High Oil Saturation Research Articles

Oil–reservoir correlation: Unravelling the producing reservoir for the sulfur-rich Qianjiang shale oil play

The hypersaline Qianjiang shale oil play represents a promising yet challenging target for exploration due to its multiple stacked shale-carbonate layers, which complicate the identification of the most viable extraction sites. Additionally, the oil accumulated in these layers is immature to low-mature and considerably high in sulphur content. To trace the shale zones after fracturing, a newly developed oil-reservoir correlation method employing Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) was utilised. This method proved effective in distinguishing between the acidic nitrogen-, sulphur-, and oxygen-containing (NSO) compounds identified by the negative mode of electrospray ionisation FT-ICR MS and the less polar NSO compounds and aromatic hydrocarbons detected by positive ion atmospheric pressure photoionisation FT-ICR MS. These compounds facilitated the deconvolution of oils produced from mixed layers in the hypersaline Qianjiang shale play. The zones of oil production identified through this method corresponded well with shale reservoirs previously characterised by anomalously high oil saturation index values (OSI >400 mg/g TOC) and a preferential enrichment of saturated hydrocarbons. A detailed analysis of C31-35 homohopane distributions in shale extracts and crude oil corroborated these findings. The variability in the producibility of NSO compounds and aromatic hydrocarbons was examined based on functional group, degree of aromatisation, and molecular weight. During production, sulphur- and nitrogen-containing compounds predominantly migrated into the produced oil, whereas oxygen-containing compounds were less affected. Nonetheless, determining the production partitioning of aromatic hydrocarbons remains challenging; if present, it may be obscured by the commingled production effects from multiple layers.

Integrated geological quality evaluation using advanced wireline logs and core data: a case study on high clay shale oil reservoir in China

Abstract In the unconventional energy sector, shale oil is increasingly recognized as a crucial supplement to production. In recent years, China has made significant advancements in the development of shale oil. A unique type of pure shale reservoir in the Songliao basin, distinct from established shale oil reservoirs worldwide, has emerged as a focal point for exploration and research endeavors. This kind of shale exhibits enhanced heterogeneity, high clay content, intricate rock electricity relationship, posing significant challenges to formation evaluation. This study introduces conversion coefficients for the elements and minerals, a decision tree model, a variable T2 cutoff value method, and 2D NMR cluster analysis, all based on the integration of microimaging, spectroscopy, and 2D NMR logging. These novel approaches facilitate a comprehensive geological quality evaluation of key parameters, including mineral composition, lithology, effective porosity, total organic carbon content, fluid composition, and saturation characteristics within pure shale formations from the Songliao Basin. The established petrophysical model has been validated by core analysis data and successfully applied in exploration wells. Through systematic petrophysical analysis, the optimal landing point for horizontal wells was identified based on the identification of the best reservoir quality interval with high movable oil and oil saturation. The subsequent drilling of horizontal wells demonstrated the reliability of petrophysical evaluation in terms of oil production. This integrated evaluation method for pure shale holds reference significance for similar shale reservoirs in other blocks in the future.

Low Resistivity Pay Zone Detection in Hydrocarbon Formation: The Feasibility of the Spectral Induced Polarization Method

Summary Identifying and characterizing low resistivity pay (LRP) zones within hydrocarbon-rich formations has long been challenging in the petroleum industry due to their complex mineral composition, microporosity, and diminished resistivity contrasts. Traditional methods, such as resistivity measurements, struggle to effectively pinpoint LRP zones, prompting the need for innovative approaches in reservoir evaluation. This paper explores the feasibility of using the spectral induced polarization (SIP) method for detecting LRP zones. The SIP method measures complex conductivity across a frequency range from 1 mHz to 10 kHz. While this technique has been widely used in mining and environmental studies, its potential for petrophysics applications in the oil and gas sector remains largely unexplored. This study acts as a proof of concept, demonstrating the capability of SIP for detecting LRP zones. Laboratory experiments utilized dual-porosity silica gel samples with controlled micro- and macroporosity fractions and added pyrite content. Despite a high crude oil saturation of approximately 60%, the presence of brine in continuous micropores resulted in low resistivity readings (0.7 Ω·m) at low frequencies, as conventionally measured by direct current resistivity tools. However, at higher frequencies (>100 Hz), the study observed high average resistivity values (82 Ω·m), indicating a frequency-dependent behavior in electrical measurements. This behavior is attributed to polarization mechanisms, including the electrical double layer (EDL). This study’s findings propose the SIP method’s potential effectiveness for detecting LRP zones, paving the way for future research to delve deeper into the application of SIP in petrophysics.

