Unconventional Reservoir Rocks Research Articles

Experimental study on crack propagation characteristics of unconventional reservoir rocks

This study investigates the fracture behaviour of three types of specimens (shale, sandstone, and coal), which are commonly found in unconventional reservoirs, based on mode Ⅰ single-edge notch beam (SENB) test. We employ the Digital Image Correlation technique to track the strain evolution and crack propagation paths of the three types of materials and compare their fracture characteristics. The experimental results show that both the surface roughness and crack initiation angle of the coal are larger comparing with that of sandstone and shale, which demonstrates the ductile property of coal and fracturing difficulty in coal seam. Moreover, the average velocity difference of crack propagation is obvious, which is 53.76 × 103, 453, and 0.33 mm/s in shale, sandstone, and coal, respectively. The elastoplastic J-R curves, which reflects the influence of the plastic zone, are presented to analyze the energy dissipation characteristics of three types of specimens during crack propagation. It is found that the J-integral of shale and sandstone does not increase with crack propagation, but the J-integral of coal shows obvious increasing trend with crack propagation due to the effect of plasticity. In addition, microscopic analysis is conducted using a petrographic microscope and scanning electron microscope (SEM) to explain the plastic zone differences at the notch tips of shale, sandstone, and coal. This study is a preliminary and significant step of hydraulic fracturing application in unconventional reservoirs for efficient recovery of the berried natural gas.

HSIR-ME-CPMG: A High-Resolved Pulse Sequence for the T₁ – T₂ Measurement of Unconventional Reservoir Rocks

HSIR-ME-CPMG: A High-Resolved Pulse Sequence for the <i>T</i>₁ – <i>T</i>₂ Measurement of Unconventional Reservoir Rocks

Nanoquartz in Late Cretaceous Deposits in the Lower Berezovskaya Subformation

The Lower Berezovskaya subformation in the Upper Cretaceous is a complex reservoir with unconventional reservoir rocks located in the north of Western Siberia. The clay–siliceous deposits in the Lower Berezovskaya subformation are represented by various types of silicites that have unique petrophysical and mineralogical characteristics that cause significant difficulties in the development of associated productive layers. The aim of the research is to study their mineral composition, the parameters of the void space structure, and the conditions of formation, as well as to determine the sources of silica and perform a detailed study on the structure of nanoquartz. To study the mineral composition, the structure of the void space, and the genesis, special methodological techniques were applied, and a comprehensive analysis of the results using a wide range of laboratory studies, including optical micro- and stereoscopy, scanning electron microscopy, X-ray diffraction analysis, and microtomography, was performed. Silicites in the Lower Berezovskaya subformation are caused by the complex structure of the void space, which includes a wide range of genetic types of voids ranging from micron and submicron dimensions to fractions of a millimeter (voids confined to the burrowing organisms, intraform voids, interform voids, lenticular voids, cellular voids, and voids confined to microstylolite seams). The most widespread type of void is the interaggregate (lenticular and cellular) void, which is formed by clay (montmorillonite) scales, on the surface of which numerous α-quartz nanocrystals ranging in size from 0.05 to 0.5 microns are noted. The content of such quartz reaches up to 80% of the total volume of the rock in individual samples. The source of siliceous material for nanoquartz crystals was most likely volcanic processes, since the revealed mineral paragenesis of montmorillonite, cristobalite, and zeolites indicates the active transformation of ash material that entered the basin from volcanic formations.

Geological prerequisites for the search for rocks with increased reservoir properties in domanic type sediments on the territory of the Republic of Tatarstan

