Shale Porosity Research Articles

On a Deep Learning Method of Estimating Reservoir Porosity

Porosity is an important parameter for the oil and gas storage, which reflects the geological characteristics of different historical periods. The logging parameters obtained from deep to shallow strata show the stratigraphic sedimentary characteristics in different geological periods, so there is a strong nonlinear mapping relationship between porosity and logging parameters. It is very important to make full use of logging parameters to predict the shale content and porosity of the reservoir for precise reservoir description. Deep neural network technology has strong data structure mining ability and has been applied to shale content prediction in recent years. In fact, the gated recurrent unit (GRU) neural network has further advantage in processing serialized data. Therefore, this study proposes a method to predict porosity by combining multiple logging parameters based on the GRU neural network. Firstly, the correlation measurement method based on Copula function is used to select the logging parameters most relevant to porosity parameters. Then, the GRU neural network is used to identify the nonlinear mapping relationship between logging data and porosity parameters. The application results in an exploration area of the Ordos basin show that this method is superior to multiple regression analysis and recurrent neural network method, which indicates that the GRU neural network is more effective in predicting a series of reservoir parameters such as porosity.

Supercritical CO2 fracturing with different drilling depths in shale

ABSTRACT Shale gas is a crucial unconventional natural gas; carbon dioxide is a serious greenhouse gas. Therefore, using supercritical carbon dioxide as a fracturing fluid can fracture shale reservoirs and exploit shale gas as well as store carbon dioxide to slow the greenhouse effect. In this study, supercritical carbon dioxide fracturing experiments were conducted at different drilling depths. They showed that structural failure pressure decreased with the increase in borehole and sealing lengths owing to the larger excavation damage zone induced by borehole drilling. During the fracturing process, acoustic emission signals were recorded, which exhibited similar development tendencies, and this process could be divided into four parts based on the acoustic emission characteristic. The saltation of fluid pressure was due to the saltation of isothermal compression and expansion occurring in phase change processes. Moreover, crack morphology before and after the fracturing were scanned and rebuilt by computed tomography instruments, which displayed that an effective fracturing crack could be generated by supercritical carbon dioxide. Although the cark morphology was relatively simple, a complex crack could be formed at a deep drilling depth as revealed by the comparisons of the box dimension, crack perimeter, and crack area at different drilling depths. Based on the acoustic emission accumulation counts, a damage variable was introduced to describe failure degree. Furthermore, based on a previous work and the damage characteristic and fluid pressure features, the entire process of supercritical carbon dioxide fracturing could be divided into five main stages. In addition, the chemical reaction between the shale matrix and the fracturing fluid was analyzed. The supercritical fracturing fluid could dissolve and remove substances, improving the shale porosity and connectivity.

Multiscale characterization of shale pore-fracture system: Geological controls on gas transport and pore size classification in shale reservoirs

A sound understanding of the pore-fracture system across all scales provides an in-depth look at the intricate gas transport mechanisms in shale reservoirs. We performed a comprehensive multiscale characterization analysis on the Longmaxi shale samples using five complementary techniques: low-temperature gas (N2) adsorption (LTGA), mercury intrusion porosimetry (MIP), nuclear magnetic resonance (NMR), field emission scanning electron microscopy (FE-SEM), and X-ray computed tomography (CT) scanning. For pore size distribution (PSD) determination, LTGA (N2) analysis can detect small pores (2–300 nm sized), while MIP analysis is suitable for large pores or fractures (> 300 nm). NMR can reveal full-scale PSD characteristics of shale. Combining NMR with LTGA or MIP is recommended, since NMR alone would over- or under-estimate the pore size. The Longmaxi shale pores observed by FE-SEM imaging are of good connectivity and, by and large, are tens of nanometers sized. The scale-dependent analysis shows that the representative elementary volume (REV) for porosity of the Longmaxi shale based on FE-SEM imaging is almost 600 μm. As evident from the CT scanning, the connectivity of the entire shale pore-fracture system increased significantly after saturating the sample with water. The gas slippage (Klinkenberg) effect is significant at relatively low pressures. A second-order model would better estimate the intrinsic permeability compared with the traditional Klinkenberg equation. Microfractures manifest preferred orientation or alignment parallel to the shale bedding plane and are the dominant pathways for gas transport in shale. Finally, we proposed a new pore size classification of shale considering gas transport mechanisms: adsorption pores (pore size < 10 nm), slippage pores (10 nm < pore size < 1000 nm), and seepage pores or fracture-pores (pore size > 1000 nm). Although slippage pores dominate in terms of the total volumetric contribution of the Longmaxi shale, with a clear presence of adsorption pores, overall gas transport in shale is predominantly controlled by the seepage pores (fracture-pores), which constitute a very small portion of the total volume.