Experimental and Numerical Simulation Study on CO2-Assisted Steamflooding in Ultraheavy Oil Reservoirs

Summary Certain ultraheavy oil reservoirs with depths approaching 1000 m feature wide well spacing. After cyclic steam stimulation (CSS), cold oil zones with high residual oil saturation exist between wells. This leads to a high oil saturation at the steam front during the subsequent steamflooding process, which in turn results in a high injection pressure. The simultaneous injection of CO2 and steam into the formation can optimize formation pressure and enhance steam utilization efficiency. A majority of laboratory-based experimental studies have reported favorable outcomes with CO2-assisted steamflooding. However, some field tests of CO2-assisted steamflooding have encountered severe steam channeling problems, resulting in oil recovery and an oil/steam ratio below the expected level. Consequently, this study uses an ultraheavy oil reservoir as a case study and integrates physical simulation with numerical simulation to investigate the impact of CO2-assisted steamflooding on enhanced oil recovery in ultraheavy oil reservoirs. The findings suggest that the beneficial effect of CO2 in reducing oil viscosity and injection pressure plays a significant role in models with smaller thickness, thereby improving oil production rate and recovery factor. However, as the thickness of the model increases, the adverse effect of CO2 exacerbating steam channeling becomes increasingly evident, leading to a decline in the oil recovery factor and a longer duration to reach the maximum recovery factor. Therefore, in field applications, it is essential to consider adjusting the CO2 injection method or using thermosetting plugging agents to achieve superior results.

Visualization of dynamic micro-migration of shale oil and investigation of shale oil movability by NMRI combined oil charging/water flooding experiments: A novel approach

Investigating the micro-migration processes of hydrocarbons within interbedded shale reservoirs, and quantitatively characterizing the movability of shale oil, are highly important for the exploration and development of continental shale oil. However, due to complex pore-fracture structures, the characterization of the micro-migration and movability of shale oil presents significant difficulties, and the lack of suitable technology restricts the understanding of shale oil accumulation mechanisms and the evaluation of movability. This study employs nuclear magnetic resonance imaging (NMRI) technology in conjunction with oil charging and water flooding experiments, to innovatively visualize and quantitatively characterize the dynamic micro-migration features and movability of hydrocarbons within the pore-fracture structures of shale. The results indicate a significant increase in oil saturation within the interbedded shale oil reservoir during the oil charging process, with the oil phase primarily accumulating in larger pores (T2 = 1–100 ms). The micro-migration and accumulation process of interbedded shale oil can be divided into three stages: the initial stage dominated by water phases in the pore spaces due to insufficient oil filling pressure, the intermediate stage marked by a rapid increase in hydrocarbons in the pore spaces, and the final stage where oil fills the entire pore system resulting in high oil saturation. The movability of different types of shale oil during water flooding varies significantly and is mainly influenced by pore-fracture structures. Interbedded shale oil reservoirs with larger pores exhibits a higher movable oil saturation (approximately 36.94%), while matrix-type shale oil reservoirs shows greater heterogeneity and lower fluid movability (approximately 14%). However, the shale oil movability of matrix-type shale oil reservoir with developed microfractures can reach 40%. More specifically, the fluid movability in smaller pore-microfracture structures (T2 < 0.5 ms) is as high as 56.88%, surpassing that in larger pores (T2 > 0.5 ms) (32.78%). Larger pores and microfractures substantially enhance the movability of hydrocarbons in the shale matrix, thus improving shale oil recoverability. In contrast, due to the higher capillary pressure (Pc) and flow resistance (Pv), smaller pores contribute less to the movability of shale oil. Overall, the outcomes of this study not only advance our understanding of the micro-migration and accumulation patterns of interbedded shale oil but also offer new insights for geological and engineering integration research on shale oil.

