Oil Shale Field Research Articles

Application of Simul-frac technology in Longdong shale oil field

Abstract This paper for the transformation of unconventional reservoir large-scale volume fracturing of long operation cycle, equipment occupancy, through the well optimization, fracturing design optimization, supporting equipment, construction organization mode upgrade, in the changqing oilfield longdong shale oil HX platform realized a single set of fracturing vehicle for two well synchronous shunt fracturing, created a single unit 17 hours fracturing 10 shale oil reservoir transformation new record. Compared with the production mode of two sets of fracturing units on the same platform, the efficiency of synchronous shunt fracturing operation of single unit increased by 32.1% and the number of equipment used decreased by 17.3%, which initially reflected the advantages of synchronous shunt fracturing technology in improving quality and efficiency. Through the output tracking analysis of the horizontal Wells of synchronous shunt fracturing transformation for half a year, the four Wells showed good transformation effect. Synchronous shunt fracturing technology in changqing oilfield shale oil platform successful application for the future unconventional oil and gas resources cluster well fracturing transformation speed to provide new ideas, the technology can improve the efficiency of oil service enterprises, reduce the completion cycle and comprehensive operation cost, for oilfield company, can quickly build production effect.

Field pilots of carbon dioxide huff and puff method at a shale oil field

AbstractCO2 huff and puff is a widely used enhanced oil recovery method in many oil fields, but its implementations in shale fields is scarce. This paper reports trials of CO2 huff and puff in a shale field in China. Laboratory studies revealed that CO2 effectively reduced oil viscosity, increased oil volume, and improved oil recovery under miscible conditions. For the three wells that received CO2 huff and puff treatments, one well showed satisfactory results, while the other two wells demonstrated poor economics. Discussions and recommendations are made based on field experiences. © 2024 Society of Chemical Industry and John Wiley & Sons, Ltd.

Experimental investigation on flow patterns and pressure gradients of shale oil–water flow in a horizontal pipe

With the growing demand for hydrocarbon resources and the depletion of conventional oil and gas reservoirs, the development of shale oil will become popular. As the shale oil fields gradually enter the middle and late stages of exploitation, the water content reaches as high as 60–80 %. Analyzing the flow characteristics of shale oi–water flow during high water content can help optimize the range of flow parameters and improve pipeline transportation efficiency. However, research on shale oil–water flow patterns and pressure drop prediction models is still lacking. Therefore, this work conducted shale oil–water flow experiments in the multi-test section pipe flow loop, considering the temperatures (40–70 °C), mixture velocity (0.2–1.2 m/s), and water contents (60–80 %). The flow patterns of shale oil–water flow are studied, and the flow pattern maps are created. Moreover, the influence factors on pressure gradient are analyzed, including pipe diameter, water content, mixture velocity, and temperature. Eventually, the pressure drop prediction models are modified based on the pressure gradient and holdup experimental data. The results show that a thin oil film and an oil-sticking layer are adhered to the pipe wall at 40 °C and 50 °C, respectively. The mixture velocity increased from 0.4 m/s to 1.2 m/s, and the pressure gradient increased by 69.89 % when the temperature and water content are constant. The lubrication coefficient is introduced in stratified flow (ST) and three-phase stratified flow (TPS) models, and the pipe flow friction coefficient is modified in dispersed flow (DF) and intermittent flow (IF) models. Moreover, the average relative deviations between experimental data and calculated values of ST, TPS, DF, and IF modified models are 4.49 %, 4.23 %, 4.40 % and 5.17 %, respectively. Therefore, surface wettability reduces the friction between the oil phase and the pipe wall, and the oil film and oil-sticking layer increase the pipe flow resistance.

A Comprehensive Evaluation of Shale Oil Reservoir Quality

To enhance the accuracy of the comprehensive evaluation of reservoir quality in shale oil fractured horizontal wells, the Pearson correlation analysis method was employed to study the correlations between geological parameters and their relationship with production. Through principal component analysis, the original factors were linearly combined into principal components with clear and specific physical meanings, aiming to eliminate correlations among factors. Furthermore, Gaussian membership functions were applied to delineate fuzzy levels, and the entropy weight method was used to determine the weights of principal components, establishing a fuzzy comprehensive evaluation model for reservoir quality. Without using principal component analysis, the correlation coefficient between production and evaluation results for the 40 wells in the Cangdong shale oil field was only 0.7609. However, after applying principal component analysis, the correlation coefficient increased to 0.9132. Field application demonstrated that the average prediction accuracy for the cumulative oil production per kilometer of fractured length over 12 months for the 10 applied wells was 91.8%. The proposed comprehensive evaluation method for reservoir quality can guide the assessment of reservoir quality in shale oil horizontal wells.

