Hydrocarbon Volumes Research Articles

Deep hydrocarbon charging and accumulation in complex fault blocks, the northern part of the eastern Liaohe depression, China

Deep exploration in complex fault-block regions is critical for global oil and gas development. As a representative region characterized by complex fault-block development, the northern part of the eastern Liaohe depression poses challenges in understanding the charging time and migration channels of deep hydrocarbons due to its intricate structural and reservoir conditions. For this purpose, this study utilizes diverse geological data from recent explorations, employing the petrological characteristics of inclusions, homogenization temperatures, and simulations of the thermal burial history to investigate the charging times of deep hydrocarbons. It combines the diagenetic processes of the reservoir with tectonic evolution to reveal the charging pathways and dynamic processes of deep hydrocarbons in the northern part of the eastern Liaohe depression. The results indicate that there are two charging periods in the study area: the late Oligocene (32.9–27.5 Ma) and from the late Neogene to the present (8.7–0 Ma). During these critical periods, faults with high activity intensity and low fault section normal stress were in an open state, which can serve as pathways for the vertical long-distance migration of hydrocarbons. In the first charging period, a substantial volume of hydrocarbon expelled from the source rocks migrates vertically into the deep sandstone reservoir through opening faults, exhibiting characteristics of source–reservoir separation. Subsequently, a brief uplift at the end of the Oligocene halted hydrocarbon generation. In the second charging period, as the source rocks further matured, a substantial volume of natural gas was injected into the deep reservoirs. At this period, the faults approached the seal, preventing hydrocarbons from migrating vertically and allowing them to enter the deep sandstone reservoirs adjacent to the source rocks, reflecting characteristics of source–reservoir proximity.

Predicting Water Saturation in a Greek Oilfield with the Power of Artificial Neural Networks.

Water saturation plays a vital role in calculating the volume of hydrocarbon in reservoirs and defining the net pay. It is also essential for designing the well completion. Innacurate water saturation calculation can lead to poor decision-making, significantly affecting the reservoir's development and production, potentially resulting in reduced hydrocarbon oil recovery. Various techniques to estimate the water saturation in both clean and shaly formations. However, the most widely used approaches in the petroleum industry rely on petrophysical models, including Archie's equation, Waxman-Smits, Simandoux, Indonesia, and dual-water models. Most of these methods are only valid for clean sands or carbonate, while the presence of clay significantly limits the accuracy of these models. On the other hand, the estimation of the water saturation through core analysis does not usually cover a large interval of the well, is highly costly, and requires much time. In this study, an empirical equation for predicting water saturation based on the weight and biases of the artificial neural networks (ANN) was developed. 334 data points of the shale volume, formation deep resistivity, porosity, and permeability and their corresponding water saturation collected from the Epsilon Field in Greece were considered for optimizing the ANN model. The ANN model was trained on 252 data sets, where the water saturation was predicted with an average absolute percentage error (AAPE) of 0.90%. Then, an empirical equation was developed based on the optimized ANN model and its weights and biases. The developed equation predicted the water saturation for the remaining 82 data sets (testing data) with an AAPE of 1.08%. The newly established empirical correlation enhances the precision of water saturation prediction and provides a cost-effective means to acquire a continuous water saturation profile, a critical asset for oilfield management and hydrocarbon exploration.

STUDY OF THE PETROPHYSICAL CHARACTERISTICS OF ROCKS FROM THE LIBWA FIELD IN THE PINDA RESERVOIR IN THE D.R. CONGO COASTAL BASIN

The Libwa field, located offshore the Democratic Republic of Congo (DRC), has significant potential for hydrocarbon exploitation, particularly in the southern part, which remains unexploited. Previous studies have identified various hydrocarbon exploitation opportunities in place, as measured by the volumes of oil in place (STOIIP). However, recent analysis by Perenco DRC highlights the need for additional volumes to meet current production levels in the northern part of the field. The Pinda reservoir, which forms an essential part of the Libwa field, has a porosity of between 15% and 19%. However, it has a very low permeability, averaging less than 2 millidarcies (mD). This low permeability makes it difficult to accurately assess porosity using seismic data, due to minor variations in the geological structure. Ongoing research is aimed at gaining a better understanding of the geological structure of the Libwa field and determining whether additional volumes of hydrocarbons exist in the southern part or in other areas of the field. Understanding the petrophysical characteristics is crucial to optimizing extraction strategies and assessing the economic potential of the reservoir.