Integrating Well Logs and Core Data for Better Reservoir Characterization of Mamuniyat Formation, Murzuq Basin, Libya

Increasing the number of dry holes in the last two decades to more than twenty wells in Murzuq Basin necessitates a comprehensive reservoir evaluation study to resolve this issue. The current work combines well logging and core data analysis to precisely estimate petrophysical parameters and evaluate the Mamuniyat reservoir. The available data includes well logs from eleven wells and core data from one of the studied wells (I-14 Well). Utilizing well logs and core data, the Mamuniyat Formation is found to be made up of sandstone with a low shale content between 5 and 10%. It has effective porosity values that vary between moderate (13%) and good (16%), with oil saturation ranging from 62 to 91%. Using core data analysis, it was found that the grain density is 2.65 g/cc. A good match between the core-derived and log-derived porosity values is observed. It could be concluded that the Mamuniyat Formation is a sandstone reservoir with low shale volume, moderate effective porosity, and high oil saturation. The reason for the large number of dry holes in Murzuq Basin could be attributed to other factors other than reservoir quality.

CALCULATION OF AN ALTERNATIVE DEVELOPMENT SYSTEM FOR THE MAIN DEPOSIT OF THE DANILOVSKOYE OIL AND GAS CONDENSATE FIELD

The article provides a calculation of an alternative development system for deposit 3 (Main deposit ) of the Danilovskoye oil and gas condensate field. At the time of the analysis, this deposit is in the pilot development stage, with six development variants proposed in the trial operation project, which assume a principled arrangement of wells along an areal homogeneous grid. At the same time, due to the need to maintain the energy of the formation (that is, certain values of thermodynamic conditions), three provide for a transition to pressure maintenance, with the resulting four-point scheme of effect on the deposit (intensity 1:2; one well for injection, two for production). In the alternative model under consideration, the development method also involves a subsequent transition to pressure maintenance, but with a more active, five-point waterflooding system (intensity 1:1, equal ratio of production and injection wells), if necessary, as will be shown in the work, easily convertible to a nine-point one. The latter is an objective advantage, since the formation has low permeability and high vertical and lateral heterogeneity, and during waterflooding, zones not affected by the impact may appear, and, consequently, zones with high residual oil saturation. When calculating the characteristics of the proposed alternative method, modeling using the Peaceman method is used. Peaceman’s method is based on determining the well-reservoir connectivity of each individually opened cell, used to calculate flow rates (taking into account different values of average water cut for wells). The method is classical and, although it includes a large number of limiting assumptions, it is applicable everywhere and can provide sufficient justification for the effectiveness of the chosen development variant. General recommendations for the development of the entire field are also given (taking into account the low viscosity and lightness of oil and the properties of reservoir rocks). Such as the use of acid fracturing technology, the use of surfactants, hydrochloric acid treatments (HAT) and a complexing phosphorus-containing reagent — AFC.

Effects of Pore Geometry and Saturation on the Behavior of Multiscale Waves in Tight Sandstone Layers

