Search Results (71)

The Kekeya oilfield is located at the southwestern edge of the Tarim Basin, in the southern margin of the Yecheng depression, at the western end of the second structural belt of the northern foothills of the Kunlun Mountains. It is one of the important oil and gas fields in western China, with significant oil and gas resource potential in the X4-X5 section of the Xihepu Formation. This study focuses on the edge of the alluvial fan depositional system, employing various techniques, including core data and well logging data, to precisely characterize the sand body architecture and comprehensively analyze the reservoir architecture in the study area. First, the regional geological background of the area is analyzed, clarifying the sedimentary environment and evolutionary process of the Xihepu Formation. Based on the sedimentary environment and microfacies classification, the sedimentary features of the region are revealed. On this basis, using reservoir architecture element analysis, the interfaces of the reservoir architecture are finely subdivided. The spatial distribution characteristics of the planar architecture are discussed, and the spatial distribution and internal architecture of individual sand body units are analyzed. The study focuses on the spatial combination of microfacies units along the profile and their internal distribution patterns. Additionally, a quantitative analysis of the sizes of various types of sand bodies is conducted, constructing the sedimentary model for the region and revealing the control mechanisms of different sedimentary architectures on reservoir properties and oil and gas accumulation patterns. This study pioneers a quantitative model for alluvial fan fringe in gentle-slope basins, featuring the following: (1) lobe width-thickness ratios (avg. 128), (2) four base-level-sensitive boundary markers, and (3) a retrogradational stacking mechanism. The findings directly inform reservoir development in analogous arid-climate systems. This research not only provides a scientific basis for the exploration and development of the Kekeya oilfield but also serves as an important reference for reservoir architecture studies in similar geological contexts. Full article

The massive heavy oil reserves in the Athabasca region of northern Alberta depend on steam-assisted gravity drainage (SAGD) for their economic exploitation. Even though SAGD has been successful in highly viscous oil recovery, it is still a costly technology because of the large energy input requirement. Large water and natural gas quantities needed for steam generation imply sizable greenhouse gas (GHG) emissions and extensive post-production water treatment. Several methods to make SAGD more energy-efficient and environmentally sustainable have been attempted. Their main goal is to reduce steam consumption whilst maintaining favourable oil production rates and ultimate oil recovery. Oil saturation within the steam chamber plays a critical role in determining both the economic viability and resource efficiency of SAGD operations. However, accurately quantifying the residual oil saturation left behind by SAGD remains a challenge. In this experimental research, sand pack Expanding Solvent SAGD (ES-SAGD) coinjection experiments are reported in which Pentane -C₅H₁₂, and Hexane -C₆H₁₄ were utilised as an additive to steam to produce Long Lake bitumen. Each solvent is assessed at three different constant concentrations through time using experiments simulating SAGD to quantify their impact. The benefits of single-component solvent coinjection gradually diminish as the SAGD process approaches its later stages. ES-SAGD pentane coinjection offers a smaller improvement in recovery factor (RF) (4% approx.) compared to hexane (8% approx.). Between these two single-component solvents, 15 vol% hexane offered the fastest recovery. The obtained data in this research provided compelling evidence that the coinjection of solvent under carefully controlled operating conditions, reduced overall steam requirement, energy consumption, and residual oil saturation allowing proper adjustment of oil and water relative permeability curve endpoints for field pilot reservoir simulations. Full article

The analysis of sand distribution in a marine–continental rift basin is of practical value for hydrocarbon prediction. The primary objective of this study is to investigate the correlation between Paleoproterozoic sand development and paleomorphology in the Nanpu sag, and to focus on identifying the key factors controlling sand deposition in the marine–continental rift basin. Correspondence between the development of the Paleoproterozoic sand in the Nanpu sag and the paleogeomorphology shows that the gully limited the deposition of the sand into the lake. The differentiation and aggregation of the sand in the lake basin were influenced by two kinds of slope break zones (the syn-sedimentary fracture tectonic slope break zone and the paleo-topographic flexural depositional slope break zone). Due to tectonic movements in the marine–continental rift basin, as well as provenance supply and weather during chasmic stages, the impact of valley and syndeposit slope break zone on sand development varies. In areas where allocation is better as valley–syndeposit slope break zone, basal slope and its vicinity usually are favorable for delta (braided channel) and fan delta sand development, which extend basinward through hydraulic transport. Meanwhile, under the influence of syntectonic and gravitational disequilibrium, gravity flow sand can be seen sporadically distributed in the deep end of fan fronts. This study is of great significance for oil and gas exploration in the Bohai Bay Basin region and contributes to a better understanding of depositional processes in similar marine–continental rift basins around the globe. Full article