MODERN METHODS OF QUANTITATIVE ASSESSMENT OF THE STRUCTURE OF HYDROCARBON RESOURCES OF LARGE PETROLEUM BASINS

The article discusses modern methods of quantitative assessment of the elements of hydrocarbon resource structure in large oil and gas (petroleum) basins. The assessment is based on the law of mass distribution of hydrocarbon accumulations, i.e., the truncated Pareto distribution. The procedure developed is used for: estimation of the truncated Pareto distribution parameters and cumulative hydrocarbon volumes concentrated in pools, prediction of their number and size distribution and total resources within each size-class interval; simulation of spatial distributions of hydrocarbon accumulations with transformation of a population of HC pools into a population of fields; prediction of the number and size-class distribution of total HC resources in pools and fields, and fields distribution by the number of HC pools. The involved analytical approach based on the simulation mathematical modeling is described.

Hydrocarbon generation in the onshore and offshore of the Austral and Malvinas basins based on 3D petroleum system modelling

The Austral and Malvinas basins are prolific oil and gas provinces, estimated to contain a significant proportion of undiscovered hydrocarbon reserves in the South Atlantic. A three-dimensional basin and petroleum system model (3D BPSM) is presented to visualize the complex deformation history which impacted in the volumes of generated hydrocarbons from the Lower Cretaceous source rock (LC-SR) in fold-and-thrust belt (FTB) regions through geological time. Organic geochemistry and maceral analysis obtained from samples from 28 wells were incorporated to 3D BPSM to evaluate the source rock potential from the Austral to Malvinas basins. The LC-SR contains a type II to type II–III kerogen with most samples showing a regular to good (>1%), and in few cases, excellent (>4%) TOC contents in both basins. Modelling results show higher source rock maturities (dry gas window) and kerogen transformation that occurred towards the fold-and-thrust belt regions, where deeper burial conditions were reached. A general decrease of maturity is observed towards the foreland regions of both basins. From Late Cretaceous large volumes of hydrocarbons were generated and expelled in fold and thrust belt regions of Austral and Malvinas basins. The main phase of hydrocarbon generation occurred during the Eocene, when the LC-SR reached the maximum burial, especially in the Fuegian-FTB. Hydrocarbon generation and expulsion continue to the present, particularly in the kitchen located in the eastern sector of the Malvinas Basin.

Integrated geological study for reservoir modeling and characterization of the Shurijeh gas bearing sandstones in one of the Northeast Iran gas fields

The sandstones deposited in the sequence of Shurijeh Formation comprise a giant gas reservoir in the Northeast of Iran. Five primary facies (petrofacies) were identified in the deposits of Shurijeh Formation such that the entire sedimentary sequence was divided into eight zones. Diagenetic processes have affected the pore properties of sandstone (zone D2). In this research, the petrophysical parameters (porosity and water saturation) and lithology were gamma-ray in the correlation with the petrofacies and core data. The areas with good reservoir properties for each zone and the total reservoir volume were simulated by exerting an appropriate threshold cutoff limit for the reservoir parameter (porosity and water saturation) and shale volume. For determine the economic hydrocarbon volume of the field, the uncertainty analysis in volumetric calculations was carried out utilizing the Monte Carlo method, with the production of Case50, gas-in-place was calculated as 28 × 106 cubic meters. The sensitivity analysis was conducted to determine the impact of each parameter on gas-in-place. Based on the results of this study, the sedimentary facies and diagenesis processes directly affect the in gas-in-place the reservoir. According to the sensitivity analysis, the map of underground lines (UGC) and fluid contact were the most sensitive compared to porosity and water saturation. That the fluid contact is related to the sedimentary facies and diagenetic processes. In fine-grained sedimentary facies, due to the transition zone increase, it is difficult to accurately determine the fluid boundary of the reservoir, while in coarse-grained sediments, which have high permeability, due to the transition zone reduction, the fluid boundary is more accurately determined. Also, diagenetic processes such as cementation, dissolution, and dolomitic processes cause great complexity in determining fluid boundaries. Therefore, comprehensive geological and reservoir studies must be done before any field development work. In this study, the spread of the reservoir zones B and D1, which have the highest volume of in-situ hydrocarbons, with lithofacies that are associated with high-energy environments (mostly sandstone) and have excellent petrophysical parameters in terms of reservoir quality was demonstrated. In accordance with these results, initial depositional processes control the distribution of porosity, water saturation, thickness and extension of prolific areas at the field scale.

