Reservoir Formation Research Articles

Depositional environments as a framework for genetic classification of the basic criteria of petroleum potential

Most classifications of reservoirs, seals and source rocks based on the ability of the rock to generate, accumulate and preserve hydrocarbons, and the genesis of rocks is not always taken into account. The article presents a ranking scheme for continental, coastal-marine and marine sedimentation environments that determine the genesis and properties of the basic criteria of petroleum potential – source rocks, reservoirs, seals and pinch-out traps. Rocks, which can consider as source rock, reservoirs and seals are formed in each depositional environment. However, their structure, mineral composition and distribution area will differ from each other depending on the sedimentary environment and conditions. A combination of elements of the hydrocarbon system formed, corresponding to the sedimentation environment and are characteristic for basins of various types. Continental environments are favorable for the formation of reservoirs and local seals, while the accumulation of source rocks limited by lacustrine, floodplain, and swamp facies. The coastal-marine environment is favorable for the formation of all the basic criteria of petroleum potential, and the transgressive-regressive cyclicity determines the interbedding of source rocks, reservoirs and seals in the section. The marine depositional environments are most favorable for the formation of regional seals and source rocks, including high-carbon formations. The proposed ranking scheme of sedimentary environments and the basic criteria of petroleum potential genetically related to them is applicable in system analysis and selection for analogues of petroleum system elements in sedimentary complexes formed in similar depositional environments.

Geological Modeling of Sandstone Formations and Petrophysical Characterization of Hydrocarbon Reservoirs in the Termit Basin, Eastern Niger: Case of the Goumeri Prospect

This study focuses on the geological model of sandstone formations and the petrophysical characterization of hydrocarbon reservoirs in the Termit Basin. The specific objectives are: (1) to establish a geological model visualizing the geometry of reservoir rocks and (2) to visualize the spatial and vertical distribution of the petrophysical parameters (porosity, permeability). The methodological approach integrated the interpretation of lithology data and petrographic parameters from the logs by using Petrel software 17.4 versions. The interpretation of the obtained results shows that: the reservoir formations present in the shape of sand lenses whose thickness varies according to another prospect. The petrophysical parameter models including the porosity and permeability model were used to understand the vertical and spatial distribution of the different reservoir units.

Control of faults and fractures on shale oil enrichment

The Qingshankou Formation is the primary shale oil exploration and development target in the Songliao Basin, but controlling factors of shale oil enrichment, especially the role of faults and fractures, are still poorly understood. We identify fault geometry in the Qingshankou Formation based on seismic interpretation. We characterize natural fractures with outcrop and core observations, and thin-sections petrography. By integrating faults and fracture observations at various scales, tectonic history of the basin, and burial history of the studied reservoir formation, we explain the control of faults and fractures on shale oil enrichment. Results show that high-density fault systems, namely “T11″ and “T2″ fault systems, were developed at the top and bottom of Qingshankou Formation in the north of Songliao Basin. Both fault systems is characterized as a group of high-density, closely spaced small faults forming a fault belt, with evident multi-stage activities. Nature fracture categories identified including folding and faulting related fractures, bed-parallel fractures and overpressure fractures, while the former two are better developed. Tectonic movements have caused the structural uplift and subsidence to take place at different times in different parts of the basin. The structural uplift happened late in the study area, consequently the source rocks have gone through a long burial history and are well matured, which favors shale oil enrichment. Tectonic uplifts generated large numbers of fractures locally, effectively increase oil production by improving the migration pathways and storage space of shale oil. Fault systems of different scale also provided two-way channels for oil migration in Qingshankou Formation. Large-scale faults that cut through the full shale column allow the shale oil to migrate to the conventional reservoirs above and below the Qingshankou Formation. The smaller faults in the high-density fault belt within the Qingshankou Formation (Qing-1 Member) enhanced seepage capacity and connectivity of the shale reservoir. As a result, shale oil and conventional oil development in the study area can collaborate with one another. High-density, well connected natural fractures also played an important role by providing storage space and fluid flow conduit which is essential in shale oil reservoirs. However, these fractures along faults may migrate oil from shale reservoirs to neighboring conventional reservoirs.

