Petroleum Basins Research Articles

Mineralogical and Maturation Considerations of the Coqueiros Formation (Campos Basin, Brazil): Insights from Multi-Technique Analyses of Source Rocks

The Coqueiros Formation, a strategic stratigraphic unit within the Lagoa Feia Group (LFG) in the Campos Basin offshore Brazil, is known for its lacustrine carbonate deposits, which include both organic-rich shales and economically important “coquina” reservoirs. While coquina facies are widely recognized as reservoirs, the source-rock potential of the intercalated shales remains relatively underexplored. This study aims to characterize the mineralogy and thermal maturity of the Coqueiros Formation to assess its potential as a source rock, using a multi-technique approach integrating X-ray Diffraction (XRD), Scanning Electron Microscopy (SEM), and Raman spectroscopy analyses of shale samples from two wells: 3-BP-11-RJS and 6-DEV-18P-RJS. XRD analyses revealed a heterogeneous mineralogy dominated by carbonates (calcite and dolomite) and quartz, with significant contributions from clay minerals and trace minerals such as pyrite and barite. SEM imaging revealed a heterogeneous fabric with grain size, morphology, and porosity variations, reflecting a dynamic lacustrine depositional setting influenced by storm events and fluctuations in terrigenous input. The presence of authigenic minerals, as reported in other studies, such as saddle dolomite, mega-quartz, and various sulfides, provides evidence for hydrothermal alteration, likely related to Late Cretaceous magmatic activity in the Campos Basin. Raman spectroscopy yielded equivalent vitrinite reflectance (Ro%) values consistently exceeding 1.00, ranging from 1.03 to 1.40, indicating that the organic matter in the Coqueiros Formation shales has attained a high thermal maturity level, surpassing the oil window and reaching the condensate wet gas zone. The mineralogical and equivalent maturation data presented herein provide a valuable foundation for future studies, highlighting the complexity and heterogeneity of the Coqueiros Formation and its potential significance as a source rock within the Campos Basin petroleum system.

An updated terrestrial heat flow data set for the Junggar basin, northwest China: implications for geothermal resources

SUMMARY Terrestrial heat flow plays a vital role in determining the present thermal regimes of sedimentary basins, offering a robust foundation for understanding hydrocarbon maturation processes and the geothermal resource potential. The Junggar basin is one of the largest and most petroliferous superimposed petroleum basins in China. However, research on heat flow is scarce. In this study, 94 new high-quality heat flow values are derived from through borehole temperature analysis and thermal conductivity measurements of rocks. The results indicate that (1) the geothermal gradient in the basin varies from 11.4 to 28.3 °C km−1, with a mean value of 20.9 ± 3.4 °C km−1, and the heat flow varies from 23.4 to 64.5 mW m−2, with a mean value of 45.1 ± 8.4 mW m−2. The overall low geothermal gradient and heat flow are attributed to the continuous cooling during the Meso-Cenozoic. (2) At basin scale, the high heat flow values are primarily concentrated in areas characterized by basement uplift, whereas the low heat flow values are mainly located in the depressions. This suggests that thermal refraction is the primary factor influencing the heat flow variations. (3) Although large-scale development and utilization of geothermal resources face challenges, certain local areas in the basin show promise for geothermal resource utilization.

Nature and occurrence, geochemical characteristics, and families of the crude oils in Sirt Basin, Libya: Implication for super rift basin petroleum system