Source Rock Assessment of the Permian to Jurassic Strata in the Northern Highlands, Northwestern Jordan: Insights from Organic Geochemistry and 1D Basin Modeling

The present study focused on the Permian to Jurassic sequence in the Northern Highlands area, NW Jordan. The Permian to Jurassic sequence in this area is thick and deeply buried, consisting mainly of carbonate intercalated with clastic shale. This study integrated various datasets, including total organic carbon (TOC, wt%), Rock-Eval pyrolysis, visual kerogen examination, gross composition, lipid biomarkers, vitrinite reflectance (VRo%), and bottom-hole temperature measurements. The main aim was to investigate the source rock characteristics of these strata regarding organic richness, kerogen type, depositional setting, thermal maturity, and hydrocarbon generation timing. The Permian strata are poor to fair source rocks, primarily containing kerogen type (KT) III. They are immature in the AJ-1 well and over-mature in the NH-2 well. The Upper Triassic strata are poor source rocks in the NH-1 well and fair to marginally good source rocks in the NH-2 well, containing highly mature terrestrial KT III. These strata are immature to early mature in the AJ-1 well and at the peak oil window stage in the NH-2 well. The Jurassic strata are poor source rocks, dominated by KT III and KT II-III. They are immature to early mature in the AJ-1 well and have reached the oil window in the NH-2 well. Biomarker-related ratios indicate that the Upper Triassic oils and Jurassic samples are source rocks that received mainly terrestrial organic input accumulated in shallow marine environments under highly reducing conditions. These strata are composed mostly of clay-rich lithologies with evidence of deposition in hypersaline and/or stratified water columns. 1D basin models revealed that the Upper Triassic strata reached the peak oil window from the Early Cretaceous (~80 Ma) to the present day in the NH-1 well and from ~130 Ma (Early Cretaceous) to ~90 Ma (Late Cretaceous) in the NH-2 well, with the late stage of hydrocarbon generation continuing from ~90 Ma to the present time. The present-day transformation ratio equals 77% in the Upper Triassic source rocks, suggesting that these rocks have expelled substantial volumes of hydrocarbons in the NH-2 well. To achieve future successful hydrocarbon discoveries in NW Jordan, accurate seismic studies and further geochemical analyses are recommended to precisely define the migration pathways.

Comparison of Hydrocarbon Volumetric Calculation between Cell-Based Model and Numerical Integration

Volume estimation for hydrocarbon reserves is a challenging yet pivotal task in engineering for exploration and production. Advances in technology now enable us to compute volume integration using programming computation. Various approaches using numerical integration, including the trapezoidal, pyramidal, and Simpson's rule, along with cell-based models as comparative methods can be used for the calculation of hydrocarbon volume. In this study, original oil in place (OOIP) is employed to determine reserve oil volume. The OOIP values obtained are 8.55 million m3 through cell-based calculations, 8.63 million m3 via the trapezoidal approach, 8.58 million m3 using the pyramidal method, and 8.57 million m3 with Simpson's 3/8 rule. The relative error ratio percentages between the cell-based model as the reference value and the numerical integration calculations as the measured values are 0.93% for the trapezoidal method, 0.35% for the pyramidal method, and 0.23% for Simpson's 3/8 rule. Simpson's 3/8 rule demonstrates the closest mathematical result to the cell-based model. Within this margin of error, the methodologies have been demonstrated to proficiently compute hydrocarbon reserves from real data through simplified and abbreviated processes.