Genetic relationships of solar system bodies based on their nucleosynthetic Ti isotope compositions and sub-structures of the solar protoplanetary disk

Nucleosynthetic isotope variations are powerful tools to investigate genetic relationships between meteorite groups and planets. They are instrumental to assess the early evolution of the solar system, including mixing and reservoir formation in the protoplanetary disk, as well as planet formation. To address these questions, we report high-precision nucleosynthetic Ti isotope compositions of a wide range of bulk meteorites, partially complemented with new Cr isotope data. New Ti isotope data confirm the first order dichotomy observed between carbonaceous chondrites (CC), representing outer solar system compositions, and non-carbonaceous (NC) meteorites from the inner solar system. The data in combination with nucleosynthetic isotope data of other elements (e.g., Cr, Ca) indicate that isotopically heterogeneous reservoirs were also present as sub-reservoirs in the inner disk (NC reservoir), generating two or more clusters i.e., (i) the Vesta-like howardites-eucrites-diogenites (HEDs), mesosiderites, angrites, acapulcoites, lodranites, and brachinites and (ii) the Earth-Mars-like ordinary chondrites (OC), aubrites, enstatite chondrites (EC), winonaites, IAB silicates, rumuruti chondrites (R), Martian and terrestrial samples. These reservoirs likely represent disk substructures such as secondary gaps and ring-structures, created by spiral arms, which were emitted from the growing Jupiter and/or Saturn. The distinct isotopic compositions of these reservoirs may reflect thermal processing of material within the disk in combination with temporal isotopic variations either due to isotopically variable infalling material from a heterogeneous molecular cloud and/or thermal processing during the infall that induced such heterogeneities. Such effects were likely reinforced by thermal processing of the material within the disk itself and by physical size- and density sorting of dust caused by the giant planets, creating gaps and pressure bumps in the disk.Genetic relationships of meteorite groups and their implications on parent body formation are evaluated. New high precision Ti isotope data are consistent with that (i) CH and CB meteorites derive from a common parent body, which most likely accreted material from the same isotopic reservoir as the parent body of CR chondrites, (ii) silicates of IAB irons and winonaites originate from the same parent body, and (iii) mesosiderites and HED meteorites have a common origin on Vesta. The indistinguishable Ti and Cr isotope compositions of HEDs/mesosiderites to acapulcoites are not attributed to a common parent body, because of petrologic and chemical differences in addition to their distinct O isotope compositions. Their parent bodies likely accreted in the same disk region, which showed a higher level of O isotope heterogeneity compared to that of Ti, Cr and other refractory nucleosynthetic tracers. The similarity in Ti isotope compositions of Martian meteorites and OCs indicates that OC-like material belongs to the main building blocks of Mars.

The origin of heterogeneous sucrosic dolomite reservoir of the lower Permian Qixia Formation, NW Sichuan Basin, China

Sucrosic dolomite, an important hydrocarbon reservoir, has long been the focus of carbonate sedimentological and reservoir geological studies. This study investigated a kind of heterogeneous sucrosic dolomite in the Lower Permian Qixia Formation of NW Sichuan Basin, which has recently been the location of giant natural gas discoveries. The heterogeneous sucrosic dolomite is characterized by coexistence of porous euhedral dolomite and tight anhedral dolomite, and it is mainly distributed in the platform-marginal shoal facies with a quasi-layered structure. Further geochemical analysis, including C, O, and Sr isotopes as well as rare earth elements, reveals that the euhedral dolomite and anhedral dolomite have similar geochemical properties to the matrix limestone representing coeval seawater, and they were mainly generated from dolomitization by the closed marine-related fluid (left-leaning REE and δPr < 1) in the shallow burial. The difference in crystal morphology, porosity, and permeability between the euhedral dolomite and anhedral dolomite is mainly related to the compositional and textural heterogeneities of the host rocks. Due to the dissolution of meteoric water (relatively flat REE and low Y/Ho) in the early diagenetic stage caused by high frequent exposures, quasi-layered vugs and caves were formed in the grainstones. In the process of shallow burial dolomitization, the loose-filled carbonate sands formed the porous euhedral dolomite due to sufficient space, while the matrix limestone formed the tight anhedral dolomite due to relatively poor porosity and permeability. Accordingly, the paleogeomorphic highland controlled platform-marginal shoal superimposed by meteoric water dissolution in the early diagenetic stage is the main factor for the formation of Qixia Formation reservoirs, while dolomitization is mainly manifested as the inheritance and adjustment of pre-existing pores in the host rock. Therefore, the exploration direction for dolomite reservoirs in the Qixia Formation in the Sichuan Basin should be shifted to the favorable sedimentary facies-controlled reservoir model, which can also be referential for other cases under similar geological setting.