AbstractGeometric heterogeneities in tight reservoir rocks saturated with a fluid mixture may exhibit different scale distribution characteristics. Conventional models of rock physics based on poroelasticity, which usually consider single‐scale pore structure and fluid patches, are inadequate for describing elastic wave responses. A major challenge is to establish the relationship between the wave response at different spatial scales and frequencies. To address this problem, three sets of observational data over a wide frequency range were obtained from a tight oil reservoir in the Ordos Basin, China. Ultrasonic measurements were made on eight sandstone samples at partial oil‐water saturation at 0.55 MHz. Data from six borehole measurements and seismic profiles were acquired and analyzed at about 10 kHz and 30 Hz, respectively. Analysis of the cast thin sections shows that dissolution pores and microcracks generally develop, with fractal dimensions of the pores ranging from 2.45 to 2.67 for the samples with porosities between 5.1% and 10.2%. Compressional wave velocity and attenuation were estimated from the observed data. The results show that the velocity dispersion from seismic to ultrasonic frequencies is 10.02%, mostly occurring between sonic and ultrasonic frequencies. The attenuation is stronger at higher oil saturation. The relationships between velocity, attenuation, and wavelength were established and can be used for further forward modeling and seismic interpretation studies. A partial saturation model has been derived based on effective differential medium theory and a double double‐porosity model, assuming that the medium contains fractal cracks and fluid patches. The effects of scale and saturation on wave responses are prevalent. Modeling results consistent with observed data show that the radii of cracks and fluid patches range from 0.1 μm to 2.8 mm, affecting ultrasonic, acoustic, and seismic attenuation. The multiscale data and proposed model quantify the relationship between fracture and fluid distributions and attenuation and could be useful for upscaling to the reservoir scale. The study helps improve the understanding of seismic wave propagation in partially saturated rocks, which has potential applications in seismic exploration, hydrocarbon production in reservoirs, and CO2 sequestration in aquifers.

Numerical analysis of water-alternating-CO2 flooding for CO2-EOR and storage projects in residual oil zones

Residual oil zones (ROZs) have high residual oil saturation, which can be produced using CO2 miscible flooding. At the same time, these zones are good candidates for CO2 sequestration. To evaluate the coupled CO2-EOR and storage performance in ROZs for Water-Alternating-CO2 (WAG) flooding, a multi-compositional CO2 miscible model with molecular diffusion was developed. The effects of formation parameters (porosity, permeability, temperature), operation parameters (bottom hole pressure, WAG ratio, pore volume of injected water), and diffusion coefficient on the coupled CO2-EOR and storage were investigated. Five points from the CO2 sequestration curve and the oil recovery factor curve were selected to help better analyze coupled CO2-EOR and storage. The results demonstrate that enhanced performance is observed when formation permeability is higher and a larger volume of water is injected. On the other hand, the performance diminishes with increasing porosity, molecular diffusion of gas, and the WAG ratio. When the temperature is around 100 °C, coupled CO2-EOR and storage performance is the worst. To achieve optimal miscible flooding, it is recommended to maintain the bottom hole pressure (BHP) of the injection well above 1.2 minimum miscibility pressure (MMP), while ensuring that the BHP of the production well remains sufficiently high. Furthermore, the tapered WAG flooding strategy proves to be profitable for enhanced oil recovery, as compared to a WAG ratio of 0.5:1, although it may not be as effective for CO2 sequestration.

Organic petrography and geochemistry of the Fu 2 member of the Paleocene Funing formation, Gaoyou Depression, Subei Basin, Eastern China: Implications for shale oil potential

The Fu 2 Member of the Paleocene Funing Formation in the Gaoyou Depression, Subei Basin is an organic matter-rich formation, and has a high potential for shale oil exploration and exploitation. Total organic carbon (TOC), organic petrography, Rock-Eval pyrolysis, chloroform bitumen “A” extraction, and SARA (saturates/aromatics/resins/asphaltenes) composition analyses of shale samples from one drill core in the studied area spanning a thickness of 257 m were conducted to study the organic matter (OM) richness, kerogen type, maceral composition, hydrocarbon generation potential, and oil content of the Fu 2 Member. Results show that the Fu 2 Member shales in the study area have a Ro of 0.87%, in the peak oil window, suggesting a high potential for hydrocarbon generation. The studied OM in shales mainly belongs to kerogen Type II, with a minor portion of Type I and Type III. Under microscopic observation, macerals in the studied shales are mainly composed of vitrinite, inertinite, alginite, and solid bitumen. The studied shales have an average TOC content of 1.41 wt%, indicating good petroleum potential. The variations of maceral compositions could affect the reliability when the Tmax is used as an indicator of thermal maturity. The lower Shale 4 and upper Shale 5 interval (3650–3700 m), with high TOC and high oil saturation index, is identified as the sweet-spot interval of the Fu 2 Member for shale oil exploration.