Water-capped tailings technology (WCTT) is a strategy where oil sand tailings are sequestered within a mined-out pit and overlayed with a layer of water in order to sequester tailings with the aim that the resulting pit lake will support aquatic plants and organisms over time. The Base Mine Lake Demonstration (BML) is the first full-scale demonstration of a pit lake in the Athabasca Oil Sands Region (AOSR). In the BML, the release of methane from the fluid tailings influences several key processes, including the flux of greenhouse gases, microbial oxygen consumption in the water column, and ebullition-facilitated transport of organics from the fluid tailings to the lake surface. It is hypothesized that the residual low molecular weight hydrocarbons (LMWHCs) derived from diluent naphtha used during bitumen extraction processes are the carbon sources fueling ongoing microbial methanogenesis within the BML. The aims of this study were to identify the LMWHCs in the BML fluid tailings, to elucidate their sources, and to assess the extent of biogeochemical cycling affecting them. A headspace GC/MS analysis identified 84, 44, and 56 LMWHCs (C4–C10) present in naphtha, unprocessed bitumen ore, and fluid tailings, respectively. Equilibrium mass balance assessment indicated that the vast majority (>95%) of LMWHCs were absorbed within residual bitumen rather than dissolving into tailings pore water. Such absorbed compounds would not be readily available to in situ microbial communities but would represent a long-term source for methanogenesis. Chromatographic analysis revealed that most biodegradable compounds (n-alkanes and BTEX) were present in the naphtha but not in fluid tailings or bitumen ore, implying they are sourced from the naphtha and have been preferentially biodegraded after being deposited. Among the LMWHCs observed in bitumen ore, naphtha, and fluid tailings, C2-cyclohexanes had the highest relative abundance in tailings samples, implying their relatively high recalcitrance to in situ biodegradation. Full article

Altered body condition and diminished growth in wildlife in the Alberta Oil Sands Region (AOSR) are prompting investigations into the impact of oil sands industrial activity on wildlife in the region. Chemical constituents from bitumen-influenced waters, including oil sands process-affected water (OSPW), can disrupt endocrine signaling, leading to aberrant lipid accumulation and altered glycemic control in mammals. This study aimed to investigate the effects of naphthenic acid fraction components (NAFCs), derived from OSPW, on energy homeostasis using the McA-RH7777 rat hepatocyte model. Cells were exposed to NAFCs at nominal concentrations of 0, 0.73, 14.7, and 73.4 mg/L for 24 and 48 h. We assessed gene expression related to lipid and glucose metabolism and measured triglyceride accumulation, glucose, and fatty acid uptake. NAFC exposure (14.7 and 73.4 mg/L) reduced triglyceride levels and glucose uptake and increased fatty acid uptake and the expression of beta-oxidation genes, suggesting a metabolic switch from glucose to fatty acid oxidation. This switch in substrate availability signifies a shift in cellular energy dynamics, potentially linked to altered mitochondrial function. To investigate this, we conducted adenosine triphosphate (ATP), mitochondrial membrane potential, and terminal deoxynucleotidyl transferase dUTP nick-end labeling (TUNEL) assays to measure cellular ATP levels, mitochondrial membrane potential, and apoptosis, respectively. At both time points, 73.4 mg/L NAFC exposure resulted in increased ATP levels, induced mitochondrial membrane hyperpolarization, and increased apoptosis. These results suggest that mitochondrial efficiency is compromised, necessitating metabolic adaptations to maintain energy homeostasis. Given that cells exhibit metabolic flexibility that allows them to dynamically respond to changes in substrate availability, we further demonstrated that the kynurenine–tryptophan ratio (KTR) serves as a marker for a shift in energy metabolism under these stress conditions. This work provides a mechanistic framework for understanding how bitumen-derived organic contaminants may disrupt metabolic function in wildlife living in the AOSR. These findings further support the use of molecular markers like KTR to evaluate sub-lethal metabolic stress in environmental health monitoring. Full article