Analysis of Reservoir Properties and Quantification of Hydrocarbon Volumes Within LK Field, Niger Delta, Nigeria

This work analyzes and estimates the qualities and volumes of hydrocarbons in the identified reservoirs (Thin Sand and Sand B) of the LK field in the Niger Delta, Nigeria. The LK field is a promising hydrocarbon reservoir located at the border of the Greater Ughelli Depobelt in the Niger Delta Basin. The data utilized encompassed a 3D seismic survey, which was analyzed to delineate faults, identify stratigraphic horizons, and generate maps illustrating the time and depth structures within the subsurface. Well log data, including gamma ray, resistivity, and density/neutron measurements, were analyzed to evaluate and describe the petrophysical characteristics of the subsurface rock formations. The Thin Sand reservoir unit contains natural gas, while the Sand B reservoir is divided into two separate zones: the first zone (Z1) contains natural gas, and the second zone (Z2) contains oil. For Sand B, Z1, and Z2, the gross thicknesses are 13.16m and 57.46m, net thicknesses are 11.32m and 45.39m, NTGs are 0.86 and 0.79, shale volumes (Vsh) are 0.13 and 0.21, effective porosities (?e) are 0.28 and 0.21, water saturations (Sw) are 0.11 and 0.39, and hydrocarbon saturations (Sh) are 0.89 and 0.61, respectively. For the Thin Sand reservoir, the gross thickness is 6.00m, net thickness is 4.74m, NTG is 0.79, Vsh is 0.21, ?e is 0.23, Sw is 0.12, and Sh is 0.88. The stock tank oil initially in place (STOIIP) in the Sand B, Z2 reservoir is estimated to be 46.8 million barrels, with a recoverable oil volume of 9.4 million barrels, assuming a 20% recovery factor. The stock tank gas initially in place (STGIIP) is estimated at 10.4 billion cubic feet (Bcf) in the Thin Sand reservoir and 30.6 Bcf in the Sand B, Z1 reservoir, with recoverable gas volumes projected at 8.3 Bcf and 24.5 Bcf, respectively, assuming 80% recovery factors. After estimating the volume of hydrocarbons in the known reservoirs, significant and economic amounts of gas and oil for commercial purposes were discovered. However, this research study faces challenges such as uncertainty, unreliability, and varying scales due to different origins within the field. Further research using unconventional computational tools together with high-resolution simulating software is needed to produce more detailed and accurate results.

Effect of hydrocarbon volume ratio in sweet top-of-the-line corrosion under water-hydrocarbon co-condensation

Wet gas pipelines transport unprocessed natural gas that contains water and carbon dioxide (CO2), which combination can lead to severe wall loss caused by CO2 or sweet corrosion in carbon steel. Under specific conditions, CO2 corrosion occurs at the top section of the pipeline, which is known as top-of-the-line corrosion (TLC). TLC tests were conducted in the water-hydrocarbon co-condensation environment using 10 vol% n-heptane and 25 vol% n-heptane to simulate the internal condition of a wet gas pipeline to study the effect of hydrocarbon volume ratio towards TLC. The presence of n-heptane showed minimal effect on the gas temperature profile; however, n-heptane suppressed the water condensation, resulting in a tremendous decrease in the water condensation rate (WCR). The TLC rates were found to be lower in the presence of n-heptane, which can be attributed to the reduced WCR and water-wetted areas. The presence of n-heptane had no significant effect on the pitting rates but showed an increasing pit ratio as the n-heptane volume increased. TLC tests were conducted at three durations: one day, two days and three days showing that n-heptane has no significant effect on corrosion kinetics.

Characteristics and origin of low-organic-matter carbonate source rocks in the Middle–Upper Ordovician, Tarim Basin, northwestern China

The continually-discovered large volumes of marine hydrocarbons indicate a huge exploration potential within the carbonate rocks of Ordovician in the Tarim Basin, northwestern China. The Middle–Upper Ordovician (O2+3) carbonate source rocks are at a highly mature stage. These rocks presently contain a low amount of total organic carbon (TOCpd ≤0.5%) (TOCpd means the present-day TOC). A mass balance approach is used to identify the source rocks that have expelled hydrocarbons. The characteristics and origin of hydrocarbon expulsion from low-TOCpd source rocks are studied, which are significant for oil exploration in the basin. The results showed that a low-TOCpd O2+3 source rock having expelled hydrocarbons was type I and had a very narrow oil window. With a high rock maturity and a high original TOC (TOCo) value exceeding 1%, nearly 80% of the generated hydrocarbons were expelled. The content of gammacerane and C28 steranes in the oil and source rock extracts were relatively lean, with a V-shaped distribution of regular steranes, suggesting a possible genetic relation between the low-TOCpd source rocks and the marine oil in the Tabei area. Hydrogen-rich planktonic algae or acritarchs were the main hydrocarbon parent materials, distributed in the subsiding platform-slope facies. Organic matter was preserved under reducing conditions, and source rocks were formed with a favorable kerogen type and a moderate hydrocarbon generation potential. This study illustrates the hydrocarbon expulsion of low TOCpd source rocks in northern Tarim Basin, which is greatly significant for analyzing the genesis of marine crude oil in Tarim Basin, and evaluating the distribution of marine source rocks. This research method is theoretically significant for oil and gas exploration in the same type of highly-mature carbonate paleobasins.