A new application of atomic force microscopy in the characterization of pore structure and pore contribution in shale gas reservoirs

The pore structure determined by different materials is extremely significant for shale gas accumulation. Understanding how different materials contribute to the pore remains a knowledge gap. To elucidate the surface property and pore structure qualitative and quantitative characteristics of gas-bearing shales, the Atomic Force Microscopy (AFM) and low-temperature nitrogen gas adsorption (LT-N2GA) experiments were performed on shale samples selected from the Longmaxi Formation (Fm.) in the Sichuan Basin in China in this study. A new method based on AFM technique was used to calculate shale porosity, and the double-threshold discrete integration method was proposed to estimate the pore contributions of main materials. The results show that the organic-rich shale is significantly different from the organic-poor shale in material composition. The average value of mean roughness (Ra) of the organic-rich and organic-poor shale samples are 38.74 nm and 104.58 nm, respectively, indicating that the organic-poor shale has a rougher surface. The average value of mean square roughness (Rq) of the organic-rich and organic-poor shale samples are 49.91 nm and 138.80 nm, respectively, indicating that the organic-poor shale has a severer variation degree. Moreover, organic-poor shale samples also have a more concentrated height distribution. The average surface porosity of the organic-rich shale and organic-poor shale are 17.08% and 3.31% respectively. The average form factor (ff) of the organic-rich shale and organic-poor shale are respectively 0.102 and 0.386. It indicates that organic-rich shale has more pores and more complicated pore boundaries than organic-poor shale. AFM-calculated porosity is consistent with that of LT-N2GA-converted, which indicates that the porosity calculated by AFM is real porosity and reliable. The essence of the phase change on the shale surface is the difference in material composition. Shale pores are mainly contributed by organic matter, followed by chlorite, potash feldspar, and quartz. The results show that our method provides a powerful and effective tool to characterize the nanopore structure of organic rocks, obtain shale reservoir physical properties, and analyze pore contribution of shale components etc. issues, which has a wide application prospect.

Experimental determination of porosity and methane sorption capacity of organic-rich shales as a function of effective stress: Implications for gas storage capacity

Gas storage capacity estimates of shales are routinely assessed using laboratory data from unconfined methane sorption and porosity measurements. In this study, the stress dependence of the methane excess sorption capacity and specific pore volume are investigated simultaneously. Experiments were performed on dry core plugs (Cambrian–Ordovician Alum, Jurassic Bossier, Late Cretaceous Eagle Ford, and Jurassic Kimmeridge shales) at 30°C under controlled confining stress up to 40 MPa and gas pressures up to 20 MPa. Increasing overburden stress results in a significant decrease of both specific pore volume and excess sorption capacity. The stress sensitivity of the specific pore volume was most prominent for the total organic carbon (TOC)–rich Kimmeridge sample (45% TOC) and further decreased in the order of Bossier, Eagle Ford, and Alum. Stress dependence of the methane excess sorption capacity, expressed as percentage reduction at 40-MPa overburden as compared to unconfined conditions, decreases in the order Eagle Ford (∼56%), Bossier (∼30%), Kimmeridge (∼14%), and Alum (∼5%). Although the decrease of specific pore volume is definitely caused by poroelastic compression, the mechanism(s) leading to the reduction of excess sorption capacity with stress require further investigation. Gas storage calculations show that routine methods based on unconfined data may grossly overestimate the total storage capacity. In this scenario, at 2500-m depth, the total gas storage capacity will be overestimated by 5% for the Alum, 28% for the Bossier, 18% for the Eagle Ford, and 28% for the Kimmeridge if the stress dependent reduction of volume and sorptive storage capacity is not considered.