Domanic type deposits generally is abundant in Tatarstan Republic and other territories. They are feature with oil-source rocks (black shales), which partly generated hydrocarbons. However, due to their high hydrocarbon contain, domanic type deposits construing as unconventional reservoir rocks, that may be commercial significant. Based on Russian and foreign experience in the development of such deposits, the prospects for their exploitation are associated with the searching for formations with increased reservoir properties and light oil. In this work we are analyzed the stratigraphic distribution of domanic type deposits in the Kama-Kinel system of depressions and beyond them. It is shown that such deposits in the Kama-Kinel system of depressions have a thickness about 300 m and cover the stratigraphic range from semiluk horizon of the Frasnian stage to Tournaisian stage. But out of depressions these rocks occurred only in semiluk horizon. The reason of it is high dissection of the bottom of the Domanic sedimentation basin in the Late Frasnian-Tournaisian ages due to the evolution of the Kama-Kinel system of depressions in the east of the Russian Plate. The results of our own research show that carbonate and carbonate-siliceous rocks enriched in organic matter are the most common lithotypes in the Domanic type deposits. Also, we constantly found carbonate breccias and less secondary dolomites in the studied geological columns. In the last two types of rocks, we found higher values of porosity, openness, and a lighter composition of hydrocarbons. Based on the results of the author’s research and the literature observation, it follows that the development of carbonate breccias and secondary dolomites will be in the sides of the Kama-Kinel system of depressions. We consider that they are as the most promising objects for the search for industrial profit in the Domanic type deposits.

Acoustic Dispersion in Low Permeability Unconventional Reservoir Rocks and Shales at In Situ Stress Conditions

Utilizing laboratory measurements on dry and fully brine-saturated well-lithified shale reservoir rocks and comparing them to log data and theoretical modeling, we find no statistically significant intrinsic dispersion from seismic to sonic and laboratory measurement frequencies due to fluid effects. Under in situ stress conditions, the Gassmann zero-frequency P-wave velocity prediction for a Permian basin sample was within 0.3% of the measured velocity on the brine-saturated sample at an ultrasonic frequency. At deviatoric stresses ranging from 1.7 to 70 MPa on the same sample, the percent error in the Gassmann P-wave velocity prediction ranges from 0.3 to 2.2%. These results are consistent with the lack of significant dispersion in the reported velocities and theoretical predictions in the Cotton Valley shale. Based on the Biot–Gassmann model, the characteristic frequency in both formations occurs at ~1010 Hz. Applying a squirt flow model also predicts transition to the high-frequency regime occurring at ~109 Hz for both formations. The comparison of the sonic log measurements for four different shale/tight rock formations to ultrasonic measurements taken from core samples under in situ stress conditions confirms these findings. To our knowledge, this is the first extensive comparison of the sonic log to ultrasonic core data measurements. For these rocks, there is no clearly observable or predicted significant dispersion due to fluid effects at in situ stress conditions within the frequency range for which measurements are made.

A modified Guggenheim-Anderson-Boer model for analyzing water sorption in coal

The presence of water can alter the mechanical properties of coal, which may not only cause roof falls during the coal mining process but also affect the hydraulic fracturing of coalbed methane (CBM) reservoirs. The nature of water adsorption properties in unconventional reservoir rocks has been the subject of several recent papers. However, the adsorption properties and adsorption mechanism of water in coal have not been thoroughly investigated. In this study, we carried out water vapor sorption experiments on four coal samples of different maturities. We found no linear relationship between maturity and water adsorption capacity. Furthermore, we proposed that the water adsorption mechanism in coal can be divided into two types: attached to oxygen functional groups and pore filling, which occur in hydrophilic pores and hydrophobic pores, respectively. Based on the above hypothesis, a modified Guggenheim-Anderson-Boer model was proposed to interpret water adsorption isotherms. It was concluded that the differences in the water adsorption characteristics of different coals under high humidity conditions were caused by the pore volume and the proportion of hydrophilic pores. We further analyzed the influence mechanism of water adsorption on methane adsorption under high relative humidity conditions. We found that the influence of water adsorption on methane adsorption in coal can be attributed to the water adsorption amount and proportion of hydrophilic pores.

Pore characterization of unconventional reservoirs

This study proposes an image-based idea for analyzing the complex geometric characteristics of reservoir spaces using various change curves of the pore geometric attributes to subdivide and evaluate tight reservoir rocks from micron to centimeter thicknesses. Using advanced imaging and image-processing technologies, in this study, we transform information from reservoir images into a vertical stratigraphy via an imaging-based method. The new parameter system incorporates three categories of parameters, size (S), morphology (M), and direction (D), to quantitatively and comprehensively characterize the pores of unconventional reservoir rocks. Given these three categories of the parameters, the curve at a certain depth value can be used to clearly identify obvious interfaces, which constitute high tip values. These interfaces may indicate that the hydrodynamic conditions, stress conditions of the reservoir, temperature and pressure, or other physical or chemical conditions changed significantly at these points, allowing the sedimentary compaction process to be well documented at the microscale level. This indicates that, from a micro-level perspective, we can find micro-evidence of the hydrodynamic conditions at the time of formation. Such information can help strengthen our understanding of the geological formation processes of unconventional hydrocarbon reservoirs.