An enhancement in the petrophysical evaluation in a vuggy carbonate gas reservoir by integrating the core data and empirical methods, Zagros basin, south of Iran

The presence of vuggy pore types poses challenges in accurately assessing effective porosity. This study focuses on the significant scientific issue of improving petrophysical evaluation in vuggy carbonate gas reservoirs. The Kangan Formation is one of the main gas reservoir formations in the southern Zagros region, Iran. The main objective of the current research is to distinguish and exclude the influence of vuggy pore types from effective porosity in the reservoir pay zones of the Kangan reservoir.In the current research, a combination of full suite logs, image logs, core analysis, and thin section studies was employed. The image logs illustrate that vuggy porosity is abundant in the Kangan Formation and these results are confirmed by the available core thin sections, specifically in Zone Kangan_B; Additionally, the cross plots of compressional velocity versus bulk density and total porosity, as a part of rock physics study, indicate the characteristics of the vuggy reservoir. Two methods are utilized to quantify vuggy porosity. The first method, the Velocity Deviation Log (VDL) approach, identifies various available pore types, especially vugs. The second method is a newly proposed approach that can exclude vuggy porosity from the computed effective porosity. In this novel approach, a variable porosity exponent (m) is derived by adopting the Lucia equation to exclude vuggy porosity from the effective porosity computations. Thus, petrophysical evaluation can be implemented based on the constant and variable “m”. Comparing both petrophysical results, it is evident that the amounts of effective porosity and water saturation are modified in the vuggy-bearing intervals. Applying the proposed approach will improve the accuracy of petrophysical properties and lead to the proper calculation of the hydrocarbon volume in the carbonate reservoir rocks containing isolated vugs, particularly in gas-bearing reservoirs where conventional logs are affected by gas contents.

Volumetric Analysis of Selected Reservoirs in Ogbenu Field, Niger Delta, Nigeria Using 3D Seismic and Well Log Data

Volumetric analysis of selected reservoirs in the Ogbenu field, Niger Delta, Nigeria was carried out using 3D seismic and well log data. The objectives include the identification and selection of suitable reservoirs, correlating the reservoirs across the field, generating synthetic seismograms and seismic-to-well ties, performing structural interpretation of faults and horizons to generate time and depth structure map, identifying potential prospects and volumetric analysis to estimate the volume of hydrocarbon in place. The adopted methodology comprises structural, petrophysical and volumetric analysis facilitated by Petrel and Techlog software suites. Well log were utilized to identify distinctive features and cross-well stratigraphic correlation which revealed complex variations, indicating a potential thickening trend in the Agbada sequence towards the southwest. Faults and horizons were mapped to establish the structural framework, unveiling a faulted rollover anticline influenced by lateral fault block movements, contributing to a complex structural style. Detailed analysis of seismic responses, synthetic seismograms, and petrophysical parameters from the well log led to the identifying and correlating of eight prospective reservoir intervals (Reservoir A to H). Average petrophysical parameters, including thickness, porosity, Not-to-Gross ratio, volume of shale, and water saturation were derived from the petrophysical analysis, confirming the eight reservoirs exhibit good petrophysical properties, indicating their potential as promising prospects. The reservoirs exhibit varying qualities, with a southward decline in reservoir quality and indications of gas-water contacts in reservoir A with a similar trend across the other reservoir units. The estimated Original Oil in Place volume were. Reservoir A (29,025.57 MMBOE), B (23.95 MMSTB), C (2,776.37 MMBOE), D (48.19 MMSTB), E (16.69 MMSTB), F (131.98 MMSTB), G (42.19 MMSTB) and H (102.60 MMSTB). This integrative approach revealed complex reservoir variations and structural intricacies, enhancing the understanding of future exploration and production strategies in the Ogbenu field.