In this study, we investigated the nature and characteristics of petroleum fluids in a super-global basin situated in the central north of Libya. With over 100 discovered fields (comprising oil and gas), this study aimed to understand the basin's petroleum accumulation mechanism (PAM), thereby shedding light on the factors contributing to significant petroleum discoveries in North Africa (Libya). The primary objective of this study was to provide a detailed regional refined oil family distribution and new insights into the total petroleum system (TPS) of the basin. This analysis was based on the integration of regional geology and organic geochemistry. Additionally, we utilized the physical properties of petroleum, such as API and sulphur content (%S), to obtain a better understanding of the regional physical nature of petroleum types and properties. Organic geochemical data for the basin fields were compiled, focusing on key biological marker and carbon isotope (‰ δ13C) data for saturated and aromatic compounds. These data were used to understand the origin, depositional source, and thermal maturity of the generated, migrated, and accumulated petroleum fluids. The study established specific types of organofacies and their relationships with petroleum phase characteristics, including type and quality, categorized into known groups (e.g., B, C, and D/E). Hierarchical cluster analysis (HCA) and map-based presentation approaches were used to determine the spatial types and distributions of oil and gas families in the basin. This was achieved by selecting the input parameters from various datasets and defining the significant parameters to characterize the distribution patterns. The findings indicate that the bulk fluid of the Sirt Basin primarily resembled Brent oil, which was characterized by a very low sulphur content (less than 1.4%). The API gravity ranged from 30 to 65, reflecting a diverse range of oil types within the basin. The crude oils in the basin were primarily derived from marine organofacies, predominantly from type B. This inference is supported by related biomarkers such as regular steranes and isoprenoids. Furthermore, the analysis of carbon isotopes provided a similar indication, with values ranging from −32 to −27 for ‰ δ13C for saturates and −31.2 to −25.4 ‰ δ13C for aromatic compounds. The thermal maturity biomarker ratio (Ts/Ts + Tm) of the Sirt Basin crude oils varied from 0.35 to 0.92, suggesting different levels of thermal maturity, typically ranging from the mid to late mature stages. This observation is consistent with the indication based on the 22S/22S + 22R ratio. The basin exhibited four dominant oil families and eight subfamilies with the same geochemical characteristics (HCA-based analysis), including early and later generations, relatively sulphurized oils, and condensate families.

Geochemical evaluation of Sarvak oil reservoir using biomarkers, carbon isotope and trace element: A case study from Southwest Iran

The crude oils of the Sarvak reservoir were studied by integrated geochemical, inorganic and isotopic analyses to evaluate the origin, depositional conditions, geological age, thermal maturity of the source rocks and possible facies from which these oils were sourced. This study provides new insights into the Middle-Jurassic age source rock in the Azar Oilfield. This is the first geochemical study in Azar Oilfield where non-biomarker parameters and biomarker parameters were utilized to achieve the objectives. The n-alkane distribution pattern along with their standard ratios, including CPI (0.83–1.03), TAR (0.18–0.29) and isoprenoids (Pr/Ph, 0.52–0.65) as well as pristane/n-C17 versus phytane/n-C18 cross-plot indicate a marine source of the organic matter deposited in an anoxic condition. The sterane parameters such as C27 and C29 are characterized by the predominance of C27ααα-20R steranes (41%–49%) and also depict the algal source of organic matter. The organic input and facies of the source units were also determined by terpanes C29/C30H, Ts/Tm, C35/C34-HH, and DBT/Phen. The relatively high ratio of C29/C30H along with the ratios of Ts/Tm (<0.5) and C35/C34 (>0.8) reflect the carbonate marine facies of the source rocks. Furthermore, the higher values of the homohopane index (>0.1) along with the low ratio of the gammacerane/C30-H (0.06–0.22) as well as the high ratio of V/Ni (>1) further indicate anoxic environments. The dibenzothiophene/phenanthrene ratios of the oil samples (from 2.43 to 3.25) indicate the marine carbonates/marl zone. This genetic classification is also supported by stable carbon isotopic compositions (δ1³C). Most of the maturity-related biomarkers and non-biomarker parameters such as CPI, steranes-C29S/(S + R), ββ/(αα+ββ), moretane to hopane (M29/C30H), pentacyclic terpanes C27Ts/(Ts + Tm), C32-S/(S + R) hopanes, and methyl phenanthrene index agree that the analyzed oils have originated from mature source rocks. Ultimately, this study has demonstrated that analyses of biomarkers and their stable isotope compositions (δ13C and δ34S) complemented with trace element data provide an excellent novel tool for better understanding the basic concepts in petroleum basins and for solving a wide range of problems during petroleum exploration.