The fourth member of the Triassic in the Tahe Oilfield, as one of the key strata for clastic rock reservoirs, poses significant challenges to oil and gas exploration due to unclear identification of its depositional environments and sedimentary microfacies. Based on the guidance of sequence stratigraphy and sedimentological theories, this study comprehensively analyzed well logging data from more than 130 wells, core analysis from 9 coring wells (including lithology, sedimentary structures, and facies sequence characteristics), 3D seismic data (covering an area of 360 km²), and regional geological background. Combined with screening and settling method granularity experiments, the sedimentary characteristics of the sand body in the fourth member were systematically characterized. The results indicate the following: (1) In the Tahe Oilfield, the strata within the fourth member of the Triassic are predominantly characterized by marginal lacustrine subfacies deposits, with delta-front subfacies deposits developing in localized areas. (2) From the planar distribution perspective, influenced by the northwestern provenance, a small deltaic depositional system developed in the early stage of the fourth member in the northwestern part of the Triassic Akekule Formation. This system was dominated by subaqueous distributary channel sand bodies, which were subjected to erosion and reshaping by lake water, leading to the formation of several stable sand bars along the lake shoreline. In the later stage of the fourth member, as the lake level continued to recede, the area of deltaic deposition expanded westward, and deltaic deposits also developed in the central to slightly eastern parts of the study area. Based on this, a depositional model for the fourth member of the Triassic in the Tahe Oilfield has been established. (3) In the Tahe Oilfield, the sand bodies within the fourth member of the Triassic system gradually pinch out into mudstone, forming lithological pinch-out traps. Among these, the channel sand bodies and long belt sand ridges, due to their good sorting and high permeability, become favorable reservoirs for oil and gas accumulation. This study clarifies the sedimentary model of the fourth member and reveals the spatial differentiation mechanism of sand bodies under the control of lake-level fluctuations and ancient structures. It can provide exploration guidance for delta lake sedimentary systems similar to the edge of foreland basins, especially for efficient development of complex lithological oil and gas reservoirs controlled by multistage lake invasion–lake retreat cycles. Full article

Reservoir evaluation in multi-source systems is challenging because studies generally follow single-source principles. This limitation has substantially hindered the understanding of reservoir and hydrocarbon accumulation processes in source–reservoir systems. This study examines the Dingbian area of the Ordos Basin, China, and investigates the key factors controlling hydrocarbon accumulation in the Chang 9 reservoir of the Triassic Yanchang Formation within a multi-source system. The study area spans approximately 0.9 × 10⁴ km². First, by comparing the biological markers in Chang 9 crude oil with those of potential source rocks, the oil source of the Chang 9 reservoir was identified. The study area was subsequently divided into three provenance zones—northeast, northwest, and central mixed source areas—based on heavy mineral content and the orientation of sedimentary sand bodies. Additionally, well logging data, oil production data, petrographic thin sections, scanning electron microscopy (SEM), and mercury injection porosimetry were used to investigate the reservoir characteristics, oil reservoir features, and crude oil properties across different source areas. The results indicate that the oil source of the Chang 9 reservoir in the Dingbian area is the Upper Chang 7 source rock. The northwest source area exhibits superior reservoir properties compared to the other two zones. In the northwest source area, lithology-structure oil reservoirs are predominant, whereas the central mixed source area is characterized by structural-lithology oil reservoirs, and the northeast source area predominantly features lithology-controlled reservoirs. From the northwest to the central mixed source areas, and finally to the northeast source area, crude oil density and viscosity increase gradually, while the degree of oil–water separation decreases correspondingly. Based on these findings, the study concludes that the distribution of structures, lithology, and source rocks significantly influences the Chang 9 reservoirs in the Dingbian area. The controlling factors of oil reservoirs differ across the various source zones. In multi-source systems, evaluating oil reservoirs based on source zones provides more precise insights into the characteristics of reservoirs in each area. This approach provides more accurate guidance for exploration and development in multi-source regions, as well as for subsequent “reserve enhancement and production increase” strategies. Full article