Hydrocarbon Source Rock Evaluation of the Lucaogou Shale in the Periphery of Bogeda Mountain (SE Junggar Basin, China) and Its Implications for Shale Oil Exploration: Insights from Organic Geochemistry, Petrology, and Kinetics Pyrolysis

Since the discovery of the vast Jimusaer shale oilfield in the southeastern Junggar Basin in 2012, there has been considerable interest in neighboring areas around Bogeda Mountain that have shale oil potential. The primary productive interval in the basin, the Middle Permian Lucaogou Formation (P2l), is well-developed in the areas of Qitai, Mulei, Shiqiantan, Chaiwopu, and Miquan. In this study, we conducted an assessment of the hydrocarbon generation potential of the P2l in these five areas and compared it with that of the P2l in the Jimusaer oilfield, which were determined by GC-MS, total organic carbon (TOC) and vitrinite reflectance (Ro) measurements, Rock-Eval pyrolysis, and organic petrology to investigate the type, origin, thermal maturity, hydrocarbon potential, and oil/gas proneness of organic matter in the P2l. Additionally, we applied open-system pyrolysis of hydrocarbon generation kinetics to explore differences in hydrocarbon generation and expulsion across various P2l mudstone/shale in the southeastern Junggar Basin. The findings of this study revealed that the P2l shale in Qitai and Miquan areas contains more abundant and lower thermally mature organic matter (early mature–mature stage), characterized by primarily Type II1–I kerogen, similar to that found in the P2l shale of the Jimusaer oilfield. Conversely, the P2l shale in Mulei, Shiqiantan, and Chaiwopu contains less abundant and more thermally mature organic matter (mainly mature–highly mature stage), dominated by Type II2–III kerogen. Consequently, shale in these areas is considerably less desirable for oil exploration compared to the Jimusaer shale. The semi-deep to deep lake facies in Miquan and Qitai exhibit the most promising exploration potential. This study can serve as a guide for shale oil exploration in the southeastern Junggar Basin.

Technological issues in shale oil development using horizontal wells in Ordos Basin, China

The PetroChina Changqing Oilfield Company has successfully achieved large-scale economical development of continental low-pressure freshwater lake interlayer shale oil in the Ordos Basin, China, targeting the gravity-flow sandstone thin interlayers in the organically rich mud shale formation of the seventh member of Yanchang Formation (Chang 7 Member) of Triassic,. Their significant discovery of the 1-billion-ton-level Qingcheng shale oil field, with a proven reserve of 1.052 × 109 t, has marked the establishment of China's first million-ton shale oil development zone. However, the extensive growth in production and construction has brought attention to notable challenges, including geological variances, low initial production, rapid decline, low recovery rates, and high development costs. Based on extensive field experience, this paper identifies several technological issues in shale oil development and offers comprehensive recommendations through systematic analysis. The encounter rate of horizontal shale oil wells, crucial for enhancing individual well productivity, can be improved both vertically and horizontally by prioritizing the extension direction of high-quality reservoirs during the deployment of horizontal wells. The contribution of fracturing fluid elasticity to the recovery rate is relatively low. Reservoir modification should not overemphasize large sand volume, fluid volume, or discharge. Additionally, optimizing parameters such as well spacing, vertical interlayer distribution, and fracture development is essential for maximizing the efficiency of fracturing scale, operation discharge, and other parameters. Variability in hydrocarbon source rock quality and the strength of diagenesis significantly impact oil saturation in sand bodies, affecting the selection of favorable areas and the distribution of high-quality reservoirs. Furthermore, the utilization of pre-fracturing with CO2 proves to be an effective approach in reducing viscosity and increasing the ultimate recovery rate. To ensure the efficient development of shale oil in the Changqing Oilfield, this paper emphasizes the necessity of deepening integrated geological studies, clarifying the main controlling factors of shale oil heterogeneous accumulation, and meticulously depicting three-dimensional sweet spots while exploring more effective development methodologies.