AFM characterization of surface mechanical and electrical properties of some common rocks

The characterization of micro-surface mechanical and electrical properties of the natural rock materials remains inadequate, and their macroscopic performance can be better comprehended by investigating the surface properties. With this purpose, the present research focuses on characterizing the micro-surface morphology, Derjaguin-Muller-Toporov (DMT) modulus, adhesion, and potential of granite, shale, and limestone by employing the atomic force microscope (AFM) as a pioneer attempt. The results show that the micro-surface morphology of the rock fluctuates within hundreds of nanometers, among which the granite micro-surface is comparatively the smoothest, followed by limestone. The morphology of the shale is the roughest, indicating that the regional difference of shale micro-surface is dominant. The distribution of the adhesion on rock micro-surface is uneven; the average adhesion of eight measuring areas for shale is 23.93 nN, accounting for three times of granite and limestone, while the surface DMT modulus of shale is relatively lower than granite and limestone. It is inferred from the obtained results that higher surface adhesion is helpful to the gas adsorption of shale, and the lower surface DMT (elastic) modulus is useful to the formation of fractures and pores. Thus, these two are the micromechanical basis of shale gas adsorption. Additionally, introducing a method to reduce the surface adhesion will benefit the exploration of unconventional resources such as shale gas. The micro-surface of the three types of rocks all shows electricity, with average potential ranging from tens of millivolts to hundreds of millivolts. Besides, the micro-surface potential of the rocks are heterogeneous, and both positive and negative points can be found. The existence and uneven distribution of micro-surface potential provide a robust physical basis for the electromagnetic radiation generated by rock fracture under loading. This study offers a new method for revealing the adsorption characteristics of unconventional gas reservoir rocks and the electromagnetic radiation mechanism of the rock fracture.

Laboratory Investigation of Hydraulic Fracture Behavior of Unconventional Reservoir Rocks

The heterogeneity of the rock fabric is a significant factor influencing the initiation and propagation of a hydraulic fracture (HF). This paper presents a laboratory study of HF created in six shale-like core samples provided by RITEK LLC collected from the same well, but at different depths. For each tested sample, we determined the breakdown pressure, the HF growth rate, and the expansion of the sample at the moment when the HF reaches the sample surface. Correlations were established between the HF parameters and the geomechanical characteristics of the studied samples, and deviations from the general relationships were explained by the influence of the rock matrix. The analysis of the moment tensor inversion of radiated acoustic emission (AE) signals allows us to separate AE signals with a dominant shear component from the signals with a significant tensile component. The direction of microcrack opening was determined, which is in good agreement with the results of the post-test X-ray CT analysis of the created HF. Thus, it has been shown that a combination of several independent laboratory techniques allows one to reliably determine the parameters that can be used for verification of hydraulic fracturing models.

CO2 storage capacity estimation under geological uncertainty using 3-D geological modeling of unconventional reservoir rocks in Shahejie Formation, block Nv32, China

Underground CO2 storage is a promising technology for mitigating climate change. In this vein, the subsurface condition was inherited a lot of uncertainties that prevent the success of the CO2 storage project. Therefore, this study aims to build the 3D model under geological uncertainties for enhancing CO2 storage capacity in the Shahejie Formation (Es1), Nv32 block, China. The well logs, seismic data, and geological data were used for the construction of 3-D petrophysical models. The target study area model focused on four units (Es1 × 1, Es1 × 2, Es1 × 3, and Es1 × 4) in the Shahejie Formation. Well logs were utilized to predict petrophysical properties; the lithofacies indicated that the Shahejie Formation units are sandstone, shale, and limestone. Also, the petrophysical interpretation demonstrated that the Es1 reservoir exhibited high percentage porosity, permeability, and medium to high net-to-gross ratios. The static model showed that there are lateral heterogeneities in the reservoir properties and lithofacies; optimal reservoir rocks exist in Es1 × 4, Es1 × 3, and Es1 × 2 units. Moreover, the pore volume of the Es1 unit was estimated from petrophysical property models, ranging between 0.554369 and 10.03771 × 106 sm3, with a total volumetric value of 20.0819 × 106 sm3 for the four reservoir units. Then, the 100–400 realizations were generated for the pore volume uncertainties assessment. In consequence, 200 realizations were determined as an optimal solution for capturing geological uncertainties. The estimation of CO2 storage capacity in the Es1 formation ranged from 15.6 to 207.9 × 109 t. This result suggests the potential of CO2 geological storage in the Shahejie Formation, China.