Estimation of Reservoir Porosity Using Seismic Post-Stack Inversion in Lower Indus Basin, Pakistan

Seismic post-stack inversion is one of the best techniques for effective reservoir characterization. This study intends to articulate the application of Model-Based Inversion (MBI) and Probabilistic Neural Networks (PNN) for the identification of reservoir properties i.e. porosity estimation. MBI technique is applied to observe the low impedance zone at the porous reservoir formation. PNN is a geostatistical technique that transforms the impedance volume into porosity volume. Inverted porosity is estimated to observe the spatial distribution of porosity in the Lower Goru sand reservoir beyond the well data control. The result of inverted porosity is compared with that of well-computed porosity. The estimated inverted porosity ranges from 13-13.5% which shows a correlation of 99.63% with the computed porosity of the Rehmat-02 well. The observed low impedance and high porosity cube at the targeted horizon suggest that it could be a probable potential sand channel. Furthermore, the results of seismic post-stack inversion and geostatistical analysis indicate a very good agreement with each other. Hence, the seismic post-stack inversion technique can effectively be applied to estimate the reservoir properties for further prospective zones identification, volumetric estimation and future exploration.

Seismic signatures of partial steam saturation in fractured geothermal reservoirs: Insights from poroelasticity

Detecting the presence of gaseous formation fluids, estimating the respective volumes, and characterizing their spatial distribution are important for a wide range of applications, notably for geothermal energy production. The ability to obtain such information from remote geophysical measurements constitutes a fundamental challenge, which needs to be overcome to address a wide range of problems, such as the estimation of the reservoir temperature and pressure conditions. With these motivations, we compute the body wave velocities of a fractured granitic geothermal reservoir formation with varying quantities of steam to analyze the seismic signatures in a partial saturation context. We use a poroelastic upscaling approach that accounts for mesoscale fluid pressure diffusion (FPD) effects induced by the seismic strain field, and, thus, describes the governing physical processes more accurately than standard representations. Changes in seismic velocities due to steam saturation are compared with changes associated with fracture density variations, as both are plausible results of pressure changes in geothermal reservoirs. We find that steam saturation has a significant impact on P-wave velocities while affecting S-wave velocities to a significantly lesser extent. This contrasting behavior allows us to discriminate between fracture density and steam saturation changes by means of P- and S-wave velocity ratio analyses. To evaluate the potential of seismic methods to provide this information, a canonical geothermal reservoir model is used to compute the Rayleigh wave velocity dispersion and seismic reflection amplitude variation with angle (AVA) curves. These studies reveal that AVA analyses allow differentiating changes in fracture density from changes in steam saturation. We also note that the Rayleigh-wave-based techniques are much less sensitive to steam content changes than to fracture density changes. Comparisons with elastic approaches indicate that including FPD effects through the use of a poroelastic model is crucial for the reliable detection and characterization of steam in fractured geothermal reservoirs.

Characteristics and controlling factors of petroliferous reservoirs in the Permian Lower Urho Formation, western Mahu Slope, Junggar Basin, Northwest China