Petrophysical Properties and Identification of Electrofacies from Well Log Data of Nahr Umr Formation in Subba Oilfield, Southern Iraq

The main purpose of this study is to identify electrofacies and evaluate the petrophysical properties of the Nahr Umr Formation in four wells: A, B, C, and D in the Subba oilfield, southern Iraq. The petrophysical properties, such as shale volume, porosity, water saturation, hydrocarbon saturation, and bulk water volume, were computed and interpreted using Techlog software. According to the interpretation of density, neutron, and gamma ray sonic logs and deep resistivity logs using the IPSOM technique, four electrofacies were identified as sandstone, shaly sand, sandy shale, and shale electrofacies. The formation was divided into three parts based on well log interpretation and petrophysical analysis: the upper part, middle part, and lower part Interpretation of formation lithology and petrophysical parameters shows that the lower part consists mainly sandy shale with layers of sandstone and shale high porosity and high oil saturation whereas middle part consists mainly of sandstone, alternating with thin bedded of sandy shale and shale with high porosity and medium oil saturation. The upper part consists mainly of a sandy shale alternating with shale and shaly sand with high porosity, hydrocarbon saturation, and lower water saturation.

Screening of Chemicals to Enhance Oil Recovery in a Mature Sandstone Oilfield in Kazakhstan: Overcoming Challenges of High Residual Oil

Chemical flooding, such as alkaline-surfactant (AS) or nanoparticles-surfactant (NS) flooding, is an enhanced oil recovery (EOR) technique that has been increasingly utilized to enhance the oil production rate and recovery factor while reducing chemical adsorption. The AS/NS flooding process involves the injection of a mixture of surfactant and alkali/nanoparticles solutions into an oil reservoir to reduce the interfacial tension between the oil and water phases by surfactant and lower surfactant adsorption by alkali or nanoparticles (NPs) to improve the residual oil recovery. In this study, the AS/NS flooding is evaluated for a Kazakhstani oilfield by systematically screening the chemical constituents involved. Field A in Kazakhstan, one of the oldest fields in the country, has been waterflooded for decades and has not produced even 50% of the original oil in place (OOIP). Currently, the water cut of the field is more than 90%, with a high residual oil saturation. Therefore, besides polymer flooding to control mobility, chemical EOR is proposed as a tertiary recovery method to mobilize residual oil. This study aimed to screen chemicals, including surfactant, alkali, and NPs, to design an effective AS/NS flooding program for the target field. The study focused on conducting laboratory experiments to identify the most effective surfactant and further optimize its performance by screening suitable alkaline and NPs based on their compatibility, stability, and adsorption behavior under reservoir conditions. The performance of the screened chemicals in the porous media was analyzed by a set of coreflood experiments. The findings of the study indicated that alkali agents, particularly sodium carbonate, positively affected surfactant performance by reducing its adsorption by 9–21%. The most effective surfactant combination was found, which gave Winsor type III microemulsion and the lowest interfacial tension (IFT) of 0.2 mN/m. The coreflood tests were conducted with the screened surfactant, alkali, and NPs. Both AS and NS tests demonstrated high residual oil recovery and microemulsion production. However, NS flooding performed better as the incremental oil recovery by NS flooding was 5% higher than standalone surfactant flooding and 9% higher than AS flooding. The results of this screening study helped in designing an efficient chemical formulation to improve the remaining oil recovery from Field A. The findings of this study can be used to design EOR projects for oil fields similar to Field A.

Characteristics and Key Controlling Factors of the Interbedded-Type Shale-Oil Sweet Spots of Qingshankou Formation in Changling Depression