Study of gas slippage factor in anisotropic porous media using the lattice Boltzmann method

In unconventional reservoir rocks, pore anisotropy and gas high Knudsen number (Kn) effect are prominent, while gas slippage factor is a crucial parameter to evaluate their apparent permeability. To analyze the correlation of gas slippage factor with pore anisotropy of porous media and Kn, two-dimensional bundle models and anisotropic porous media with same characteristic length were skillfully constructed in this work. A multi-relaxation-time Lattice Boltzmann model combining diffusive reflection boundary condition and Bosanquet-type viscosity model was applied to simulate gas high-Kn flow (Kn = 0.05–0.53) in them. The results showed that Kn and pore-scale anisotropy jointly determine gas slippage factor of anisotropic porous media, which has nothing to do with porosity, specific surface area, and intrinsic permeability in nature. Pore-scale anisotropy leads to the distinct nonlinear changes of gas slippage factor with Kn. When pore-scale anisotropy factor is between 5.37 and 14.58, gas slippage factor of porous media is positively correlated with Kn. But as pore-scale anisotropy factor is in a range from 1.0 to 5.37, gas slippage factor decreases with an increase of Kn. In addition, gas slippage factor of porous media increases with an increase of pore-scale anisotropy as Kn is in a range of 0.18 to 0.53. This work further improves the understanding of gas slippage factor and gas high-Kn effect in anisotropic porous media.

Gas-water relative permeability of unconventional reservoir rocks: Hysteresis and influence on production after shut-in

Relative permeability is one of the most important parameters in reservoir modeling. However, measurements of relative permeability in unconventional reservoir rocks are rare, and the influence of relative permeability hysteresis on reservoir studies has not previously been addressed. This paper presents a systematic investigation of gas-water relative permeability and hysteresis based on a laboratory technique developed through our previous work. Gas relative permeability was measured using the modified gas expansion method under the scenario of drainage and subsequent imbibition. Water relative permeability was estimated based on Brooks-Corey (1956) equations. Results of gas-water relative permeability that cover a broader range of saturation than that in our previous work were obtained. Causes of relative permeability hysteresis are discussed in detail. The laboratory-based gas-water relative permeability of one of the samples is compared to history-matched results from the literature, and upscaling of the laboratory result is discussed on the basis of this comparison. Finally, the potential influence of relative permeability hysteresis on water and gas production after hydraulic fracturing and shut-in is illustrated through a conceptual model and quantitative analysis. Gas production rates can be overestimated after hydraulic fracturing when hysteresis is ignored. Shut-in can enhance gas production rates significantly. Enhancement of production rate is greater at the initial phase, but it diminishes later, after continuous expansion of the imbibition zone. This work presents the first known study of gas-water relative permeability hysteresis in unconventional reservoir rocks.

Experimental investigation of the effect of temperature on thermal conductivity of organic-rich shales