Numerous hydrocarbon discoveries in the lower Urho Formation of the western Mahu Slope, China indicate that potential petroliferous reservoirs may exist in that region. However, issues concerning the reservoir characteristics and associated controlling factors remain unclear. To determine the characteristics and associated controlling factors of these reservoirs, we conducted integrated analysis of the 3D seismic volume, wireline logs, mud logs, cores, thin sections, porosity, and permeability data. Several lithologic types were identified from the core, casting thin section, and mud-log data (including mudstone, sandstone, gravity flow-derived glutenite, transitional glutenite, and traction flow-derived glutenite). The contact relationship was determined from the casting thin section data, and it included point contact and lineal contact, followed by concavo-convex contact and suture contact. We found the dominant pore types were found to be intergranular pores, followed by intragranular pores, intramatrix pores, and cracks. The porosity and permeability data reveal that sandstone and traction flow-derived glutenite commonly form low-porosity and low-permeability reservoirs, whereas transitional glutenite commonly forms low-porosity and ultralow-permeability reservoirs and gravity flow-derived glutenite generally forms low-porosity and ultralow-permeability reservoirs. This integrated analysis finds that tectonic movements and a sedimentary environment control the physical properties of the reservoirs. The tectonic movements control reservoir characteristics through thrust fault systems and large-scale provenance, and the sedimentary environment controls reservoir characteristics via facies distribution and lacustrine fluctuation. The insights gained from this study can provide knowledge about the characteristics and associated controlling factors of the reservoirs in the Permian Lower Urho Formation within the western Junggar Basin. These insights can also benefit petroleum reserve and hydrocarbon production exploration in the study area and further petroleum exploration in other areas with similar sedimentary/tectonic settings.

P-103 Three-dimensional oviductal organoid model to study spermatozoa-oviduct interaction in humans

Abstract Study question Is it possible to establish an in vitro model that recapitulating human oviduct to investigate sperm-oviduct interaction Summary answer Three-dimensional (3D) oviductal organoid model was established from either primary human oviductal tissues or immortalized human OE-E6/67 cell line, based on our protocol. What is known already The sperm reservoir in oviduct is formed to maintain the fertilizing capacity of spermatozoa until ovulation by the binding of sperm to the epithelial lining of the oviduct, which is also significant to select sperm with normal chromatin structure and superior fertilization ability. The regulation and mechanism of sperm reservoir formation in human is still unknown, mainly due to the ethical issue and technical difficulty in obtaining enough human oviduct. We previously demonstrated that sperm fucosyltransferase-5 (sFUT5), a carbohydrate-binding protein on spermatozoa, is responsible for spermatozoa-oviduct interaction in humans. Study design, size, duration Human oviductal epithelial cell line immortalized by HPV 16 E6/E7 open reading frame by retroviral expression system was employed to establish the co-culture model. Fresh human samples (human spermatozoa,N = 30; 1-2 cm primary oviductal tissue,N = 15) were collected in hospital with signed consent. Fluorescent pre-labelled sperm were co-cultured with organoids for 2 hours. At least three replicates were conducted for each assay. Participants/materials, setting, methods Morphological characterization and markers expressions of the organoid were determined by immunohistochemistry and confocal microscopy analysis. The sperm binding capacity of the oviductal organoid was studied by co-culture system. Sperm chromatin structure of the organoid-bound sperm was assessed by flow cytometry-based TUNEL assay. Affinity chromatography followed by nano-liquid chromatography–mass spectrometry was used to identify the sFUT5-binding proteins on ovidutal epithelial cells (OECs) and their expressions on OECs were validated by immunostaining/flow cytometry. Main results and the role of chance The organoid exhibited a hollow structure surrounded by a single layer of OECs. Immunohistochemistry analysis revealed the high expressions of epithelial marker E-cadherin (basolateral membrane), secretory marker pair-box 8 (PAX8) and proliferative marker Ki67. Expression of ciliated cell marker, acetylated tubulin (AcTUB) can also be detected. The modification of culture environment successfully reversed the OEC organoids polarity as demonstrated by immunostaining using antibodies against ZO-1 (apical marker) and E-cadherin (basolateral marker), making the organoid accessible during the co-culture. These apical-out OEC organoids have significantly higher sperm binding capacities than their basal-out counterparts. Furthermore, OEC organoid-bound spermatozoa possessed more intact DNA than the unbound spermatozoa. The results indicate the relevance of using OEC organoid-spermatozoa co-culture model as a tool to assess spermatozoa-oviduct interaction in humans. By using immuno-affinity chromatography and mass spectrometry analysis, cell adhesion molecule 4 (CADM4) was then identified as a potential sFUT5-interacting protein on OECs. This result was further supported by flow cytometry and immunofluorescent staining. 3-D oviductal organoid model demonstrates profound potential for in vitro investigation of human oviduct physiology. Limitations, reasons for caution Our 3D model may not fully represent the entire cellular complexity and tubular architecture of the oviductal epithelium. Further investigation on the sperm morphology and DNA integrity and analysis on organoid transcriptome will enhance our understanding on oviduct in human reproduction. Wider implications of the findings The results from co-culture may give a clue to future study on whether oviductal organoid can be applied clinically for functional sperm selection in in vitro fertilization. Our apical-out organoid model may also be applied to study tubal ectopic pregnency. Trial registration number not applicable