셰일 및 치밀 저류층의 지화학 및 암석물리 특성 연구동향 고찰

Shale reservoirs has drawn great attention among unconventional resources since the first unconventional extraction of gas from Barnett Shale by Mitchell in 1998. In the beginning, carpet drilling and hydraulic fracturing to shale reservoirs made a great benefit without detailed geological understanding. However, the sudden increase of gas supply and international economic crisis resulted in lower gas price relative to oil price, which requires more detailed development optimization and geological characterization on shale reservoirs to reduce operation cost. In order to evaluate the productivity of shale and tight reservoirs, it is necessary to accurately predict the amount of gas stored in the reservoir. To calculate exact volume of gas in reservoirs, we must reliably measure petrophysical parameters such as permeability, porosity, and water saturation to estimate free gas volume, and geochemical parameters such as total organic carbon (TOC) and adsorption capacity to estimate desorbed gas volume. Several measurement techniques have been proposed to overcome the difficulty in very low porosity and permeability of shale and tight reservoirs. Recently, the crushed rock technique have been used for porosity and permeability of shale and tight reservoir are measured, but the standard procedures have not yet been established. Water saturation is another hurdle since actual measurements are extremely difficult and time-consuming. Modified conventional equations have been tried, but there are still various limitations. We also cover currently available techniques and their limitations on TOC, a measure for gas generation potential, and adsorption capacity. Currently, measurement techniqies for petrophysical and geochemical properties of shale and tight reservoirs are not fully established. There should be detailed studies for the accurate estimation of these properties, which can lead successful reservoir characterization.

Porosity and Water Saturation Estimation for Shale Reservoirs: An Example from Goldwyer Formation Shale, Canning Basin, Western Australia

Porosity and water saturation are the most critical and fundamental parameters for accurate estimation of gas content in the shale reservoirs. However, their determination is very challenging due to the direct influence of kerogen and clay content on the logging tools. The porosity and water saturation over or underestimate the reserves if the corrections for kerogen and clay content are not applied. Moreover, it is very difficult to determine the formation water resistivity (Rw) and Archie parameters for shale reservoirs. In this study, the current equations for porosity and water saturation are modified based on kerogen and clay content calibrations. The porosity in shale is composed of kerogen and matrix porosities. The kerogen response for the density porosity log is calibrated based on core-based derived kerogen volume. The kerogen porosity is computed by a mass-balance relation between the original total organic carbon (TOCo) and kerogen maturity derived by the percentage of convertible organic carbon (Cc) and the transformation ratio (TR). Whereas, the water saturation is determined by applying kerogen and shale volume corrections on the Rt. The modified Archie equation is derived to compute the water saturation of the shale reservoir. This equation is independent of Rw and Archie parameters. The introduced porosity and water saturation equations are successfully applied for the Ordovician Goldwyer formation shale from Canning Basin, Western Australia. The results indicate that based on the proposed equations, the total porosity ranges from 5% to 10% and the water saturation ranges from 35% to 80%. Whereas, the porosity and water saturation were overestimated by the conventional equations. The results were well-correlated with the core-based porosity and water saturation. Moreover, it is also revealed that the porosity and water saturation of Goldwyer Formation shale are subjected to the specific rock type with heterogeneity in total organic carbon total clay contents. The introduced porosity and water saturation can be helpful for accurate reserve estimations for shale reservoirs.

Numerical simulation on the in situ upgrading of oil shale reservoir under microwave heating

Microwave heating shows great potential in pyrolyzing oil shale with fast heating rate in many laboratory experiments. There are few studies based on numerical simulations to investigate the technical and economic feasibility of microwave on the in situ upgrading of oil shale reservoir. In this study, the mathematical models including electromagnetic field, heat transfer, chemical engineering, mass transfer and fluid flow were presented to simulate the temperature distribution, kerogen decomposition, and production efficiency of oil and gas under microwave heating. The effects of output power level and thermal conductivity of oil shale on the reservoir temperature distribution were investigated to fully understand the mechanism of microwave exploitation. To avoid the superheat region around the heaters, the intermittent heating and stepwise heating modes were proposed and proved to be practical. Also, stepwise microwave heating mode showed better performance than electrical heating in terms of production efficiency and energy consumption. Under microwave irradiation, both porosity and permeability of oil shale can be highly enhanced. Moreover, the seepage channels of the reservoir can also be improved by hydraulic fracturing. Eventually, the time for opening the production well is optimized in order to reduce the secondary oil cracking. The flowing field added into the existing model highly influences the reservoir temperature distribution, kerogen decomposition, and production yield. The results from this study can provide comprehensive understanding of microwave exploitation for oil shale upgrading and valuable guideline for optimizing engineering parameters.