Experimental data on thermal conductivity of hydrocarbon reservoirs and surrounding formations at elevated temperatures are important for a variety of purposes: determining heat flow density; designing and optimizing thermal methods of enhanced oil recovery (EOR); basin and petroleum system modeling; exploitation of geothermal reservoirs; and design of radioactive waste disposal. However, there is an acute shortage of such data at present, particularly for unconventional reservoir rocks. We helped to fill this data gap by using a new, sophisticated technique to carry out thermal conductivity measurements on 28 oil shale samples from various unconventional formations in a temperature range of 30–300°С. The formations studied were Bazhenov and Abalak (West Siberia, Russia), Mendym, Domanic, Sargaev and Timan (Volga-Ural, Russia). Divided-bar and optical scanning methods were combined in the thermal conductivity measurements in order to account for thermal anisotropy and heterogeneity of the rocks and improve quality of the experimental data. Application of the optical scanning technique enabled us to select representative full-diameter or split-core samples from the continuous thermal core logging data and to choose an optimal location for drilling of core plugs from the core samples for measurement of thermal conductivity at elevated temperatures, with due account for anisotropy and heterogeneity inherent to oil shales. This approach enabled us to reveal and overcome systematic errors in previous measurements of oil shale samples using the divided-bar method and to develop an approach for the correction of measurement results. The measurements of thermal conductivity of our samples at elevated temperatures found a 5–27% decrease of rock thermal conductivity with temperature increase from 30 to 300°С. New methodology of the rock thermal conductivity determining at elevated temperatures is reported that includes a combination of two instruments: Thermal Conductivity and Thermal Diffusivity Scanner and DTC-300. It allowed to account for the contact resistance, non-ideal form of rock samples prepared for study (nonparallelism of rock samples surfaces), and changes in rock samples structure after heating.

Mineral dissolution and precipitation induced by hydraulic fracturing of a mudstone and a tight sandstone in the Powder River Basin, Wyoming, USA

Water-based hydraulic fracturing requires high-pressure injection of large quantities of water mixed with chemicals into the subsurface, where fluids contact mineral surfaces. Chemical imbalance between minerals and the injected fluids provides the potential for chemical reactions that may induce physical alterations to the rock. We investigate mineral reactivity during in situ water-rock interaction between unconventional reservoir rocks and hydraulic fracturing fluid. We characterized two unconventional reservoir rocks, a calcareous mudstone (B Bench of the Niobrara Formation) and a calcite-cemented sandstone (Wall Creek Member of the Frontier Formation) of the Powder River Basin, Wyoming, USA, and developed, analyzed, and quantified the aqueous geochemistry of a hydraulic fracturing fluid (HFF). These datasets informed the design of numerical simulations that predict mineral-HFF interactions at in situ conditions over a 31-day timeframe. The two unconventional reservoir rocks have similar mineral assemblages, albeit in different proportions, which leads to similar dissolution/precipitation reactions. Calcite, feldspar, and authigenic clay minerals begin to dissolve, and secondary calcite, anhydrite, and illite form. Calcite dissolution increases porosity of the B Bench from 2% to 2.9% and porosity of the Wall Creek from 5% to 5.8%. Mineral-fluid reactions manifest in flowback fluids as temporal geochemical trends consistent with limited field data.

Core versus cuttings samples for geochemical and petrophysical analysis of unconventional reservoir rocks

Core samples from petroleum wells are costly to obtain, hence drill cuttings are commonly used as an alternative source of rock measurements for reservoir, basin modelling, and sedimentology studies. However, serious issues such as contamination from drilling mud, geological representativeness, and physical alteration can cast uncertainty on the results of studies based on cuttings samples. This paper provides a unique comparative study of core and cuttings samples obtained from both vertical and horizontal sections of a petroleum well drilled in the Canadian Montney tight gas siltstone reservoir to investigate the suitability of cuttings for a wide range of geochemical and petrophysical analyses. The results show that, on average, the bulk quantity of kerogen or solid bitumen measured in cuttings is comparable to that of the core samples. However, total organic carbon (TOC) measurements are influenced by oil-based drilling mud (OBM) contamination. Solvent-cleaning of cuttings has been shown to effectively remove OBM contamination in light, medium, and heavy range hydrocarbons and to produce similar kerogen/solid bitumen measurements to that of core samples. Similarly, pyrolysis methods provide an alternative to the solvent-cleaning procedure for analysis of kerogen/solid bitumen in as-received cuttings. Microscopic study substantiates the presence of significant contamination by OBM and caved organic and inorganic matter in the cuttings, which potentially influence the bulk geochemistry of the samples. Furthermore, minerals in the cuttings display induced micro-fractures due to physical impacts of the drilling process. These drilling-induced micro-fractures affect petrophysical properties by artificially enhancing the measured porosity and permeability.