Autonomous Inflow Control Valve for Medium-Light Oil and Its Effective Performance

Summary Many horizontal oil wells will after a time start producing unwanted fluids. Autonomous inflow control valves may help to choke these unwanted fluids and consequently improve carbon efficiency. This paper publishes new experimental data describing how an autonomous inflow control valve manages medium-light oil (6 cp), water, and gas at reservoir conditions. A further objective is to evaluate how this valve might impact well performance under various conditions. To verify the single- and multiphase flow behavior of the valve, extensive flow loop experiments were performed. Initial testing was done in a model fluid laboratory, while a more extensive test was performed at reservoir conditions (i.e., with formation water, reservoir oil, and hydrocarbon gas at the given reservoir temperature and pressure). To explore and understand the impact of this valve for various reservoir scenarios, a simple conceptual reservoir model with realistic boundary conditions was used. At various differential pressures, the single-phase oil, water, and gas rates were measured. Performance at varying water and gas fractions was measured to get an improved understanding and knowledge of multiphase flow occurring in a well. The results show clearly that the valve will choke gas and water effectively, both at single-phase and multiphase flow conditions. The reservoir and model fluid evaluations show consistent results. The valve shows roughly a monotonic decreasing total rate with decreasing oil fraction, implying that the valve will always prioritize sections with the largest oil fraction. A mathematical model match of the valve performance is possible via the 10-parameter extended autonomous inflow control device (AICD) equation that enables practical evaluation of the valve in industry-standard reservoir simulators. Various scenarios are explored with a conceptual reservoir model, and the autonomous inflow control valve shows its capacity to reduce water production and enable a more gradual and controlled increase in gas/oil ratio for most scenarios. The autonomous inflow control valve shows its largest potential to reduce unwanted fluids and increase oil recovery when used in segmented reservoirs. In cases with uncertain aquifer and/or gas cap strength, or large variation in effective permeability, the valve will make an infill well more robust as it autonomously adapts to reality, chokes unwanted fluids, and consequently enables more carbon-efficient reservoir management.

Гидротермально изменённые породы – индикаторы зон разгрузки углеводородов Красноленинского свода (Западная Сибирь)

Our own research data as well as numerous publications of recent years on modern problems of oil potential in the West Siberian oil and gas province were used in this study. Based on the Palyanovskaya, Talinskaya and adjacent areas of the Krasnoleninsky arch, the issues of deposits structure and confinement to certain regional levels of the section, the problems of unconventional reservoirs formation in the zones of tectonic deformations and hydrothermal-metasomatic changes in pre-Jurassic basement rocks (Paleozoic granites), as well as problems of highly permeable “supercollector” (the lower horizons of the Jurassiccomplex – Sherkalinskaya formation) and an almost impermeable reservoir with difficult to recover huge hydrocarbon reserves (its upper horizons – Bazhenov formation) are discussed. The oil deposits distribution in the Jurassic part of the section was shown to comply with the fluid migration model with the participation of deep hydrocarbon fluid. New types of unconventional reservoirs have been identified in the basement granites and in the unloading zones in the Jurassic deposits of the sedimentary cover.

Improved delineation of the Gassum Formation reservoir zones using seismic impedance inversions: implications for exploiting the Stenlille aquifer gas storage facility as a CO 2 storage demonstration site, onshore Denmark