P.771 Deciphering pharmacological mechanism of neurotrophic activity of steroidal chlorohydrin by proteomic, immunocytochemical and computational approach

Wufeng-Longmaxi Formations shale gas is a new exploration field in Wuxi area, Sichuan Basin, China. Some geological parameters related to shale gas evaluation of the new exploration wells in Wuxi area have been studied, including shale reservoir, gas-bearing, geochemical and paleontological characteristics. The study suggests that the original shale gas generation conditions of the area were good, but later this area went through serious and multi-phase tectonic damage. The major evidences include that: the δ13C2 value of shale gas is obviously higher than that in areas with the same maturity, indicating the shale gas is mainly late kerogen cracking gas and high hydrocarbon expulsion efficiency; the porosity of shale in Wuxi area is very low because of strong tectonic movements and lack of retained oil in the shale; some shale cores near faults even show very weak metamorphic characteristics with intense cleavage, and the epidermis of graptolite fossils was pyrolyzed. The comprehensive study shows shale gas in Wuxi area has prospective resources, but the possibility to get scale commercial production in recent time is very low.

Application of nuclear magnetic resonance logging in the low-resistivity reservoir — Taking the XP area as an example

With the deepening of exploration and development, many low-resistivity reservoirs have been found in the XP area. We have found that the genesis of these low-resistivity reservoirs is that they contain a lot of very fine sand, which leads to the high content of bound water in the reservoirs and reduces resistivity. Compared with normal oil reservoirs, these reservoirs show low resistivity and high natural gamma, which makes it difficult to identify reservoirs qualitatively and calculate parameters quantitatively. Using conventional logging interpretation methods, the wrong shale content and porosity will be obtained, and such reservoirs may even be judged as mudstones. To solve this problem, we extract a characteristic parameter from the T2 spectrum of nuclear magnetic resonance (NMR) logging, which can effectively identify such reservoirs. In addition, we have innovatively adopted an optimized logging interpretation method for integrated NMR logging and conventional logging, which has effectively improved the parameter calculation accuracy of this type of reservoir and achieved a good application effect in the XP area.

A simulation study of the effect of clay swelling on fracture generation and porosity change in shales under stress anisotropy

The simulation study of the effect of clay swelling on fracture generation and porosity change in shale rocks is of great significance for applying hydraulic fracturing in the development of shale reservoirs in the petroleum industry. However, previous simulations did not consider the heterogeneous characteristics of shales. Besides, it is not clear how the swelling stresses are distributed owing to swelling inside shales. In this paper, we employ a discrete element method (DEM) modeling, which is combined with the CT images and MATLAB coding, to predict the effect of clay swelling on fracture generation and porosity change in shales under stress anisotropy. We are able to successfully simulate the effect of clay swelling on fracture generation and porosity change in heterogeneous shales under stress anisotropy by employing the discrete element method (DEM) modeling. Clay content is the key factor in fracture generation and the resulted porosity change. For shales with high clay content, clay swelling has contributions to the recovery of shale's porosity. The von Mises stress maps show that the stress inside the model is highly anisotropic and the maximum effective stresses concentrate on the fractures' areas. The larger the pressure is applied to the sample, the larger the von Mises stress can be observed. Stress anisotropy is a positive factor in fracture generation in the process of water-shale interaction. The degree of the clay swelling and the heterogeneity of samples are two factors that could influence the results.

Laponite: a promising nanomaterial to formulate high-performance water-based drilling fluids

High-performance water-based drilling fluids (HPWBFs) are essential to wellbore stability in shale gas exploration and development. Laponite is a synthetic hectorite clay composed of disk-shaped nanoparticles. This paper analyzed the application potential of laponite in HPWBFs by evaluating its shale inhibition, plugging and lubrication performances. Shale inhibition performance was studied by linear swelling test and shale recovery test. Plugging performance was analyzed by nitrogen adsorption experiment and scanning electron microscope (SEM) observation. Extreme pressure lubricity test was used to evaluate the lubrication property. Experimental results show that laponite has good shale inhibition property, which is better than commonly used shale inhibitors, such as polyamine and KCl. Laponite can effectively plug shale pores. It considerably decreases the surface area and pore volume of shale, and SEM results show that it can reduce the porosity of shale and form a seamless nanofilm. Laponite is beneficial to increase lubricating property of drilling fluid by enhancing the drill pipes/wellbore interface smoothness and isolating the direct contact between wellbore and drill string. Besides, laponite can reduce the fluid loss volume. According to mechanism analysis, the good performance of laponite nanoparticles is mainly attributed to the disk-like nanostructure and the charged surfaces.