Modeling gas relative permeability in shales and tight porous rocks

Accurate modeling of gas relative permeability (krg) has practical applications in oil and gas exploration, production and recovery of unconventional reservoirs. In this study, we apply concepts from the effective-medium approximation (EMA) and universal power-law scaling from percolation theory. Although the EMA has been successfully used to estimate relative permeability in conventional porous media, to the best of our knowledge, its applications to unconventional reservoir rocks have not been addressed yet. The main objective of this study, therefore, is to evaluate the efficiency of EMA, in combination with universal power-law scaling from percolation theory, in estimating krg from pore size distribution and pore connectivity. We presume that gas flow is mainly controlled by two main mechanisms contributing in parallel: (1) hydraulic flow and (2) molecular flow. We then apply the EMA to determine effective conductances and, consequently, krg at higher gas saturations (Sg), and the universal scaling from percolation theory at lower Sg values. Comparisons with two pore-network simulations and six experimental measurements from the literature show that, in the absence of microfractures, the proposed model estimates krg reasonably well in shales and tight porous rocks. More specifically, we found that the crossover point – gas saturation (Sgx) at which transport crosses from percolation theory to the EMA – is non-universal. The value of Sgx is a function of pore space characteristics such as pore size distribution broadness and critical gas saturation. This means that one should expect Sgx to vary from one rock sample to another.

Estimation of Capillary Pressure in Unconventional Reservoirs Using Thermodynamic Analysis of Pore Images

AbstractUnconventional reservoirs comprise a growing portion of producible reserves due to increasing knowledge of their nature as well as significant advances in production technology. The development of advanced pore‐scale modeling techniques presents potential for better estimation of reservoir flow characteristics including relative permeability, saturation distributions, and capillary pressure. Although pore‐scale network models take into account the pore throat connections and the appropriate fluid properties, highly simplified pore cross‐sectional shapes are still employed when estimating the threshold capillary pressure for fluid‐fluid displacements in each pore element. As a result, there is a growing need for more realistic threshold capillary pressure estimates generated using pore geometries that honor the real pore topology. To this end, a semianalytical model is presented that allows the prediction of threshold capillary pressure as well as the capillary pressure versus saturation relationship for piston‐like fluid displacements using images of unconventional reservoir rock samples. The model was validated on three different idealized pore geometries and compared against available analytical solutions, resulting in an error of less than 1% for all cases. The model was compared to experimental data using fluid occupancy maps obtained using an X‐ray nano‐CT scanner during an oil imbibition sequence into a miniature reservoir shale sample. The capillary pressure versus wetting phase saturation relationship was also determined for a 2‐D focused ion beam scanning electron microscopy image slice. The presented model shows promise for enabling more advanced pore‐scale modeling of shale rock.

Nanoscale pore structure and mechanical property analysis of coal: An insight combining AFM and SEM images

Scanning Electron Microscopy (SEM) and Atomic Force Microscope (AFM), two easily acquired and widely applied image acquisition and analysis methods, have rarely been combined to study the pore structure for unconventional natural gas reservoir rocks. In this work, we present an investigation of nanoscale detection of the pore distribution and mechanical properties of coals using SEM and AFM observations, and conduct quantitative analyses on pore structure distribution, surface roughness and mechanical properties. The morphological characteristics of the coal surface can be revealed by both SEM and AFM methods, and the mechanical parameters of the selected position were obtained under the peakforce quantitative nano-mechanics (PF-QNM) AFM mode, including the Young's modulus, peak force error, deformation, and adhesion forces. By fusing 800 high resolution SEM images into one single image (named as MAPS), the pores morphology and distribution of different scales were acquired. And the studied coal shows different types of cellular pores and gas pores with multiresolution. The mechanical property difference between the matrix and minerals of coal are clearly observed, with the Young’s modulus of organic component around 2 GPa, and that of the minerals generally higher than 10 GPa. The maximum adhesion force values range between 20 and 50 nN. The high values occurred where pores are developed. This work demonstrated that the combination of two dimensional (2D) SEM and three dimensional (3D) AFM results is effective in detection of surface properties, and is of significance in revealing the pore structure and mechanical properties at nanoscale.