Different types of shale-oil sweet spots have developed and are vertically stacked in multiple layers of the Qingshankou Formation in the Changling Depression, southern Songliao Basin. Furthermore, this area lacks a classification standard in the optimization of its shale-oil sweet-spot area/layers. Through relevant tests of the region in question’s organic geochemistry, physical properties, oiliness, and pore structure, this paper investigates the formation elements of shale-oil sweet spots. In addition, summaries of its enrichment-controlling factors are given, and the classification standard and evaluation method for understanding the comprehensive sweet spots of the interbedded-type shale oil are then established. The interbedded-type shale oil is enriched in the Qingshankou I Member in the Changling Depression, and it has the features of medium-to-high maturity, the development of inorganic pores and micro-cracks, as well as higher oil saturation and better oil mobility. The sweet-spot enrichment is affected by lamina type, sedimentary facies, maturity, and sand–shale combinations. Both silty-laminated felsic shale and argillaceous-laminated felsic shale, which are developed in semi-deep lakes, are favorable shale lithofacies as they have excellent brittleness and oil mobility. The high maturity and the interbedded combination of sand and shale ensure the efficient production of shale oil, among which the pure-shale section issues a continuous contribution to the production process. Combined with oil testing, sweet-spot classification standards and a comprehensive evaluation of interbedded-type shale oil were established. An area of 639.2 km2 for the interbedded-type shale-oil sweet spots was preferred, among which type I (193 km2) belonged to the combination of “good shale and good siltstone interlayers adjacent”, and type II belonged to “good shale and medium siltstone interlayers adjacent” combination (which have long-term low and stable production prospects). The research provides theoretical guidance on the effective exploration and development of the shale oil of the Qingshankou Formation in the Changling Depression.

Crude oil differential enrichment in sandy-debris-flow and turbidite-current sandstones by physical simulation experiment

The article selected the samples of Chang 6 sandy-debris-flow and turbidite-current sandstones in the Ordos Basin and studied the seepage law and differential accumulation of crude oil by physical simulation experiment. The results show that the sandy-debris-flow and turbidite-current sandstones are featured with nonlinear and quasilinear crude oil flow with the threshold pressure gradient and critical pressure gradient. The oil saturation increases by leaps in the turbidite-current sandstones with relatively low maximum oil saturation. The sandy-debris-flow sandstones show steady growth with high maximum oil saturation. Differential accumulation of crude oil is controlled by porosity, permeability, crude oil viscosity, and hydrocarbon-generating pressure. The crude oil accumulation requires the pressure gradient to break through the critical pressure gradient, which can be formed if oil saturation exceeds 25%. Large-scale oil accumulation is easily formed in near-source sandy-debris-flow sandstones. Far-source deep-water sandstones easily develop inauthentic oil accumulation.

Interpretation of Petrophysical Properties in Reservoir Rock Using Capillary Pressure Data of the Mishrif Formation in West Qurna Oilfield, Southern Iraq

In this study, capillary pressure tests for twenty-nine samples acquired from four wells, (Rn-83, WQ-155, WQ286, and WQ-355) were used to estimate pore size distribution, pore-throat sorting, displacement pressure, reservoir grade, oil column, effective porosity, and relative permeability of the Mishrif Formation at West Qurna Oilfield, southern Iraq. Interpretation of capillary pressure data revealed that the formation can be divided into four reservoir facies with different reservoir production performances: very good, good, medium, and poor. The facies with very good performance is characterized by large pore sizes, excellent reservoir grade, low displacement pressure, and high oil saturations. The good facies is characterized by the presence of good pore throat sorting, good reservoir grade, and good porosity. Contrary, Medium-performance reservoir facies are characterized by the presence of medium pore sizes, medium pore throat sorting, and medium reservoir grade. Poorly performing reservoir facies is characterized by small pore size, high displacement pressure, poor throat sorting, and high water saturation levels. Based on the relative permeability calculations some samples are wet with water (water-wet), while others are wet with oil (oil-wet).