Study on the characterization of pore structure and main controlling factors of pore development in gas shale

Shale has a complex pore structure, which leads to complex petrophysical characteristics. The porosity, pore type, pore size, pore volume, TOC, and other petrophysical parameters of shale all affect the shale gas content. Therefore, using multiple methods to jointly characterize the pore structure of shale with different gas content and study on the main controlling factors of pore development have an important guiding role in the exploration and development of shale gas. In this study, we carry out gas shale samples in different areas. The samples collected from wells in the Sichuan Basin have high gas content, collected from wells near the Pengshui, and Tongren areas have medium gas content and collected from wells near the Guiyang area have low gas content. Shale in these areas with different gas production has been characterized, by the integration of geophysical and petrophysical data, in terms of pore type and pore connectivity, including X-ray diffraction, low-field Nuclear Magnetic Resonance (NMR), low-pressure N2 and CO2 adsorption isotherms, porosity, permeability, thin-section observations, scanning electronic microscopy (SEM) and mercury injection capillary pressure (MICP) measurement. The results show that the pore types are clay mineral intercrystalline pores and intergranular pores, rock skeleton mineral pores, organic pores, and micro-fractures. The high gas-bearing shale has a small pore size, a large specific surface area, and pore volume, and the T2 distribution is bimodal, with a peak value around 1 ms. It shows that micropores and mesopores are widely developed in high gas-bearing shale, which provides the main place for adsorbing gas, especially shale with high TOC content. During the hydrocarbon generation process, a large number of organic pores favorable for gas adsorption will be produced. The low gas-bearing shale has a large pore size, a small specific surface area, and pore volume, and the T2 distribution presents a bimodal shape with a wider peak and the lowest spectral value. This shows that low gas-bearing shale mainly develops macropores and micro-fractures, and the pore connectivity is good, especially the interconnection between small pores and fractures, which leads to gas escape. In the high gas-bearing samples, bone needles and radiolaria are distributed in large quantities, and the silicon content of biological sources is high, which provides a lot of organic matter. In the low gas-bearing samples, the horizontal layer is not developed and the mineral particles are evenly distributed.

Reservoir heterogeneity of the Longmaxi Formation and its significance for shale gas enrichment

AbstractTo better determine the sweet spot in the vertical profile of the Longmaxi Formation, the shale heterogeneity was systematically investigated. A series of experiments were conducted on 40 shale samples collected from the Lower Silurian Longmaxi Formation in the Weiyuan shale gas field. The results indicated that total organic carbon (TOC), the mineral composition, methane adsorption capacity, and porosity of the four sub‐layers in the Longmaxi shale varied significantly. In terms of the TOC, the mid‐lower Long111 had the highest value, followed by Long113, while the TOC values of Long112 and Long114 were quite low. As for mineral composition, the mid‐lower Long111 had the highest quartz content, Long112 and Long113 had equivalent quartz, carbonate, and clay mineral contents, and Long114 had higher clay mineral and carbonate contents, but a lower quartz content. Shale porosity and methane adsorption capacity were the highest in the mid‐lower Long111, followed by Long113, Long112, Long114, and the upper Long111. The micro‐heterogeneity represented by the fractal dimension ranged from 2.590 to 2.750, with an average of 2.670. The mid‐lower Long111 had the largest fractal dimension, followed by Long113, Long112, Long114, and the upper part of Long111 had the smallest fractal dimension. The sedimentary environment controls the macro‐heterogeneity in the vertical profile. The micro‐heterogeneity depends on diagenesis, which can be investigated by the different effects of minerals on micropore development. The strong micro‐heterogeneity results in better preservation conditions for shale gas. The mid‐lower Long111 was rich in gas generation material (TOC) with enough storage space and is characterized by good preservation conditions, leading to the highest gas content of the four sub‐layers. In addition, the high brittle mineral content is conducive to fracturing and the formation of a fracture network. Thus, the middle ‐Long111 is the “sweet spot” in the vertical profile for the shale gas development.