Horizontal well path design with seismic inversion for a shale oil reservoir in the Ordos Basin, China

The Ordos Basin is located in the western part of the North-China Platform, where China’s largest shale oil field was discovered. Most of the production originates from relatively thin and tight sand bodies within the Chang 7 member of the Triassic Yanchang Formation. This consequently requires accurate and high-resolution inversion data to characterize the reservoirs and define the horizontal well paths. In this paper, we adopt full-waveform inversion (FWI) to obtain the velocity model for time-to-depth inversion. Compared with conventional migration velocity analysis, FWI can produce velocity models with more high-wavenumber variations that reflect thin and localized geologic features. Geologic statistical inversion is also applied to resolve the thin beds beyond seismic resolution. A comprehensive index is then computed with the inverted parameters to evaluate the reservoir and build a sweet-spot map. We define the coordinates, direction, and length of the horizontal well on the maps. The well path is subsequently carefully designed on the sections of the time-to-depth converted inversion data. The effectiveness of the workflow is verified using the application case of the Qingcheng oil field at the Ordos Basin.

Prediction of vitrinite reflectance of shale oil reservoirs using nuclear magnetic resonance and conventional log data

With the change of oil and gas exploration and development focus to shale reservoirs, the source rock has become a research hotspot in well logging. It is of great significance to obtain continuous organic geochemical parameters based on log data. In this paper, according to the density-bulk model of hydrocarbon source rocks, a new indicator parameter named UTM, which can characterize the thermal maturity, is constructed based on the variation of kerogen density with thermal maturity in the Jimusar Sag of Junggar Basin. This parameter can characterize the thermal maturity and be calculated by density log, nuclear magnetic resonance (NMR) log and total organic carbon content of core. This parameter has the advantage of avoiding the difficulty of calculating kerogen density. The model was validated using cores and log data that were not involved in the modeling. The vitrinite reflectance predicted by the UTM index was in good agreement with the actual cores demonstrating the reliability and applicability of the method. The method provides a new idea and practical solution for the quantitative characterization of thermal maturity in the shale oil fields.

A Microfluidic Experiment on CO2 Injection for Enhanced Oil Recovery in a Shale Oil Reservoir with High Temperature and Pressure

In recent years, CO2 huff and puff has become one of the most important methods developed for unconventional shale oil reservoirs and has been widely used in all major shale oil fields. However, the microscopic mechanism of CO2 contacting with crude oil is complex, and the change law of the residual oil occurrence after CO2 injection is unclear. In this paper, a micro visualization fluid flow simulation experiment (microfluidic experiment) under high temperatures and high pressure of a shale reservoir was conducted to reveal the micro mechanism of CO2 and crude oil after contact at the microscale. This allows conclusion of more precise results than any experiment conducted in a room environment. Combined with gas–oil two-phase micro flow characteristics, the production mechanisms of crude oil by CO2 huff and puff at the pore scale are clarified, and the change characteristics of the remaining oil occurrence state after CO2 injection are quantified. The results show that CO2 mainly produces crude oil in macropores and microfractures in the injection stage of huff and puff, improves the mobility of crude oil through diffusion dissolution in the soaking stage, and that the driving of dissolved gas is dominant in depressurization production. The major micro-mechanisms for CO2 to improve shale oil are extraction and dissolution expansion, accompanied by a variety of secondary mechanisms, such as the miscibility effect, oil expansion, viscosity reduction and other contact effects, as well as the improvement of crude oil properties. The simulation results of huff and puff development show that soaking is an important stage to enhance oil recovery. With increasing soaking time or the soaking pressure, the recovery degree of crude oil will increase positively.

Evolution of Near-Well Damage Caused by Fluid Injection through Perforations in Wellbores in Low-Permeability Reservoirs: A Case Study in a Shale Oil Reservoir

Abstract During the development of shale oil resources, fluid injection is usually involved in the process of hydraulic fracturing. Fluid injection through perforations causes near-well damage, which is closely related to the subsequent initiation and propagation of hydraulic fractures. This study is focused on the characterization of the temporal and spatial evolving patterns for near-well damage induced by fluid injection through perforations in the early stage of hydraulic fracturing. A coupled hydromechanical model is introduced in a case study in a shale oil reservoir in northwestern China. The model considers porous media flow during fluid injection. It also considers elasticity in the rock skeleton before the damage. Once the damage is initiated, a damage factor is employed to quantify the magnitude of injection-induced damage. Results show that damage evolution is highly sensitive to perforation number and injection rate in each individual perforation. Damage propagation is more favorable in the direction of the initial maximum horizontal principal stress. The propagation of damage is drastic at the beginning of fluid injection, while the damage front travels relatively slow afterward. This study provides insights into the near-well damage evolution before main fractures are initiated and can be used as a reference for the optimization of perforation parameters in the hydraulic fracturing design in this shale oil field.