A quantitative seismic interpretation of the Gassum Formation at the onshore aquifer gas storage near the Danish town of Stenlille is presented with its implications for exploiting the gas storage facility as a potential CO 2 demonstration site. Our objective was to better outline the reservoir heterogeneity of the Gassum Formation based on a 3D seismic volume and 20 wells available from the Stenlille gas storage facility. We derived new absolute and relative P-impedance inversion products, which are useful for delineating lithological distributions of thin sandstone reservoirs and shaly beds within the Gassum Formation. Our results broadly agree with previously published seismic interpretations, and build upon these by the identification of deviations in parts of the Gassum interval that should be considered in any subsequent development of a static reservoir model. Hence, this work is an important contribution to the planning of drilling new CO 2 injection wells as part of the development and management of the Stenlille CO 2 storage demonstration site. Nevertheless, we also recommend a modern seismic reprocessing of the 3D seismic data combined with newly acquired 2D data from the Stenlille structure as input into further quantitative seismic interpretation studies to refine reservoir characterization and reduce associated uncertainties. Supplementary material: video is available at https://doi.org/10.6084/m9.figshare.c.6662413

Regional variation of evaporite diagenesis in Xingouzui sandstones in Jianghan Basin, China: Implications for the evolution and prediction of saline reservoirs’ quality

Diagenetic processes and associated pore evolution are essential factors that control the development and distribution of porosity and permeability in saline reservoirs. The goal of this study is to systematically describe the comparative diagenetic processes, porosity evolution, and diagenetic facies of sandstone reservoirs in the Eocene Lower Xingouzui Formation (LXF) in two depressions in the Jianghan Basin, China. To achieve these goals, an integrated approach of petrographic, mineralogical, geochemical, and petrophysical analyses such as thin-section observations, X-ray diffraction (XRD), and mercury intrusion porosimetry (MIP) was applied to sandstone samples obtained from the Qianjiang and Jiangling sags. Diagenetic studies showed that the LXF samples had experienced several phases of diagenesis, including compaction, non-ferroan carbonate/sulfate cementation, feldspar and carbonate dissolution, quartz overgrowth cementation, ferroan carbonate and sulfate cementation, cubic pyrite precipitation, and limited gypsum dissolution. Although the LXF samples from both the Qianjiang and Jiangling sags experienced a noticeable porosity reduction induced by the compaction, the differences in diagenesis between these two sags were primarily due to complex and diverse cementation types. For instance, both early carbonate and sulfate cementation were recognized in Qianjiang samples, while only early carbonate cements were present in Jiangling samples. Based on a quantitative evaluation of the relative importance of diagenetic processes, diagenetic facies were defined in the LXF sandstones. Additionally, the pore evolution study indicated that two (upper and lower) zones of abnormally high porosity and permeability (AHPP) were developed in both sags. In particular, the upper AHPP zones occurred in sandstones in the Qianjiang and Jiangling depressions at depths of 1300 and 1800 m, respectively, while the lower AHPP zones in both depressions were located at a depth of 3300 m. The differences in the development mechanisms between the upper and lower AHPP zones were determined. This work provides an overview of the evolution and evaluation of sulfate- and carbonate-bearing sandstone reservoirs, such as the LXF sandstone, which have experienced strong diagenetic modifications during their geological histories.

Stable neodymium isotopic fractionation during chemical weathering

Stable Nd isotope ratio is a potentially useful tool to provide new constraints on the geological reservoir formation processes, complementing information from the radiogenic Nd isotope system. Here for the first time, we present the behavior of stable Nd isotopes during low-temperature weathering via a well-studied basaltic soil profile on Hainan Island, South China. The results showed that δ146/144Nd values spanned a range of approximately 0.21‰, from +0.058‰ in the lower profile to −0.152‰ in the upper soil profiles, while the τTh,Nd (%) values decreased from +387.7% to −68.2%, indicating that significant fractionation of stable Nd isotopes and migration of Nd elements occur during chemical weathering. Sequential extraction experiments suggest that the majority of Nd in this profile was hosted in the exchangeable and residual phases. The exchangeable phase was enriched with the heavy Nd isotope (146Nd) due to the adsorption of Nd onto gibbsite and the adsorption/precipitation of Fe-oxides from a heavier dissolved Nd pool in soils. The evidence for adsorption of Nd onto gibbsite is the positive correlation between the abundance of gibbsite and the proportion of Nd in the exchangeable phase, as well as the δ146/144Nd values. The evidence for the adsorption/precipitation of Nd on Fe-oxides comes from the positive correlations between Fe and Nd concentrations and δ146/144Nd values in the exchangeable fractions. The residual phases acquire depleted 146Nd signatures in the upper soil horizon, which could be caused by preferential desorption of heavy Nd isotopes from clay minerals or preferential incorporation of light Nd isotopes during kaolinite formation. These findings elucidate the mechanisms affecting stable Nd isotopic fractionation in low-temperature geochemistry and indicate that the stable Nd isotope ratio is a highly useful indicator for chemical weathering. This, combined with the radiogenic 143Nd/144Nd ratio, will be a powerful geochemical tracer for understanding global Nd cycles.