Modelling a foreland fold-and-thrust petroleum system: a Permian example in the NW Sichuan Basin, Southwest China

ABSTRACT Foreland thrust belts are globally significant areas for oil and gas exploration. These belts undergo unique tectonic activity, resulting in distinct variations in the accumulation of oil and gas. Studying the genetic evolution of deep oil and gas in these thrust belts is a crucial means of revealing the patterns of deep oil and gas accumulation. This study utilized a novel approach that combines reservoir geochemistry and basin simulation to determine the migration process of oil and gas in the foreland thrust fault belt of northwestern Sichuan Province. To achieve this goal, we established a thermal evolution model of lower Palaeozoic source rocks through organic chemical analysis. The balanced profile technique was used to determine the paleotectonic evolution pattern of the critical period in this area. Additionally, the mixed flow migration algorithm was employed to simulate the evolution of the Palaeozoic petroleum system. Through basin petroleum system modelling (BPSM), it was discovered that the bitumen found in the thrust nappe belt originated from the lower Cambrian strata. Furthermore, the gas reservoir in the hidden fault belt primarily migrated from the lower Cambrian strata and was also partially mixed with thermogenic gas from Permian source rocks. After establishing the genetic models of various tectonic belts in the study area, it became clear that there are notable differences in hydrocarbon accumulation within these belts. The BPSM results revealed that the oil present in the thrust nappe belt was generated in Lower Cambrian source rocks through early Indosinian hydrocarbon expulsion and continuous charging. The gas found in the thrust nappe belt was produced through the process of oil cracking in the deep reservoir located in the hidden front belt during the late Indosinian. The depth of the thrust nappe belt has helped to preserve hydrocarbon reservoirs. The natural gas present in the hidden fault belt primarily originates from lower Cambrian source rocks, which are combined with gas generated by oil cracking in lower Permian source rocks after the Yanshanian. Therefore, hydrocarbons accumulate deeply in the footwall of the thrust fault belt. The BPSM offers a fresh approach to hydrocarbon genetic models of thrust fault zones in the western Sichuan Basin, and it is beneficial for accurately evaluating the potential for deep hydrocarbon resources in comparable geological settings.

3D seismic analysis of complex faulting patterns and fluid escape features and their relation to Late Cenozoic Magmatism in the Bass Basin, offshore SE Australia

Abstract Igneous intrusions in sedimentary petroleum basins are often perceived as having a negative impact on the elements of the petroleum system, though the impact of intrusion-related deformation features on petroleum systems and broader geoenergy applications is not well understood. In this study, we use 3D seismic reflection data to document a variety of deformation styles that are spatially and temporally associated late Cenozoic magmatic activity in the Bass Basin, offshore southeastern Australia; three types of normal fault systems (conjugate faults, concentric faults, radial faults) and fluid escape pipes. These deformation features occur in the overburden up to ∼600 m above underlying igneous intrusions, within the Eocene to Miocene Demons Bluff and Torquay formations. The conjugate faults bound graben and are interpreted to have formed in response to underlying dyke intrusions. The radial faults are interpreted to have formed in response to overburden uplift, though the link between these and associated igneous activity is less clear. We identify 101 fluid escape features that show variation in both the morphology of their surficial depressions and of the seismic reflection characteristics of their infilling deposits. These features are interpreted to be hydrothermal or volcanic vents with underlying pipe-like feeders, depending on their spatial association with adjacent or underlying igneous intrusions. The concentric fault systems are associated with surficial depressions, and quantitative analysis of reflection sags within these depressions suggest that they are a result of subsurface subsidence in response to formation of maar-craters. The intrusion-related deformation features documented in this study may have multiple effects on working petroleum systems, such as providing secondary fluid flow pathways that can either reduce seal integrity, or enabling migration of fluids into shallower reservoirs.