Gas Relative Permeability and its Evolution During Water Imbibition in Unconventional Reservoir Rocks: Direct Laboratory Measurement and a Conceptual Model

SummaryRelative permeability has a significant impact on gas or oil and water production, and is one of the most complicated properties in unconventional reservoirs. Current understanding of relative permeability for unconventional reservoir rocks is limited, mainly because of a lack of direct measurement of relative permeability for rocks that have a matrix permeability at the submicrodarcy level. Because of the difficulties related to direct measurement, most studies on relative permeability in unconventional reservoirs are based on indirect or modeling methods. In this paper, a modified gas–expansion method for shale matrix–permeability measurement (Peng et al. 2019) was adopted to measure gas relative permeability directly under the scenario of water imbibition for samples from different unconventional reservoir formations. Evolution of gas permeability, along with gas porosity and fracture/matrix interaction, during the process of water redistribution (which mimics what occurs in the shut–in period in real production) was also closely measured. Results show that gas relative permeability in the matrix decreases during water redistribution because of water imbibition from fractures to the matrix coupled with a water–block effect. The water–block effect is more significant at low water saturations than at higher water saturations, leading to a rapid–to–gradual drop of gas relative permeability with increasing water saturation.A conceptual model on water redistribution in a fracture/matrix system and the change of gas and water relative permeability is proposed on the basis of experimental results and observations. Influencing factors including pore size, shape, connectivity, and wettability are taken into account in this conceptual model. The combined effect of these four influencing factors determines the level of residual gas saturation, which is the most important parameter in defining the shape of relative permeability curves. Water relative permeability is predicted on the basis of the conceptual model and the measured gas relative permeability using modified Brooks–Corey equations. Deducing the oil/water relative permeability is also discussed. The implications of relative permeability for gas or oil and water production and potential strategies for optimal production are also discussed in the paper. The hysteresis effect is not included in this study but will be addressed in future work.

Geochemical Productivity Index (Igp): An Innovative Way To Identify Potential Zones With Moveable Oil in Shale Reservoirs

Summary In this paper we present a method for identifying intervals in shale oil reservoirs that contain moveable hydrocarbons with a novel geochemical productivity index (PI), Igp. This index merges three important rock properties that must always be considered for sound shale oil reservoir characterization: vitrinite reflectance (%Ro), oil–saturation index (OSI), and free–water porosity (ϕFW). Integrating this index with other petrophysical properties and geomechanical parameters defines intervals with high moveable oil content. Shale oil is both a source rock and an unconventional reservoir rock. Hence, it is critical to know both its organic–matter (OM) maturity and its oil/water flow capacity. The introduced Igp considered these features simultaneously; maturity was evaluated by discretizing %Ro from 0 to 1, depending on whether the rock was immature or not; free oil flow capacity modeled the normalizing OSI between 0 and 1 on the basis of results from the Rock-Eval VI pyrolysis (REP) obtained in the laboratory or by electric logs; and water flow capacity was estimated from ϕFW, obtained using a nuclear–magnetic–resonance (NMR) log, which was transformed into an index between 0 and 1. Flow oil capacity was defined as the amount of moveable oil that exceeded the sorption capacity of the source rock. Using the Igp is explained with real data from a vertical well that penetrates several stacked shale oil reservoirs. However, the same approach can be used in any other type of wellbore architecture (i.e., deviated, horizontal, geosteered). Initially, a correlation between vertical depth and %Ro was developed. This resulted in a continuous OM–maturity curve along the well section. Next, OSI was simulated by using a bin porosity from an NMR log, where T2 was between 33 and 80 milliseconds and was correlated with OSI data from REP. As a result, a good match between the simulated and the real OSI data was achieved. Similar to OSI, ϕFW was also calculated from the NMR log, but it used a bin porosity when T2 was greater than 80 milliseconds. These three parameters were then transformed to fractional indices, which were combined into a unique index, Igp. When the index was greater than 0.66, there was a good chance that the three conditions mentioned above would be met. For the example well considered in this study, it was found that almost 30% of the total vertical section had good moveable oil potential. This corresponded to 10 intervals in the well. The key novelty of this paper is that we have developed a continuous curve of an index that is easy to use and is powerful for identifying intervals with moveable hydrocarbon potential. This is true even in those intervals without laboratory data because of the continuity of the Igp curve, in addition to the Igp integrated criteria that are usually applied independently. The Igp index is a simple–to–use approach. However, because it is a new method, an explorationist should validate it against real oil production information.