Variation in pore systems with tectonic stress in the overthrust Wufeng-Longmaxi shale of the southern Sichuan Basin, China

Pore evolution in organic-rich shale is widely reported to be related to thermodynamic reactions, but its connection with tectonic deformation is overlooked. A systematic comparative analysis was conducted in the Changning area to detect the tectonic deformation of organic-rich shale. The study encompassed mineralogical composition, petrography, and porosity, along with the state of tectonic stress and pore pressure in the Wufeng-Longmaxi shale of a basement-involved fold-thrust belt located in the southern Sichuan Basin. The content of both total organic carbon (TOC) and clay mineral was correlated with bulk porosity, indicating the relevance and impact of both organic and inorganic pores on bulk porosity. However, samples with a constant TOC or clay mineral content exhibited lower bulk porosity in wells located on the forelimb than in wells located on the crest and backlimb of the overthrust anticline. The variably elongated and slot-like morphology as well as the crude alignment of organic pores in samples from wells on the anticline forelimb suggest that the organic pores collapse under tectonic deformation. This observation was different from that of the spherical morphology of organic pores in samples from wells on the backlimb of an overthrust anticline. The ratio of horizontal stress to vertical stress (Shmin/Sv or SHmax/Sv), simulated from well logs, was negatively correlated with the median bulk porosity in the Wufeng-Longmaxi shale within various cores. This suggests that a larger strain, under higher horizontal compression stress, decreased the bulk porosity in the shale of the forelimb areas, despite the content of the mechanically weak component (e.g., TOC or clay minerals) being similar in both. Additionally, the Wufeng-Longmaxi shale generally exhibited a higher pore pressure, but lower bulk porosity, in wells on the forelimb relative to the backlimb, which indicates that the collapsed pore system has, to some extent, inhibited the relief of maturation-induced overpressure during exhumation.

Lithology and Fluid discrimination of Sody field of the Nigerian Delta

The lithology and fluid discrimination of an onshore Sody field, of the Niger Delta was studied using gamma ray, resistivity and density logs from three wells in the field in order to evaluate the field’s reservoir properties. Two reservoir sands (RES 1 and RES 2) were delineated and identified as hydrocarbon bearing reservoirs. The petrophysical parameters calculated include total porosity, water saturation and volume of shale. The results obtained revealed that the average porosity of the reservoir sands, range from 21% to 39%, which is excellent indicator of a good quality reservoir and probably reflecting well sorted coarse grain sandstone reservoirs with minimal cementation. Water saturation is low in all the reservoirs, ranging from 2% to 32%, indicating that the proportion of void spaces occupied by water is low, and implying high hydrocarbon saturation. The crossplot discriminated the reservoirs lithologies as sand, shaly sand and shale sequences, except well Sody 2 which differentiated its lithologies as sand and shale sequences and distinguished the reservoirs’ litho-fluids into three, namely; gas, oil and brine. These results suggest that the reservoirs sand units of Sody field contain significant accumulations of hydrocarbon.&#x0D; Keywords: Reservoir, porosity, net-to-gross, impedance, lithology

Study of CO2 Enhancing Shale Gas Recovery Based on Competitive Adsorption Theory.

As an indispensable part of unconventional natural gas resources, the shale reservoir is huge and widely distributed. It is of great significance to study how to enhance the shale gas recovery for improving the energy structure. In order to solve the problem of low gas production rate and long recovery period in the process of shale gas production, in this paper, the influences of pressure, temperature, moisture, and gas type on isothermal adsorption and desorption of shale gas are analyzed based on shale adsorption and desorption experiments, and the adsorption and desorption abilities of CO2 and CH4 in shale are compared to verify the feasibility of CO2 enhancing shale gas recovery. Depletion production experiments and CO2 injection experiments with different injection pressures (6 and 7 MPa), different injection rates (5, 10 and 20 mL/min), and different injection amounts are carried out. The mechanism of CO2 enhancing shale gas recovery is proposed, and the parameters of CO2 injection are optimized. The results show that the adsorption capacity of CH4 increases with the increase in pressure and the decrease in temperature and moisture in a certain range. Under the same experimental conditions, the sorting of adsorption capacity is CO2 > CH4 > N2, while desorption capacity is CH4 > CO2 > N2. The desorption curves of the three gases lag behind the adsorption curves, in which the lag phenomenon of CO2 is most obvious. The ultimate recovery of depletion production ranges from 66 to 73%. CO2 injection can effectively increase the gas production rate of CH4, and it can also keep the cumulative gas production of CH4 growing steadily and rapidly. Within a certain range, CH4 recovery increases with the increase in CO2 injection pressure, the injection rate, and injection amount, but its increase range is related to the porosity and permeability of shale.