An application of AHP and fuzzy entropy-TOPSIS methods to optimize upstream petroleum investment in representative African basins

The growing demand of China for petroleum heightens the complexities and prospects in worldwide investments, necessitating refined and strategic investment approaches. Evaluating the potential of different hydrocarbon-potential areas needs more comprehensive scientific evaluation models. This study aims to establish a Comprehensive Investment Potential of Petroleum (CIPP) framework for targeted sedimentary basins by using an integrated approach that combines the Analytic Hierarchy Process (AHP) and the Entropy-Weighted Fuzzy TOPSIS models. We focus particularly on representative African basins to inform strategic decision-making for the Chinese overseas petroleum enterprises. We firstly interpret the geological condition of these petroleum basins by researching multiple databases and proprietary research data. Then, we use a combined approach of ranking-classification-correlation analysis to evaluate 17 representative basins, taking into account both overall and individual key performance indicators. Our findings suggest the Illizi Basin and the Offshore Côte d'Ivoire Basin could be the most favorable for investment and development. Those like Southwest African Basin warrant cautious consideration. The new evaluation model and computational workflow offer an effective workflow for assessing multiple petroleum basins. This work provides not just practical investment strategies for companies aiming for African petroleum basins, but also a transferable methodology for optimizing investment decisions.

Evolution of Mesozoic paleo-uplifts and differential control on sedimentation on the southern margin of Kuqa Depression, Tarim Basin

The paleo-uplift is an important tectonic element which is key to control the sedimentary system in petroleum basins. The evolution of Mesozoic paleo-uplifts and differential control on sedimentation on the southern margin of Kuqa Depression, northern Tarim Basin, is still unclear, restricting successful petroleum exploration and development. Based on borehole and 3D seismic reflection data on the southern margin of the Kuqa Depression, the parameters of paleo-uplifts, such as residual thickness, eroded thickness, slope height, slope angle, slope height difference were extracted. Combined with the composition of the detrital minerals in the Cretaceous Shushanhe Formation which was one of the target layers and the Paleo-lithofacies map before the deposition of Cretaceous, the paleo-uplifts could be further divided into four sub-uplifts. The paleo-uplifts grew and extended in the Triassic to Jurassic, decreased in the Jurassic to Cretaceous, and transformed into subaqueous low uplift in the upper part of Cretaceous Shushanhe Formation. The evolution of paleo-uplifts controlled strata and facies, resulting in no Triassic strata were deposited in the north of Yaha-Kudong and Luntai sub-uplifts, while the Jurassic strata in the Xinhe and Qiaogu sub-uplifts experienced extensive erosion. The faults in the Xinhe sub-uplift and steep slopes in the Luntai sub-uplift controlled the deposition of alluvial fans and fan deltas, while the gentle slopes of Qiaogu and Yaha-Kudong sub-uplifts controlled the distribution of braided river deltas. The evolution of the paleo-uplifts was synchronized with regional tectonism, including the south Tianshan collision orogeny and the post-orogenic stress relaxation. This study will help elucidate the development and evolution of the paleo-uplifts on the southern margin of Kuqa Depression, northern Tarim Basin, clarify the relationship between provenance and sedimentary system, and guide the oil and gas exploration in Tarim Basin and other basins with the similar background globally.

Comparison and integration of pore pressure measurements and indicators from drilling data in a deep geothermal energy play in SE Germany

The North Alpine Foreland Basin in SE Germany is a post-mature petroleum basin and today Germany's most prolific deep geothermal energy play. Drilling of deep wells is often challenged by the complex pore pressure distribution, which has been studied in the past, but quality and reliability of individual pore pressure measurements and indicators have so far been barely addressed. This is particularly critical, since most datasets originate from old hydrocarbon wells and often display limited availability and poor quality. This paper analyses pore pressure measurements and indicators from 315 deep hydrocarbon and geothermal wells. The dataset covers pressure measurements, drilling mud weights, caliper logs, drilling events and gas readings. A large number of pressure measurements are exposed to uncertainties, resulting predominantly from incomplete pressure build-ups. In addition, investigation of drilling mud weights combined with wellbore instabilities, gas readings and pore pressure-related drilling problems suggest that many wells were subject to underbalanced drilling and mud weight alone is not a reliable pore pressure indicator. The study provides a recommendation for pre-drill pore pressure prediction based on the investigated datasets, which also presents a reference case for other post-mature petroleum basins transitioning to new industries, such as deep geothermal. Thematic collection: This article is part of the Earth as a thermal battery: future directions in subsurface thermal energy storage systems collection available at: https://www.lyellcollection.org/topic/collections/thermal-energy