Reservoir Characterization of Jeribe and Euphrates Formations in Qaiyarah OilField

Three-dimensional static model is a crucial key for a reservoir heterogeneity representation and an initial evaluation of the hydrocarbon in place, thus for a success field development, an accurate reservoir characterization is a fingerprint for the decision making. The initial goal of this study is to generate a static model for Jeribe and Euphrates formations in Qaiyarah oil field to investigate the distribution of the discrete and continuous proprieties such as, permeability and water saturation, in sequence, recognizing the value of the reserve to identity the ability of developing this reservoir as a final decision for future investment. The sever hetrogeneity and complexity of Qaiyarah oil field were the main challenges confronted through the static model building, in consequence, this paper repesents a fingerprint for the future studies in this area. The conceptual methodology in this research includes the integration of the well log data and final well reports to construct the three-dimensional model through log interpretation, sequential simulators, and properties upscaling. Initial volumetric calculations were performed mainly based on the petrophysical properties distribution of eight wells and oil water contact level. Accordingly, the hydrocarbon volume in place were estimated in the two pay reservoirs under study Jeribe and Euphrates formations. The results showed that Euphrates Formation has dominated by the largest portion of reverse (554*106 Sm3), while Jeribe Formation has lower volume of oil initially in place about 194 *106 Sm3.

Mechanism of water-induced alterations to nanoscale pores: Implications from anhydrous versus hydrous pyrolysis

In this study, shale samples from the Chang7 Member of Triassic Yanchang Formation in Ordos Basin, China were used to conduct artificially induced thermal maturity experiments from 250 °C to 450 °C for 72 h. The role of water in organic matter (OM) conversion and nanoscale porosity alterations were observed and discussed comprehensively by Rock-Eval pyrolysis, low pressure N2/CO2 adsorption, Fourier transform infrared spectroscopy (FTIR) and water-soluble organic acids (WSOAs) experiments. Results show that Rock-Eval pyrolysis parameters (Tmax, S1, and S2), TOC content, WSOAs and pore volume (PV) show slight changes below 350 °C while these parameters were considerably altered above 400 °C under two different pyrolysis conditions (anhydrous and hydrous), indicating that after 400 °C, the OM conversion and bitumen cracking will accelerate. In comparison to anhydrous pyrolysis, hydrous pyrolysis always has smaller Tmax, implying that water could inhibit OM thermal progression. Moreover, S1 of hydrous pyrolysis is approximately two times higher than that of anhydrous pyrolysis, which originates from water providing an exogenous source of hydrogen to generate excessive volumes of hydrocarbons, enhancing the conversion rate of OM. The WSOAs are 2 to 4 times greater under hydrous pyrolysis than anhydrous pyrolysis, denoting that the presence of water could improve the yield of organic acids via inhibiting the polycondensation of oxygen-containing functional groups and oxidizing organic components by hydroxyl radicals. Moreover, below 350 °C, pyrolysis shale residues exhibit a slightly smaller PV in hydrous pyrolysis, mainly due to the infilling effect of bitumen. However, exceeding 400 °C, PV that was obtained from low pressure N2 adsorption under hydrous pyrolysis conditions is found to be two times as large as the value under anhydrous pyrolysis conditions, which is attributed to the net-PV increase reactions such as thermal cracking, and the dissolution of organic acids. Furthermore, in anhydrous pyrolysis, the polycondensation of oxygen-containing functional groups and the carbon-carbon cross linking could be considered as the two main reaction pathways to release the sources of hydrogen. Collectively, the presence of water is significant for hydrocarbon generation and porosity evolution during thermal progression of OM at various stages.