Main controlling factors and oil-bearing potential characteristics of a tight sandstone reservoir: A case study of southwest Ordos Basin

Clarifying the main controlling factors of reservoirs and their oil-bearing potential is vital for predicting tight sandstone reservoirs. The Chang 8 reservoir in the southwest of Ordos Basin is a typical tight sandstone reservoir and is widely distributed. Observation description and sampling analysis of cores, the grain size analysis, casting thin section, scanning electron microscope, mercury pressure, nuclear magnetic resonance, and conventional physical analysis are used to clarify the main controlling factors and oil-bearing potential characteristics of the Chang 8 reservoir in southwest Ordos Basin. The results show that delta front subfacies are mainly developed in Chang 8 member, including distributary channel, natural dike, estuary bar and distributary bay. The main rock type of reservoir is lithic feldspathic sandstone, followed by feldspathic lithic sandstone. The types of reservoir space are mainly intergranular pores and intragranular dissolved pores, with a small amount of clay-related pores and micro-fractures. The average porosity and permeability of the reservoir are 11.67% and 0.52 × 10−3μm2, respectively. The reservoirs with high oil saturation are mainly distributary channels and thicker mouth bar sand bodies. Compaction is the main factor of reservoir compaction (porosity loss rate is 55.73%), followed by cementation (porosity loss rate is 29.23%). The favorable diagenesis is the dissolution of feldspar grains and some cement. The Chang 8 tight reservoir contains various nano-scale pore-throat. For tight reservoirs with similar physical properties, the pore-throat structure controls the oil saturation of the tight reservoir. Favorable conditions for tight sandstone reservoirs oil saturation include favorable sedimentary environment (distributary channel or thick mouth bar) and suitable microscopic pore characteristics.

Oil generation and expulsion modeling of the syn-rift Salif oil-source rock in the Tihamah Basin, Yemeni Red Sea: Implications for shale oil exploration

The Miocene Salif Formation is an oil-source rock within the Tihamah Basin, southern Red Sea of Yemen. The Salif shale beds are characterized by high organic carbon content (TOC) up to 5.59% and high oil saturation index (OSI) (30 < OSI <260 mg HC/g TOC). However, most of the Salif shale samples exhibit OSI values of >100 mg HC/g TOC, indicating a thermally mature and oil-saturated source rock system with high oil-bearing potential. This finding is supported by the vitrinite reflectance values, representing mature oil generation window. Therefore, the shale oil potential of the Salif source rock system is studied for the first time by integrating geochemical data and geological information into a 1-D modelling scheme. The models reconstructed for the thermal and burial history infers that the Salif source rock system is located within the late oil-window from the Late Pliocene to present-day. Kerogen to oil conversion and the timing of petroleum generation and expulsion are also simulated by the 1-D models, showing that 10–50% of the total kerogen is converted into oil during the early Pliocene to the Pleistocene, which is consistent with the peak-late mature oil-window (0.70–1.26 %Ro). The models also exhibited that limited oil was expelled from the Salif source rock system since the Pleistocene-present-day as demonstrated by the TR ratio of up to 55%. The integration of source rock evaluation and modeling approach concludes that the Salif source rock provides a good potential for possible oil production, where suitable reservoir characteristics do occur.

Hydrocarbon generation and retention potential of Chang 7 organic-rich shale in the Ordos Basin, China

This study investigates the hydrocarbon generation and retention potential of Chang 7 organic-rich shale, with an emphasis on the producibility of retained hydrocarbons, using a sample set chosen to represent a maturity spectrum of 0.54–0.9% R o and organic matter of type II and mixed type II–III. Based on the present-day hydrogen index (HI pd ), the sample sets were divided into three sections: Upper, Middle and Lower. The three sections have a high hydrocarbon generation potential, with an average original total organic carbon (TOC o ) content of 12.27, 3.10 and 5.13 wt%, of which 49.39, 23.62 and 49.86 wt% represents generative organic carbon (GOC), and an original hydrogen index (HI o ) of 581.27, 278.05 and 586.82 HC g −1 rock in the Upper, Middle, and Lower sections, respectively. The bulk of the analysed samples exhibited moderate–high oil saturation, yet the oil crossover effect was only observed in two organic-rich samples, indicating organic-rich shale-oil resource systems. The sorption capacity of organic matter controls oil retention in the Chang 7 shale system, where the oil saturation index increases with increasing maturity in the oil window until a maximum retention capacity of about 82–83 mgHC g −1 TOC is reached at a vitrinite reflectance of 0.8% and thereafter decreases with further maturity. Supplementary material: A detailed spreadsheet of the back-calculated original geochemical parameters using the mass-balance method of Jarvie (2012 a ) is available at https://doi.org/10.6084/m9.figshare.c.6387577