Shallow-water deltas are not only a hot spot for sedimentological research but also a key target for oil and gas exploration. In this paper, taking the third member (E₁f₃) of the Funing Formation in the Upper Jurassic as an example, based on observations made from core samples, well logging, cathode luminescence characteristics, and analytical assays, the development conditions, sedimentary characteristics, and sedimentary models of shallow-water deltas are summarized. These shallow-water deltas were deposited in conditions with the following characteristics: a gentle terrain platform, a subtropical climate with ample rainfall, an abundant source supply, strong hydrodynamic forces, shallow water bodies, and a frequently eustatic lake level. Shallow-water deltas are characterized by sediment deposition from traction currents, numerous underwater distributary channel scour structures, overlapping scouring structures, sand body distribution with planar features, underwater distributary channels as skeletal sand bodies, and undeveloped mouth bars. Based on these, it is believed that during the deposition period of E₁f₃, the Gaoyou Sag in the Subei Basin had favorable geological conditions for the development of shallow-water delta deposition. The shallow-water delta deposition that occurred during the sedimentary periods of the five major sand units in the Funing Formation is characterized by front subfacies, with underwater distributary channels as the framework for sand bodies, and multiple intermittent positive rhythms overlapping vertically with the Jianhu Uplift as the source of material supply. In this paper, a depositional model for shallow-water delta deposition during the E₁f₃ deposition period in the Gaoyou Sag is established, expanding the scope of oil reservoir exploration in the north slope region of the Gaoyou Sag and providing important geological evidence for the selection of favorable subtle zones. Full article

The Pearl River Mouth Basin (PRMB) had two potential provenances (intrabasinal and extrabasinal) during the Paleogene Enping Formation period. However, the understanding of their differences in source supply and evolution over time and space is limited due to the regional restriction in borehole coverage. This study aims to address the knowledge gap by utilizing detrital zircon U-Pb dating data, seismic data, and borehole data. Specifically, this study focuses on examining the characteristics of provenance evolution and sedimentary infilling within the Enping Formation in various sags of the northern PRMB. The results indicate temporal and spatial variability in provenance from the lower Ep⁴ and Ep³ to the upper Ep² and Ep¹ Members. The influence of extrabasinal provenance from the South China Block (SCB) was prominent in the northern region of the Zhu I Depression during the deposition of Ep⁴ and Ep³ Members, while intrabasinal provenance from local uplifts remained a significant source for most sags. During this period, sediment transportation occurred over short distances, leading to the widespread development of smaller fan deltas and braided river deltas. In contrast, extrabasinal provenance became dominant during the deposition of Ep² and Ep¹ Members throughout the entire Zhu I Depression. This shift promoted the development of large-scale, shallow, braided river deltas with sediment transported over long distances. The analysis reveals a close correspondence between the shifting provenance and the evolution of sedimentary infilling patterns in the PRMB. As a result, the sags transitioned from being under-filled or balanced-filled to being balanced-filled or over-filled. This study holds immense significance for oil and gas exploration as well as the prediction of favorable sedimentary sand bodies in offshore petroliferous basins. Full article