Occurrence Characteristics of Chang 7 Shale Oil from the Longdong Area in the Ordos Basin: Insights from Petrology and Pore Structure

Organic geochemistry experiments, X-ray diffraction (XRD), field emission scanning electron microscopy (FE-SEM), N2 adsorption, CO2 adsorption, and two-dimensional nuclear magnetic resonance (2D NMR) were performed on ten Chang 7 shale samples (Longdong area, Ordos Basin) to elucidate their pore structure and the characteristics of oil occurrence. Moreover, the factors influencing free oil were discussed, and an occurrence model was established. FE-SEM analysis reveals that the pore types include interparticle pores, intraplatelet pores within clay aggregates, rare fracture pores, and organic matter (OM) pores. The pores are predominantly slit-shaped. The development of micropores was mainly contributed to by OM. Quartz and clay minerals influence the development of macropores and mesopores, feldspar mainly controls macropore development, and pyrite most strongly affects micropore development. Micropores and mesopores constitute the main total pore specific surface area, while mesopores and macropores are the main contributors to the total pore volume. Pores > 2 nm are the main storage spaces for shale oil, and free oil mainly occurs in pores > 20 nm. Adsorbed oil and free oil were assessed by NMR T1–T2 mapping. The adsorbed oil signal intensities range from 7.5–23.4 a.u. per g of rock, and the free oil signal intensities range from 4.4–23.2 a.u. per g of rock. The free oil proportions are 15.9–70.6% (average of 44.2%). The free oil proportion is negatively correlated with the clay mineral content and total organic carbon (TOC) content but positively correlated with the saturated hydrocarbon content and volume of pores > 20 nm. The results of this study could help optimize favorable shale oil target areas.

Impact of kaolinite and iron oxide cements on resistivity and quality of low resistivity pay sandstones

Low resistivity pay (LRP) zones have been identified within many siliciclastic reservoirs around the world, and have gained significant attention due to their ability to hold substantial hydrocarbon volumes. Previous studies have focused on investigating the role of highly conductive minerals, microporosity, bound water, and bed thickness in reducing resistivity within LRP zones. However, the impact of kaolinite and iron oxides in influencing the resistivity of LRP zones remains poorly understood. To address this, we examined outcrops cemented by pore-filling kaolinite and iron oxides, which serve as analogues to subsurface reservoirs. This study combined field description with laboratory analyses, including petrography, mineralogy, porosity, permeability, resistivity, and nuclear magnetic resonance to investigate the occurrence of kaolinite and iron oxide cements and their impact on resistivity and reservoir quality. The study observed various iron-bearing structures including concretions, fracture infills, layers, ferricrete, and liesegang bands. These structures are cemented by microporous pore-filling kaolinite (up to 18%; average: 6.6 %) as well as goethite and hematite (up to 21%; average: 3.5%). Observations from this study indicate that both depositional processes, such as grain size, and diagenetic pore-filling cements, significantly influenced the resistivity and reservoir quality of sandstones. Fine-grained sandstones containing substantial amounts of microporous kaolinite (>15%) and iron oxides (>17%) cements show very low resistivity values (≤0.2 Ω m), as well as low porosity (<10%) and very low permeability (<1 mD). Conversely, medium to coarse-grained sandstones with lower concentrations of kaolinite (<15%) and iron oxides (<5%) cements exhibited higher resistivity values (2–40 Ω m; average: 8 Ω m) and displayed higher porosity (average: 22%) and permeability (average: 1300 mD). This study underscores the importance of understanding and characterizing the presence and distribution of iron oxides and kaolinite cements, along with other factors like microporosity and grain size within LRP zones. Such understanding is crucial for accurate resistivity measurements, reservoir quality prediction, and hydrocarbon estimation in sandstone reservoirs worldwide.

A SYNTHESIS OF THE GEOLOGY AND PETROLEUM GEOLOGY OF THE IRANIAN PORTION OF THE SOUTH CASPIAN BASIN AND SURROUNDING AREAS

The South Caspian Basin, the northern Alborz Mountains, the Gorgan plain and the Moghan plain constitute the northernmost and youngest petroleum system in Iran. This region was part of the Paratethys realm from Oligocene to Pliocene time. The Oligocene – Miocene Maikop/Diatom Total Petroleum System of the South Caspian Basin produces major volumes of hydrocarbons in Azerbaijan and Turkmenistan, and the Iranian sector of the basin has consequently undergone exploration due to its generally similar geology. The 20 km thick, dominantly Cenozoic sedimentary cover in the basin is reduced to less than 3 km in the northern foothills of the Alborz Mountains, and scattered surface oil seepages in the latter region are believed to be generated by Cretaceous and Miocene source rocks. In the Moghan plain to the southwest of the South Caspian Basin, anticlinal folds of Oligo‐Miocene Zivar Formation sandstones may be prospective for hydrocarbon exploration. Mud volcanoes in the Gorgan plain and in adjacent offshore regions at the SE margin of the South Caspian Basin are associated with hydrocarbon seepages, and appear to be sourced by Cretaceous and Cenozoic shales and mudstones. Major structural features in the southern part of the South Caspian Basin include Cenozoic mud diapirs, folds and gravity structures.

