to be an environmentally-friendly candidate in the selection of in-depth diverting agents. The evaluation and mechanism analysis may provide guidance for the operation design of profile control. Highlights • A fiber-based suspension system is proposed for in-depth profile control. • The formulation of 0.02 wt% citric acid+0.1 wt% YC regulator+0.1 wt% sodium tetraborate+0.12 wt% HPG shows good dispersity. • Four factors are considered to investigate inlet injectivity, in-depth mobility and overall plugging effect of suspension. • Pressure fluctuations are interpreted by four transport processes: migration, capture, redirection and recapture. [ABSTRACT FROM AUTHOR]