Bitumen extraction using Steam-Assisted Gravity Drainage (SAGD) in northern Alberta oilsands has been crucial for recovery; however, the thermal effects on formation damage still require significant attention. This thermal recovery method causes substantial changes in temperature and pressure, which are critical thermodynamic factors in the rock-fluid system of a reservoir. Those changes, both directly and indirectly, impact the flow of oil and water within the porous medium, changing fluid properties and physicochemical interactions that affect rock and fluid behaviour. Coreflooding experiments confirm the accumulation of in situ migratory particles within the pore spaces can lead to pore throat plugging and fines accumulation on the sand control screen. This disturbance within the near-wellbore region triggers permeability reduction and, subsequently, skin buildup. At the same time, changes in pressure drop may trigger the precipitation of organic and inorganic scaling and, finally, wettability alterations. This paper combines field observations and experimental tests to assess the formation damage mechanisms. While the literature has identified factors influencing the formation damage mechanisms, the interaction between these mechanisms, as well as the interplay between the wellbore completion and the surrounding sand from the perspective of formation damage, has not been thoroughly investigated. Current laboratory tests do not adequately account for the effects of high pressure and high temperature on formation damage mechanisms and their interaction in the near-wellbore region. Following the introduction of current experimental and theoretical methods related to formation damage mechanisms around SAGD wellbores, this paper introduces a comprehensive and integrated methodology for designing, testing, and evaluating formation damage mechanisms in SAGD producer wells, addressing the gaps identified in this review. This approach aims to bridge identified gaps from the literature review, advance formation damage assessment, and support the reduction of induced formation damage in thermal recovery operations. Full article

Wetlands globally have and continue to undergo modification from anthropogenic and natural environmental factors. To bridge this gap, this study utilised a GIS-based approach to quantify the areal extent of human footprint disturbances to wetlands over time. This approach attributed wetland disturbance by wetlands class, disturbance type and sector during two notable disturbance transitions, from 2000 to 2010 and from 2010 to 2018, in the oil sands region (OSR) of northern Alberta, Canada. The wetland disturbance area was calculated using a physical disturbance dataset intersected with the Alberta Merged Wetland Inventory. Results indicate that 3284 km² (2616 km² between 2000 and 2010, 668 km² between 2010 and 2018) of wetlands have undergone disturbance in the OSR. Examination of disturbance by the industrial sector between 2010 and 2018 indicates that the oil and gas and forestry sectors are the greatest sources of disturbance (402 km² and 179 km², respectively). Monetary assessment of wetland ecosystem services per year results in a minimum yearly loss of USD 30.05 million for peatlands and USD 197.86 million for marshes and swamps in USD (2007). This analysis is valuable for quantifying the impact of human footprint on wetlands, which is critical for ensuring sustainable development in wetland-rich areas. Full article

Strategic breakthroughs have been made in the exploration and evaluation of Gulong shale oil in the Songliao Basin. However, the Heiyupao Depression, located near the Gulong Depression, hosts a thick section of the Qingshankou Formation shale that has not been extensively studied. This paper presents novel insights into the lithofacies characteristics, depositional environment, and reservoir features of the Qingshankou Formation shale in the Heiyupao Depression, with a specific focus on the origin and maturation of organic-rich shale. Four core wells were drilled, and 152 core samples were analyzed through a variety of techniques, including rock type classification, mineral composition, TOC content, rare earth elements, rock pyrolysis, organic matter type determination, and CT scanning. Results indicate that the Qingshankou shale is dominated by felsic compositions and Type I kerogen, with organic maturity varying across the section. Based on lithology, sedimentary structures, mineralogy, and organic matter abundance, five distinct lithofacies are identified: high-organic mud-rich felsic shale, high-organic sand-rich felsic shale, medium-organic sand-rich felsic shale, medium-organic massive shale, and low-organic sand-rich felsic shale. Notably, the Type A lithofacies (high-organic mud-rich felsic shale) is identified as a primary source rock due to its intergranular and organic matter pores, albeit with low porosity and poor connectivity. In contrast, the Type E lithofacies (low-organic sand-rich felsic shale) have high porosity, well-developed micro- and nano-scale pores, and strong connectivity, marking them as the primary reservoirs. The characteristics of this region differ significantly from those of Gulong shale oil, requiring different extraction strategies. The mineral composition of such shale is predominantly felsic rather than mixed. The findings not only provide theoretical support for the exploration of complex lacustrine shale in the Songliao Basin but also offer valuable insights for the resource development of similar non-marine shale systems worldwide. Full article