TOC estimation of shale oil reservoir by combining nuclear magnetic resonance logging and nuclear physics logging

Abstract The evaluation of source rock properties has become a vital step in logging interpretation. Total organic carbon (TOC) content is the key to estimating the quality and hydrocarbon generation potential of source rocks. In the shale oilfield of the Junggar Basin, the conventional method of calculating the TOC of hydrocarbon source rocks cannot satisfy logging evaluation requirements. This paper predominantly deals with a method for the quantitative estimation of TOC in source rocks via nuclear physics and nuclear magnetic resonance (NMR) logs. According to this method, the total hydrogen index of the source rock is the sum of the response of kerogen, clay minerals and fluid, expressed by corrected neutron porosity. The hydrogen index of fluid and clay minerals is indicated by the effective porosity of NMR and the estimated clay content, respectively. To eliminate the hydrogen index of fluid, the effective NMR porosity is subtracted from the corrected neutron porosity. On this basis, a new and overlapping method suitable for clay-rich rocks and oil reservoirs is proposed. This method was developed by overlaying the scaled clay content curve on the hydrogen index curve. In non-source rocks, the two curves regularly overlap. However, in organic-rich rocks the two curves will separate. The separation distance between the two curves was used to estimate TOC continuously. Possessing sound application and benefiting from the measured results of sweet spots, this method provides new insights for TOC quantitative prediction in shale oil reservoirs.

An improved lithology identification approach based on representation enhancement by logging feature decomposition, selection and transformation

As the accumulation of logging data and the enhancement of computational power, machine learning technology has been progressively applied to logging interpretation field such as lithology identification. However, in traditional data-driven lithology identification model, the implied variation information of logging curve and coupling relationships among features are not fully mined. Additionally, feature extraction cannot filter out information redundancy and noise. We propose logging data representation enhancement approach for lithology identification based on feature decomposition, selection and transformation, converting the raw logging curves into an improved high dimensional representation with more effective information and less noise. Local mean decomposition is used to extract the variation information of logging curves from multiple depth scales and add them to the features of adjacent samples. Considering the different contribution of features to lithology identification, an optimized feature selection method based on Shapley additive explanation is designed to reduce redundant and noisy information in logging data. To mine the complementary information among sequence features, a representation learning model integrating feature transformation and lithology classification is developed by multi-grained scanning and cascading extreme learning machine. The effectiveness and generalization of the proposed approach are verified on the baseline and shale oil field datasets. The results show that the proposed approach can make the logging data acquire more valid information through representation enhancement, which helps to achieve high-accuracy lithology identification.

Analyzing major controlling factors of shale oil 'sweet spots' in the Chang-7 member of the Triassic Yanchang Formation, Ordos Basin