Vertically transferred overpressures along faults in Mesozoic reservoirs in the central Junggar Basin, northwestern China: Implications for hydrocarbon accumulation and preservation

Abnormally high pressure (overpressure) is common in oil reservoirs of the Mesozoic formations in the central Junggar Basin. However, the generation mechanisms of overpressure are still uncertain, which not only affects safe drilling implementation, but also restricts the understanding of hydrocarbon migration and accumulation. Based on measured pressures and mud weights, the pore pressure distributions in the Mesozoic formations are characterized in detail. The different generation mechanisms of overpressure in mudstones and sandstones are investigated based on logging responses and basin modeling. Finally, the significance of reservoir overpressure to oil accumulation and leakage is discussed. The results indicate that overpressure in the Mesozoic reservoirs in the central Junggar Basin is mainly developed below 4500 m, the excess pressures are between 12 and 58 MPa, the pressure gradient ranges from 12 to 21 MPa/km, the pressure ratios range from 0.6 to 0.95, and the overpressure ratios are between 0.25 and 0.91. The high-overpressure in reservoirs is mostly present in isolated sand bodies that are hydraulically connected to Permian source rocks by faults. The overpressure data corresponding to a pressure gradient of 11–14 MPa/km plot on the loading curve, showing typical disequilibrium compaction overpressure. The points with pressure gradients greater than 14 MPa/km obviously deviate from the loading curve, indicating unloading overpressure mechanisms. The logging responses and numerical simulation results confirm that the overpressure in mudstone is mainly generated by disequilibrium compaction and chemical compaction, and hydrocarbon generation has a limited contribution. The unloading overpressure in the sandstone is mainly generated by the vertical overpressure transfer process from the deep Permian overpressured compartment. The vertical transfer of overpressure is often related to oil migration and accompanied by high oil saturations. However, high-overpressure presents challenges for the sealing capacity of caprocks. Hydrofracturing or the activation of preexisting faults due to high overpressure determines the risk of seal failure, which controls hydrocarbon leakage. The research is of great significance for understanding the mechanisms of hydrocarbon migration along faults and evaluating caprock integrity in similar basins.

A new method of water control for horizontal wells in heavy oil reservoirs

It is more difficult to control water production in horizontal wells than in vertical wells. It is challenging to predict the water-producing section of a horizontal well and realize staged oil recovery. With water breaking through the oil layer, the water cut of production wells sharply rises. This can even lead to early closure of production wells, which can seriously affect the economic benefits. When researchers explore water control of horizontal wells, they usually use the method of plugging the water-producing section. The success rate is often low due to water flow around the plugged section and pollution of plugging agents in the high-oil saturation area. On the basis of nitrogen for water cresting control, this paper studied the ability of a viscosity reducer (VR) and nitrogen (N2) compound system to inhibit the rise in the water crest. First, a series of two-dimensional quantitative experiments and visualization experiments were conducted to study the influence and mechanism of the VR and N2 system in controlling water cresting. The results show that compared to N2 control of water cresting (recovery improved by 2.70%), the compound system greatly improved the water control and oil increase effects of the horizontal well (recovery improved by 26.38%). The VR enters the area with high oil saturation through osmosis to reduce the viscosity of heavy oil and the water-oil mobility ratio. N2 enhanced the osmosis of the VR in the reservoir. In addition, rheological tests were performed of heavy oil mixtures, and the viscosity reduction mechanism of the VR was analyzed via diffusion-ordered spectroscopy (DOSY) and scanning electron microscopy (SEM). The experiment shows that after addition of the VR, the size of heavy oil deposit was reduced and the asphaltene surface was broken. The VR reduced the viscosity of heavy oil by depolymerizing macromolecular aggregates in heavy oil and preventing them from coming together again. Finally, a field test was conducted in a horizontal well, with a cumulative oil increase of 9286.86 bbl. The research results provide an important guiding significance for water control and oil recovery of horizontal wells.