Enhanced oil recovery (EOR) techniques, such as water flooding, often face significant challenges in heterogeneous reservoirs, mainly due to permeability variations that hinder effective oil displacement. This study investigated the impact of pulsating water flooding on oil recovery in reservoirs with vertical heterogeneity, focusing on interlayer and inlayer permeability variations. Laboratory experiments were conducted using cylindrical sand pack models with varying permeability to compare steady-state and pulsating water injection methods. The results demonstrated that pulsating water flooding significantly improved vertical sweep efficiency (VSE) and overall oil recovery, particularly in low-permeability zones. Pulsations helped mobilize trapped oil and redistributed injected water more evenly, mitigating the adverse effects of early water breakthrough and enhancing sweep efficiency. For interlayer heterogeneity, pulsating water injection increased total recovery by 23.2%, 8.9%, and 6.6% for core groups with permeability contrasts of 307.9 × 10⁻³ μm², 193.9 × 10⁻³ μm², and 73.25 × 10⁻³ μm², respectively. For inlayer heterogeneity, recovery factors improved by 13.9%, 10.6%, and 3.1%, respectively. Core groups with higher permeability contrasts (i.e., larger differences between high and low permeability) experienced lower recovery under steady-state conditions, while pulsating injection mitigated these effects, resulting in higher recovery in more heterogeneous reservoirs than steady-state flooding. These findings suggest that pulsating water flooding is an effective and cost-efficient technique for enhancing oil recovery in heterogeneous reservoirs. It improves short-term and long-term recovery by increasing displacement efficiency, particularly in low-permeability regions, and effectively mitigates the challenges of permeability variations. As such, pulsating water flooding offers a significant improvement over steady-state flooding, providing valuable insights for EOR practices in complex reservoirs. Full article

Narrow Fluvial Sand Bodies are primarily developed along the river center, with horizontal wells for injection and production in some Bohai waterflooded oilfields. This results in a rapid increase in water cut due to a single injection–production direction. Over time, dominant water breakthrough channels form between wells, and the remaining oil moves to deeper regions, which makes conventional profile control measures less effective. We developed a quantitative method based on integrated dynamic and static big data to identify these breakthrough channels and measure the flow intensity between injection and production wells. To address deep remaining oil mobilization, we performed micro-analysis and physical simulations with heterogeneous core models, which led to the development of a deep profile control system using emulsion polymer gel and self-assembling particle flooding. Experiments show that the combined technology can reduce oil saturation in low-permeability layers to 45.3% and improve recovery by 30.2% compared to water flooding. Field trials proved to be completely effective, with a cumulative oil increase of over 23,200 cubic meters and a 12% reduction in water cut per well. This deep profile control technology offers significant water cut reduction and enhanced oil recovery. It can provide technical support for efficient water control and profile management in similar reservoirs. Full article

In order to accurately portray the oil and gas enrichment patterns near oil source faults in the “lower generation and upper storage” in petroliferous basins, we put forward a methodology for ascertaining the diversion period of hydrocarbon migration from fault to sand body, with the Nandagang Fault in the southern Qikou Sag in the Bohai Bay Basin serving as a case in point. The initial step was to couple the period of active faults with hydrocarbon supply to the accumulations inside and outside of the underlying source rock, with the objective of determining the hydrocarbon transport period of faults. Subsequently, the sand body’s oil and gas transport period was determined based on the time taken to form a seal in the overlying regional mudstone cap rock. Finally, the coupling period between the two was employed to ascertain the diversion period. The results indicate that the hydrocarbon transport period of the Nandagang Fault extends from the early to the late stages of the Neogene Minghuazhen Formation’s (Nm) deposition. The sand body’s oil and gas transport period spans from the end of the Paleogene Shahejie Formation’s (Es) deposition to the present day. The hydrocarbon diversion migration from the Nandagang Fault to the sand body occurred from the early to the end of the deposition period of the Nm Formation. This relatively long diversion period is conducive to hydrocarbon transport, which coincides with the magnitude and extent of actual hydrocarbon enrichment. This study contributes to effectively guiding oil and gas exploration in the vicinity of faults. Full article