The Chang-7 Member of the Upper-Triassic Yanchang Formation has favorable geological conditions (e.g., extensive distribution of source rock, broad distribution of fine-grained sand bodies, stable structure, etc.) for developing a large shale oil pool. Initial assessments have estimated that the Chang-7 has shale oil resources of 3.0 × 109 t approximately. The discovered Xin'anbian giant shale oil field has an estimated reserve of one billion tons. The shale oil in the Chang-7 Member has been developed by volumetric fracturing in long horizontal wells since 2011. By the end of 2021, more than 500 horizontal wells had been drilled, with average initial production of 9.6 t/d per well. Some large-scale effective development pilot zones (e.g., X233, Z183, A83, etc.) have been constructed. The source rock and reservoir in the Chang-7 Member are heterogeneous. Under an extensive distribution background of shale oil layers, there are some local 'sweet spots'. In order to reveal controlling factors for the productivity of shale oil, research involving the comparison of development effects, formation of geologic conditions, and technologies of the three typical pilot zones, has been conducted. The results showed that organic abundance in the source rock is the primary controlling factor for “sweet spot” distribution of the shale oil. The average TOC value in the black shale source rock in the Chang-7 Member is about 10% higher than that in the dark gray mudstone. The average hydrocarbon generation intensity is about 2.0 × 103 t/km2, the average hydrocarbon expulsion rate is 34.6%, and the production rate of gaseous hydrocarbons is 14.65–39.46 m3/t. In the vicinity of black shale with a high TOC value, the oil filling intensity in the shale oil reservoirs is high, with oil saturation of up to about 70%, and a gas-to-oil ratio >90 m3/t. Secondly, the 'sweet spots' with such petrophysical properties control the enrichment of reservoirs. Owing to conditions of low-porosityand low-permeability, the shale oil reservoirs in the Chang-7 Member of the Ordos Basin still developed 'sweet spots',with porosity larger than 9% and permeability larger than 0.08 × 10−3 μm2 . These reservoir sweet spots have a pyrolysis yield of hydrocarbons >9 mg/g and the development wells have high initial and total production, a slow decline rate, and low water cut. Moreover, the dissolved gas in shale oil in the Chang-7 Member of the Ordos Basin is an oil-type gas that was generated during the primary pyrolysis stage of sapropel kerogen after entering a mature period. The gas-to-oil ratio in crude oil is controlled by several factors, such as organic abundance and maturity in source rock, thickness, petrophysical properties, and fractures in reservoirs. The overlap of black shale with high TOC, source rock thickness >10 m, thermal maturity Ro > 0.8%, and type I and II high-quality reservoir beds are the pre-requisites for the development of sweet spots with high and stable production of shale oil. The produced gas-to-oil ratio in the development wells is stable (generally 19.68 m3/t). Some wells have produced oil continuously and stably at over 14 t/d for 5 years. This paper delineates the distribution patterns of shale oil sweet spots in the Chang-7 Member of the Ordos Basin and confirms that profitable and efficient development of shale oil can be achieved in this basin.

Sequential data-driven cross-domain lithology identification under logging data distribution discrepancy

Since traditional data-driven methods are not effective in cross-domain lithology prediction, researches recently focus on improving the model through learning the feature distribution across the datasets of different wells. However, the sequential relation in logging curves has not been fully extracted in logging data processing, and the distribution discrepancy of lithology class proportion is neglected by the classification model. In this paper, a sequential logging data-driven cross-domain lithology identification model is proposed, which mines spatial neighborhood information while learning data distribution discrepancy of both features and classes. To extract variation trend with depth of logging curves, a temporal convolutional network is designed for lithology prediction. An improved class-balanced self-training algorithm is developed based on semi-supervised learning, where the data distribution in target well is shared with source well. Besides, a model ensemble method is adopted in lithology identification by conducting results averaging to promote stability. Verification experiments on logging datasets of a shale oil field show that the proposed method can learn the sequential characteristics as well as data distribution and realize accurate cross-domain lithology identification.

Improving oil recovery of Eagle Ford shale samples using cryogenic and cyclic gas injection methods - An experimental study

Despite containing massive volumes of hydrocarbons, unconventional reservoirs have low recovery factors, <10% in oil reservoirs. Production from such ultra-low-permeable formations mainly depends on the flow conductivity. Any method enhances flow conductivity improves hydrocarbon-production from these reservoirs. In this study, implementing cryogenic and cyclic gas injection to improve oil recovery was investigated. Liquid nitrogen (LN2) was injected into saturated core samples from Eagle Ford formation at 82 °C reservoir temperature. Then, three cycles of nitrogen (N2) injection at four pressures (6.89, 13.79, 20.68, 27.58 MPa) were conducted, and oil recovery factor (RF) was calculated for up to 24 h of production period after each cycle. LN2 and cyclic N2 injection effects on core samples were assessed using computerized-tomography scan, porosity, permeability, and ultrasonic-velocity measurements. The results revealed that implementing LN2 and cyclic N2 techniques improves shale oil RF by up to 78%. Implementing LN2 and cycling N2 resulted in initiating new cracks and extending them inside the samples providing high-flow channels for the injected gas, promoting the oil and gas exchange through injection and production stages and utilizing pressure near minimum miscibility pressure yielding higher oil RF. Samples’ porosity, permeability, and velocities were altered after completing the treatments. Porosity increased by up to 60% and permeability significantly enhanced up to 2.4 orders of magnitude. Whilst P- and S-wave velocities reduced by up to 10% and 8%, respectively. Implementing LN2 and cyclic N2 could potentially be employed in shale oil fields to improve the oil recovery.