Emplacement dynamics of a complex thick mafic intrusion revealed by borehole image log facies analyses: Implications for fluid migration in the Parnaíba Basin petroleum system, Brazil

Sill intrusions may play a significant role in the development of petroleum systems in sedimentary basins by promoting maturation of source rocks, influencing fluid migration and acting as reservoirs, traps, and seals for hydrocarbon accumulations. Within this study, we present a novel approach to interpreting geophysical borehole data for a ca. 174 m thick sill from the Parnaíba Basin revealing new insights into both the emplacement mechanisms and impacts of the sill on hydrocarbon migration and trapping. High-resolution ultrasonic and microresistivity borehole image logs were integrated with conventional log data, petrography of eight side wall cores and total gas data recorded during drilling. The petrographic analysis revealed finer crystalline dolerite at the top and bottom layers of the sill while the upper central portion revealed coarser crystalline gabbroic facies, associated with anomalies in gamma ray, neutron porosity, sonic and geochemical log responses. From borehole image logs we interpreted key facies units including massive, fractured, cooling jointed and layered dolerite along with clear evidence for layers containing diverse inclusions interpreted as enclave structures. The integration and correlation of these data with analogue studies allowed the interpretation of gradational cooling with magmatic differentiation, partially melted host rock linked to sulphide production and organic matter maturation, mafic microgranular enclaves related to mingling processes of magma recharge, banding layers related to cumulate zones, and intense cooling fractures in the central sill body. An interval of ca. 44 m at the top of the sill with notably less jointing appears to be responsible for sealing the gas underneath, whilst the fractured central portion of the sill has enabled gas migration evidenced by increased gas signatures. In addition, this work also reveals for the first-time image log evidence for magma mingling and indications of assimilation and anatexis processes within the Parnaíba Basin. This study has important implications for improving the understanding of emplacement mechanisms of thick parallel layer intrusions and their implications for fluid flow in sedimentary basins worldwide.

Analytical approach for multivariate exploration planning via secondary migration modelling

Identifying potential petroleum traps in petroleum basins is one of the key challenges in petroleum exploration. Specifically, it is the identification of probable petroleum traps within a set of stratigraphic traps of a particular location of source rock and carrier bed. One solution lies in understanding the behaviour of hydrocarbon flow during secondary migration, and the evaluation of the probability of successful transport from the source rock to the trap. Modern reservoir simulators rely on numerical methods to model the oil/gas secondary migration. Using numerical simulators is, however, cumbersome and requires high volumes of data and computation time, which affects successful decision-making in exploration planning. Yet, analytical models are fast and allow for multivariant analysis of hydrocarbon secondary migration requiring only a moderate amount of geological data. This study presents the analytical modelling of hydrocarbon buoyant transport in petroleum basins by including the (i) areal variation of stringers’ cross-section, (ii) chemical reactions including oil biodegradation and (iii) hydrological water flow. The explicit formula is provided for the first and last moments of hydrocarbon arrival at the trap, describing the dynamics of filling of the trap. Field data from Australian and Chinese basins are used to investigate the effects of the above-mentioned parameters on the first and last moments of hydrocarbon arrival at the trap.