Petrophysics Analysis for Reservoir Characterization of Cretaceous Clastic Rocks: A Case Study of the Arafura Basin

This study presents petrophysics analysis results from two wells located in the Arafura Basin. The analysis carried out to evaluate the reservoir characterization and its relationship to the stratigraphic sequence based on log data from the Koba-1 and Barakan-1 Wells. The stratigraphy correlation section of two wells depicts that in the Cretaceous series a transgression-regression cycle. The petrophysical parameters to be calculated are the shale volume and porosity. The analysis shows that there is a relationship between stratigraphic sequences and petrophysical properties. In the study area, shale volumes used to make complete rock profiles in wells assisted by biostratigraphic data, cutting descriptions, and core descriptions. At the same time, porosity shows a conformity pattern with the transgression-regression cycle.Keywords: petrophysics, reservoir characterization, Cretaceous, transgressive-regressive cycle

Multifractal characteristics of shale and tight sandstone pore structures with nitrogen adsorption and nuclear magnetic resonance

Based on the experiments of nitrogen gas adsorption (N2GA) and nuclear magnetic resonance (NMR), the multifractal characteristics of pore structures in shale and tight sandstone from the Chang 7 member of Triassic Yanchang Formation in Ordos Basin, NW China, are investigated. The multifractal spectra obtained from N2GA and NMR are analyzed with pore throat structure parameters. The results show that the pore size distributions obtained from N2GA and NMR are different, and the obtained multifractal characteristics vary from each other. The specific surface and total pore volume obtained by N2GA experiment have correlations with multifractal characteristics. For the core samples with the similar specific surface, the value of the deviation of multifractal spectra Rd increases with the increase in the proportion of large pores. When the proportion of macropores is small, the Rd value will increase with the increase in specific surface. The multifractal characteristics of pore structures are influenced by specific surface area, average pore size and adsorption volume measured from N2GA experiment. The multifractal characteristic parameters of tight sandstone measured from NMR spectra are larger than those of shale, which may be caused by the differences in pore size distribution and porosity of shale and tight sandstone.

Integrated petrophysical evaluation of the Lower Middle Bakken Member in the Viewfield Pool, southeastern Saskatchewan, Canada

The Viewfield Pool of the Lower Middle Bakken Member, the largest light oil pool in Saskatchewan, Canada has been described as an unconventional resource play. Reservoir evaluation in this pool has been challenging because of low permeability, complex lithology and reservoir heterogeneity. To address the difficulties, this study employed an integrated approach to derive reservoir parameters and provided a detailed petrophysical characterization of the Viewfield Middle Bakken play, which led to a division of Unit A, the Lower Middle Bakken Member into two subunits: A1 for the lower interval and A2 for the upper interval. Petrophysical models were developed based on thorough analyses of core measurements, conventional well logs and available advanced nuclear magnetic resonance (NMR) well log data. The proposed models were applied to determine reservoir properties including shale content, porosity, permeability and water saturation for the two subunits in 163 vertical wells among which three have NMR logs. The results reveal that subunits A1 and A2 differ significantly in petrophysical properties and reservoir quality. A2, the very fine-grained dolomitic sandstone subunit has larger pore size, higher porosity and permeability, lower shale content and water saturation, and thus represents the preferred interval for oil production across the Viewfield Bakken Pool area and has greater resource potential than the siltstone subunit A1. The mapped petrophysical properties show spatial trends that align well with the previously recognized regional geological features. Favourable potential high productivity zones can be outlined by the areas of intersection of all essential reservoir parameters above defined threshold values.