Total Scanning Fluorescence Characteristics and Implications of Shale Oil in the Lucaogou Formation, Jimsar Sag, Junggar Basin, NW China

The Lucaogou Formation in the Jimsar Sag is a typical lacustrine shale oil development area where the first large-scale shale oil field in China was discovered, and a large number of studies have been conducted on the genesis and distribution of the shale oil in this formation. However, few detailed studies have been conducted on the comparison between the characteristics of the hydrocarbons in the shale and the adjacent tight reservoirs in the same shale sequence package. In this study, the total scanning fluorescence (TSF) quantitative fluorescence technique, which has been rarely applied to and studied in the Lucaogou Formation in the Jimsar Sag, was used to conduct systematic quantitative fluorescence analysis of the shale, tight reservoirs, and crude oils in the Lucaogou Formation. The geochemical analysis was also carried out for all samples. The results revealed that the shale, tight reservoirs, and oils have similar single-peak TSF spectrograms, and different values of the TSF parameters in the Lucaogou Formation. The TSF parameters R1and R2values of the blocky shale, fractured shale, tight reservoirs, and produced oils are decreased successively. The TSF parameters can be used as indicators of hydrocarbon composition, physical properties, thermal maturity, migration, and oil-producing layers. The values of TSF parameters R1and R2are generally smaller in the upper section of the Lucaogou Formation (P2l2) than in the lower section (P2l1), indicating that the hydrocarbons in the upper section have better physical properties and higher thermal maturity. The distribution of TSF parameters R1and R2in the upper section of the Lucaogou Formation is relatively scattered, indicating that the hydrocarbons have undergone obvious lateral migration. Based on the TSF parameter comparison of core and oil samples, it was preliminarily determined that the shale oil in the upper and lower sections of the Lucaogou Formation was mainly produced from the tight reservoirs in the shale sequence. The results of this study provide new data and ideas for fine studies of the shale oil in the Lucaogou Formation in the Jimsar Sag.

Reservoir formation conditions and key technologies for exploration and development in Qingcheng large oilfield

The Qingcheng oilfield, the largest shale oil field in China, was discovered in 2019 in source rock of Chang 7 Member of Mesozoic Yanchang Formation, Changqing Oilfield in Ordos Basin, with newly increased proven geological reserves of 358 million tons, predicted geological reserves of 693 million tons, and a total of 1.051 billion tons of shale oil resources. This achieves a historic breakthrough in exploration of shale oil in Chang 7 Member. In recent years, focusing on key issues, such as whether there develop sweet spots in source rock, whether commercial oil production capacity can be formed, and whether scale-effective development can be achieved, studies about geological conditions for shale oil accumulation have been continuously carried out, key supporting technologies have been developed, and a series of theoretical innovations and technological breakthroughs have been achieved in oil exploration in source rocks. The results indicate that shale oil accumulation in Chang 7 Member is controlled by following factors. Firstly, lacustrine black shale, dark mudstone and other high-quality source rocks lay a material foundation for shale oil formation. Secondly, sandy deposits intercalated within black shale and dark mudstones are exploration sweet spots, and sandbody combination types are controlled by morphology of bottom of the lacustrine basin. Thirdly, reservoir properties are good due to development of micro-nano pore throats. Finally, reservoirs with high oil saturation and high gas-oil ratio are formed due to high-intensity oil charging in source rock. Effective matching of multiple factors is a key for shale oil accumulation in Chang 7 Member in Ordos Basin. Through innovation of key supporting technologies, exploration and development technologies for shale oil are developed, and substantial breakthrough on exploration and development of shale oil is realized. The first application of logging-seismic combination technology in loess plateau improves significantly quality of 3D seismic data, which effectively guides prediction of sandy sweet spots. Three-quality well logging technology is used for further evaluation of geological and engineering sweet spots of shale oil. With volumetric fracturing technology based on precise segmentation of long horizontal wells, initial daily oil production of individual well is increased from previously 10 tons to more than 18 tons. The exploration breakthrough in source rocks in Chang 7 Member in Qingcheng oilfield provides an important resource base for the second accelerated development of Changqing Oilfield. It is predicated that oil production from shale in Chang 7 Member in Qingcheng oilfield will reach three million tons in 2022 and five million tons in 2025.