The potential extent of Early Triassic Kockatea Shale equivalent source rocks in the Northern Carnarvon and Perth Basins, Western Australia

In the northern Perth Basin (Western Australia), the Early Triassic Kockatea Shale is the primary petroleum source rock. Possible source rocks in the Northern Carnarvon Basin are more varied and include the Upper Jurassic Dingo Claystone as well as the Early Triassic Locker Shale. Biomarker analyses were conducted on petroleum samples from these basins to understand the nature of the petroleum systems. Many of the analysed petroleum samples contain carotenoids (okenane, chlorobactane and isorenieratane) derived from photosynthetic sulfur bacteria, suggesting that their source rocks were deposited under conditions of photic zone euxinia (PZE) and/or derived from microbialites. In the northern Perth Basin, the major lithofacies contributing to the source rock are dark coloured mudstones deposited under PZE conditions and/or derived from microbialites. In the southern Perth Basin, the potential source rock is either Permian, Jurassic or Cretaceous in age as indicated by the low concentrations or absence of carotenoids and the Triassic biomarker n -C 33 alkylcyclohexane. There is also a possibility that the Lower Triassic Locker Shale is the source rock of petroleum in the Tubridgi field on the Peedamullah Shelf of the Northern Carnarvon Basin, based on the similarity of biomarkers to Perth Basin petroleum sourced from the Kockatea Shale. However, the possibility of charge from the Upper Jurassic Dingo Claystone cannot be entirely excluded. Supplementary material: biomarker dataset is available at https://doi.org/10.6084/m9.figshare.c.6452153

Integrated geophysical techniques applied for petroleum basins structural characterization in the central part of the Western Desert, Egypt

Abstract The study area is situated in the central part of the Western Desert of Egypt between latitude 28°00′ to 30°00′ N and longitude 25°00′ to 30°00′ E. That region is distinguished by a featureless plain that is divided by depressions in Siwa, Qattara, and Bahariya. The purpose of the current study is to study the predominant structures in the area and how they relate to basin structure. Utilizing aerogravity data (Bouguer gravity, residual gravity, downward continuation, and Euler deconvolution) and aeromagnetic data (reduced to the northern Pole [RTP] anomalies and tilt derivative) is essential to accomplish this purpose. Through both qualitative analyses, these data were submitted to various processing and interpretation approaches. The subsurface structure configuration trending in E–W, N–S, NW–SE, NE–SW, ENE–WSW, and NNE–SSW directions has been simulated by utilizing aerogravity and aeromagnetic data. According to these maps, the study area is divided by around 44 faults. The study's findings indicated that the direction of the basement structure was almost NE–SW and N–S. The optimum Euler depth deconvolution at structure index, SI = 0 shows several features in the study area, including Sill, Dyke, Ribbon, and Step structures.

Integrated gravity and magnetic study on patterns of petroleum basin occurrence in the China seas and adjacent areas

Integrated gravity and magnetic study on patterns of petroleum basin occurrence in the China seas and adjacent areas

Microfacies and Reservoir Space Characteristics of Carbonate Reservoir of the Ordovician Yingshan Formation in Northern Slope of Tazhong Uplift, Tarim Basin

As an important stratum of exploration in the Tarim Basin, which is the largest petroleum basin in China, Yingshan Formation has great potential. The relationship between the fine division of microfacies and reservoir space characteristics has not been systematically studied which restricts further exploration. On the basis of the analysis of core, thin section, logging data, imaging logging data (FMI), and field outcrop, the microfacies types and reservoir space characteristics of the Ordovician Yingshan Formation are systemically studied. The results show that (1) nine microfacies (Mf1-Mf9) and four microfacies associations (MA1-MA4) were identified within the Ordovician Yingshan Formation. MA1-MA2 represent a medium- to high-energy sedimentary background, and MA3-MA4 represent a medium- to low-energy sedimentary background. (2) Four reservoir space types were observed in the Yingshan Formation, which are dominated by fracture-dissolution pore type, followed by small dissolution vug type, seldom fracture type, and large-scale karst-cavity type. (3) High-energy microfacies are the material basis of favorable reservoirs. The high-energy microfacies associations are prone to small dissolution vug and fracture-dissolution pore types of reservoirs; large cave reservoirs can sometimes be developed in the high part of the sequence and form favorable reservoirs in the Yingshan Formation. The low-energy microfacies associations mostly appear as original strata or interlayer, but after the superposition of structural cracks, buried karsts, or epigenetic karsts, low-energy microfacies associations may form relatively small-scale fractured and fracture-dissolution pore types of reservoirs in this area.