Mass balance of generation, retention, and production for the Wolfcamp-sourced hydrocarbon in the Permian Delaware Basin: Insight on remaining recoverable resource and expulsion efficiency

Detailed quantification of basin-wide hydrocarbon (HC) masses from generation to production is necessary for a quantitative petroleum system analysis, and ultimately, for accurate resource estimation. Such quantified HC masses must be balanced following the fundamental laws of mass conservation. Mass balance is particularly important for unconventional-conventional petroleum systems in which expulsion efficiency (EE) is a critical parameter defining HCs in place, within the source rock (SR) interval and outside. This study performs an HC mass balance assessment aiming primarily to obtain insights on the remaining recoverable and EE, applied to the Wolfcamp Formation (Fm) in the Permian Delaware Basin. Calculated generated HC volumes from the Wolfcamp Fm based on the assumed 3D geologic model and p90/50/10 SR properties are 878/2107/4514 billion barrels of oil equivalent (BBOE). The mass balance is performed with three calculation scenarios: (1) inversion of EE (based on the United States Geological Survey [USGS]-estimated remaining recoverable HC in the Wolfcamp Fm), (2) forward calculation with multiple assumed EE, and (3) HC expulsion simulation. The mass balance with the inversion of EE indicates that the p90/50/10 of 58%/62%/69% overall EE is required for the Wolfcamp Fm to achieve the USGS-estimated remaining recoverable HC of 35/78/140 BBOE. Both mass balance with forward calculation and expulsion simulation predict overall lower p90/50/10 EE of 50% and 30%/56%/75%, respectively, thus resulting in higher than the USGS-estimated remaining recoverable HC in the Wolfcamp Fm in most scenarios. All of the mass balance calculations are also consistent with the interpretation of Wolfcamp unconventional play as a self-sourced play. This workflow is an efficient tool for taking a quantitative look at the petroleum system, especially related to the possibilities of generated HC distribution in the system. The calculated mass balance can serve as a reference in modeling unconventional systems and resources.

Petroleum geochemistry and origin of shallow-buried saline lacustrine oils in the slope zone of the Mahu sag, Junggar Basin, NW China

Recently, significant oil discoveries have been made in the shallower pay zones of the Jurassic Badaowan Formation (J1b) in the Mahu Sag, Junggar Basin, Northwest China. However, little work has been done on the geochemical characteristics and origins of the oil in the J1b reservoir. This study analyzes 44 oil and 14 source rock samples from the area in order to reveal their organic geochemical characteristics and the origins of the oils. The J1b oils are characterized by a low Pr/Ph ratio and high β-carotene and gammacerane indices, which indicate that they were mainly generated from source rocks deposited in a hypersaline environment. The oils are also extremely enhanced in C29 regular steranes, possibly derived from halophilic algae. Oil-source correlation shows that the oils were derived from the Lower Permian Fengcheng Formation (P1f) source rocks, which were deposited in a strongly stratified and highly saline water column with a predominance of algal/bacterial input in the organic matter. The source rocks of the Middle Permian lower-Wuerhe Formation (P2w), which were deposited in fresh to slightly saline water conditions with a greater input of terrigenous organic matter, make only a minor contribution to the J1b oils. The reconstruction of the oil accumulation process shows that the J1b oil reservoir may have been twice charged during Late Jurassic–Early Cretaceous and the Paleogene–Neogene, respectively. A large amount volume of hydrocarbons generated in the P1f source rock and leaked from T1b oil reservoirs migrated along faults connecting source beds and shallow-buried secondary faults into Jurassic traps, resulting in large-scale accumulations in J1b. These results are crucial for understanding the petroleum system of the Mahu Sag and will provide valuable guidance for petroleum exploration in the shallower formations in the slope area of the sag.