Optimization of enhanced oil recovery operations in unconventional reservoirs

The U.S. Department of Energy is promoting the development of technologies that tackle gas flaring activity in oil production. Among these technologies, injection of flare gas into the reservoir to stimulate production of oil and capture the injected gas has received attention. Accordingly, this study contributes to understanding the economic and environmental implications of implementing enhanced oil recovery (EOR) in shale oil development to reduce gas flaring. A systematic optimization-based methodology is proposed to fully integrate the development of a shale oil field along with EOR projects. The framework optimizes decisions such as drilling schemes, workover of depleted production wells, pipeline and processing infrastructure, location of injection sites, injection rates, and duration of EOR operations. The pertinence of implementing EOR in the Bakken area is addressed through a typical production unit with 18 wellpads, which is further extended to 4 production units (72 wellpads). Results reveal consistent values across different development scales for operational variables such as percentage of wellpads undergoing EOR, incremental produced oil, percentage of total gas production used for injection, and average gas flaring. Conversion of depleted wellpads is preferred over installation of new injection wells. A global sensitivity analysis revealed the dominant role of EOR efficiency over Capex, Opex, and gas-oil ratio. EOR greatly favors the economics and the reduction of gas flaring but it is insufficient to comply with local flaring targets. Nonetheless, the implementation of EOR in combination with taxation tariffs is an adequate mechanism to reduce gas flaring and comply with regulatory targets.

Groundwater risk assessment investigations for oil shale exploitation in El-Lajjun area of central Jordan

Oil shales are sedimentary rocks that contain organic material in its inorganic matrix. The oil shale deposits of Jordan have been investigated since the 1960s. An extensive investigation studies have been commenced to evaluate the quality and quantity of these resources. In 2006, the government of Jordan invited pioneer companies in oil shale field to submit their proposal to utilize and develop the oil shale of Jordan using different extraction technologies. Jordan is considered one of the driest countries in the world, which poses an additional challenge for oil shale development, because a vast quantity of water is needed for this process. El-Lajjun study area is located in central Jordan; the oil shale in the study area was deposited in marine environment; it comprises massive beds of brown-black, kerogen-rich, bituminous chalky marl. Ten representative oil shale rock samples were collected for risk assessment investigations from different localities of oil shale exposures. A standardized laboratory Fischer assay test delivered oil shale characteristics. Sequential extraction was used to evaluate mobility and distribution of the trace elements Ti, V, Cr, Co, Zn, As, Zr, Cd, Pb, and U. Column leaching experiments were performed to simulate the leaching behavior of the above elements from oil shale and spent shale to evaluate the possible negative impact on groundwater in the study area. Results of sequential extraction indicate that concentration of trace elements and trace elements are richer in oil shale and in the spent shale compared to most rocks and soils. The concentrations in the leachate were below the maximum contaminant levels of the Environmental Protection Agency (EPA) and the Jordanian standards for drinking water. The significance of this study lies in that its utilizes for the first time the sequential extraction and column leaching techniques to investigate the Jordanian oil shale rocks.

Improving oil recovery from shale oil reservoirs using cyclic cold carbon dioxide injection – An experimental study

In this study, effects of injecting gas temperature and pressure on oil recovery factor (RF) of shale oil reservoirs were investigated by implementing cyclic cold carbon dioxide (CO2) injection on Eagle Ford Shale Oil core samples. Also, effects of injecting gas temperature on porosity, permeability, and brittleness indices of these core samples were assessed.An experimental setup was designed and built to implement CO2 cyclic gas injection and thermal shock tests. Four Eagle Ford Shale outcrop core samples were used in this study. The saturated samples were heated to 180°F and carbon dioxide at various combinations of pressure (1000 psi, 2000 psi, 3000 psi, and 4000 psi) and temperature (−15°F, 0°F, 32°F, and 74°F) was injected into them. Oil RF for each experiment was measured after five days of production period. Additionally, porosity, permeability and ultrasonic velocity of each core sample were measured both prior to and after conducting the experiment.The results indicate that injecting CO2 at low temperature results in higher oil recovery factor (up to 7%) than injecting carbon dioxide at ambient temperature. It was also observed that injecting cold CO2 enhanced both porosities and permeabilities of the core samples. The porosities and the permeabilities of the core samples enhanced by up to 3.5% and 8.8%, respectively. Also, a noticeable reduction (between 100 ft/s and 400 ft/s) in P-wave velocity was observed after injecting the cold gas into the core samples, which is an indication of creating induced fractures. The results also revealed that injecting the cold gas increased the brittleness indices of the core samples by up to 8. Hence, cyclic cold carbon dioxide injection could be potentially implemented in the shale oil fields to improve the efficiency of the current industry practice of cyclic gas injection technique.