Migration and Release Mechanism of Methane Microseepage Based on Dawanqi Field Work and Physical Simulations

Methane (CH4) microseepage from petroleum basins is a significant contributor to the atmospheric CH4 budget. However, research about CH4 migration and release mechanism is still very limited. This work seeks to theorize and verify the migration and release mechanism of CH4 microseepage via field measurement and physical simulation, which, to the best of our knowledge, has not been reported in literature. Fluxes of CH4 microseepage from Dawanqi oilfield were measured, and three manifestations of release were observed, namely, continuous, flat, and episodic. Based on field observations, bench-scale physical simulation of CH4 migration through geological features of the oilfield was further conducted for 290 days. The results show that CH4 migration is mainly driven by buoyancy and diffusion. In continuous release, CH4 migration is mainly driven by buoyancy. In flat release, CH4 migration is dominated by diffusion. At low pressure, CH4 migrates upward slowly. As buoyancy increases, CH4 eventually break through the capillary pressure of the pore throat, causing spikes in CH4 concentrations in the layers above and reproducing episodic release observed during field measurement. Via field observation and verification by physical simulation, this work theorizes the migration mechanism of CH4 microseepage and its correlation with release types observed and confirms that counterbalance of buoyancy force and capillary pressure plays a critical role in episodic release of CH4 from oilfield. The findings of this study shed light on the migration mechanism and release manifestations of CH4 microseepage under different geological conditions and improve accuracy of estimating the flux of CH4 microseepage into atmosphere.

Evaluating uncertainty in empirically derived unconfined compressive strength (UCS) estimates and implications for drilling applications; a case study from the Cooper Basin

Accurate estimates of Unconfined Compressive Strength (UCS) are essential for a range of subsurface applications, including drilling wells for subsurface fluid extraction or injection. However, measuring UCS of subsurface rock samples through laboratory-based uniaxial and triaxial testing is time consuming, expensive, and potentially subject to individual sample variance. P-wave velocity logs are routinely obtained in petroleum basins and are commonly used to estimate UCS using empirically-derived correlations. In this study we analysed P-wave velocity data from 43 wells in the Cooper Basin, Australia and created mean ranges of expected UCS through the Tirrawarra, Toolachee, Patchawarra, Murteree Shale and Epsilon formations, using literature-derived P-wave velocity-UCS correlations, and also estimated UCS based on selected available laboratory-determined P-wave velocity measurements. These two suites of P-wave velocity-derived estimates of UCS are then compared to available results from laboratory uniaxial testing of core samples. Our analysis indicates that P-wave velocities, and subsequent derived estimates of UCS from P-wave wireline logs, are typically lower than those from laboratory-analysed samples. This may reflect a sampling bias towards the selection of strong rocks for laboratory UCS testing or lower estimates of UCS due to wellbore damage and pore space content (air or liquids) from P-wave log derived velocities. However, the laboratory-derived P-wave velocities generally agree with laboratory-derived UCS data from the Patchawarra, Murteree Shale and Epsilon formations when using published empirical velocity-strength correlations. A retrospective case study presents the impacts of different UCS estimates on mud weight required to produce observed borehole breakouts in the Epsilon Formation. Breakouts were observed 90 degrees to the orientation of SHmax (117° N) with a mean width of 51°, the breakouts were produced during drilling using a 9.7 ppg mud weight. The back-calculated estimate of UCS from the observed breakout widths at 9.7 ppg is 154 MPa. This sits between the UCS estimate of 171 MPa from uniaxial testing and 145 MPa from the mean of laboratory sample-derived P-wave velocities. Estimates of UCS from empirical correlations based solely on p-wave log-derived are far lower and vary between 87.3 and 114.4 MPa.

Assessment of Reservoir Quality of the Cretaceous Yolde Sandstone: A Case Study of Doma Stream, Gongola Basin, Northern Benue Trough, Northeast Nigeria.

Sedimentology, petrography and petrophysical studies were applied to the Cretaceous Yolde Formation sediments along the Doma stream, to evaluate its reservoir quality. The Yolde Formation along the Doma Stream is composed of lithologies that are laterally extensive and have reached a thickness of about 80m. They are lithologically made of sandstones with dark grey mudstones, laminated shales and grey to pale yellow limestones. The Sandstones are structurally characterized by planar, tabular and trough cross-beds, convolute beds, and hummocky cross-stratifications with reactivation surfaces. Some of the sediments are bioturbated. The petrophysical evaluation indicated porosity values ranging from 6% to 26%, and permeability values between 12.7mD and 108mD. These values are comparable to the reservoir rocks of proven petroleum basins of the North Sea and Niger Delta. Therefore, the Yolde Sandstones of the study area can have great potential to serve as good reservoir rock in the Gongola Basin.

Stratigraphic Drilling in the Northern Kara Sea: First Case and Preliminary Results

Abstract —Until recently, the sedimentary cover age and composition of the marginal North Kara Basin (northern part of the Kara Sea, Russian Arctic) remained uncertain because of the absence of direct data from parametric and exploration wells. Taking into consideration the absolute importance of these issues for understanding the regional geology of the Arctic shelf and evaluating its petroleum potential, Rosneft Oil Company, together with AO RosGeo, drilled ten shallow stratigraphic wells in fall 2020 using the research vessel (RV) Bavenit to reveal the complete stratigraphic range of the North Kara Basin. The ultrahigh-resolution (UHR) seismic survey was carried out by the RV Kapitan Voronin to adjust the well site locations and integrate the well sections into the regional geological model based on 2D seismic data during the drilling campaign. As a result, 300 m core was recovered from 11 Paleozoic and two Mesozoic stratigraphic units, previously investigated by 2D seismic and outcrop studies of the Severnaya Zemlya Archipelago. Lab analyses (biostratigraphy, lithology, sedimentology, geochemistry, and other types of core analysis) were performed at Lomonosov Moscow State University. We present obtained lab results confirming that the main part of the North Kara Basin section belongs to the Paleozoic; late Cambrian–Late Devonian rock ages have been derived. Several Paleozoic units tend to be older than those in previously published models. Core samples include mainly terrigenous rocks with insignificant carbonate presence. Paleozoic units are overlain by a thin Mesozoic terrigenous section dated from Middle Triassic to Middle Jurassic above a distinct angular unconformity. After a thorough analysis of all the lab results, we will obtain data on the ages of sedimentary units, as well as their lithology and depositional environments, and establish elements of the hydrocarbon system (source rocks, reservoirs, and seals) to evaluate the North Kara Basin petroleum potential with lesser uncertainty. We suppose that our results will significantly contribute to establishing a stratigraphic framework, reconstructing the basin history, and evaluating the petroleum potential of the whole Arctic region.

The role of Triassic source rocks in the formation of oil accumulation in the Fukang Depression (China)

This article presents the results of geological and geochemical studies of the organic matter of source rocks and oil from reservoirs in the Karamay Formation (Anizian–Ladinian stages) in the eastern part of the Fukang Depression in Junggar petroleum basin. The quantity, quality, and degree of maturity of the organic matter in clayey mudstones in upper part of the Karamay Formation (T2k) were considered and the composition of the original organic matter, the conditions of its accumulation and the degree of maturity were reconstructed using pyrolytic parameters and biomarkers. The dark gray and gray mudstone in upper part of the Karamay Formation accumulated in fresh or low salinity lakes with relatively reducing conditions. At present, the organic matter of the Formation within the depression is in the zone of mesocatagenesis MK1–MK3, and therefore has not fully realized its oil-geological potential. It has been previously established that mudstones in upper part of the Karamay Formation provided the hydrocarbon fl uids for the Karamay reservoirs located in the submerged part of the Fukang Depression.