Experimental Investigation on the Penetrability Mechanism of Gel Slug During Well Completion Processes.

Reservoir formation damage is an essential problem which troubled oil and gas well production, a smart packer is a promising technology to maintain sustainable development for the oil and gas fields. Currently, the "gel valve" technology has been proved to be feasible with gel slug to seal casing and descend the completion pipe string, while the systemic performance of ideal gel is still not clear. In the underbalanced completion stage with the gel valve, the downward completion string needs to penetrate the gel slug to form an oil and gas passage in the wellbore. The penetration of rod string to gel is a dynamic process. The gel-casing structure often shows a time-dependent mechanical response, which is different from the static response. In the process of penetration, the interaction force between the rod and gel is not only related to the properties of the interface between gel and string but also affected by the moving speed, rod diameter, and thickness of the gel. The dynamic penetration experiment was carried out to determine the penetrating force varied with depth. The research showed that the force curve was mainly composed of three parts, the rising curve of elastic deformation, decline curve for the surface worn out, and another curve of the rod wear into. By changing the rod diameter, gel thickness, and penetration speed, the change rules of forces in each stage were further analyzed, which would provide a scientific basis for a well completion design with a gel valve.

Impact of coal evolution on formation of tight sandstone reservoirs: A case study in the Daniudi gas field, Ordos Basin, China

Tight sandstone gas in coal-bearing strata has become an important unconventional gas worldwide. This research aims at understanding the impacts of coal evolution on diagenesis and reservoir quality of sandstones by means of thin section, cathode luminescence (CL), scanning electron microscope (SEM), stable isotope analysis, and fluid inclusions. The results show that carbonate cement was the main type of cement developed in tight sandstone reservoirs, of which the carbonate ions were jointly provided by coal layers and reaction in adjacent mudstones. For sandstones close to coal layers, their carbonate ions were mainly controlled by coal evolution and there was various carbonate cement developed due to cations supplied by seawater and the intense dissolution of volcanic fragments and feldspars. Combined with coal thermal simulation and burial history, it implies that at different maturity stages of coal evolution, its impact on sandstone diagenesis was different. In the early stage, the main product was CO2, which caused the dissolution of early calcite and promoted intense compaction. In the mature stage, CO2 and other hydrocarbon gases were released, resulting in more dissolution and silica cementation. In the over-mature stage, the main product was methane, and CO2 that did not spill out preserved by forming carbonate cement. The coal evolution had a strong impact on the reservoir quality of sandstone with large grain sizes, but little effect on medium- and fine-grained sandstones. High porosity and low permeability reservoirs were usually formed in small conglomerates and coarse-grained sandstones away from coal layers. While low porosity and high permeability reservoirs were distributed close to coal layers. This study aids in understanding the formation mechanism of tight sandstone reservoirs in coal measures and provides theoretic support for further exploration.

Identification of an oil-bearing layer by formation water resistivity: A case study of the Jurassic reservoir, Southwest Ordos Basin

In the southwestern Ordos Basin, the formation water salinity and resistivity of Jurassic sandstone reservoirs are characterized by rapid changes and great variations, which lead to difficulties in the identification of reservoir fluid types and the development and exploration of the hydrocarbons in this area. To explore appropriate methods for reservoir fluid identification provided with complex formation water salinity and resistivity, we have conducted three research steps. First, using formation water testing and well-logging data, the formation water salinity, spontaneous potential, and reservoir resistivity are used to calculate the formation water resistivity. Second, the calculation results were used to separate the reservoir fluid types. Third, the calculated formation water resistivities are classified and the relationship between the formation water resistivity and the oil-producing interval is established. The results indicate that, for oil-producing intervals, the formation water resistivity calculated using the reservoir resistivity is the highest, whereas that using the formation water salinity is the lowest. Based on this understanding, two identification methods of reservoir fluid types are developed, including the qualitative curve overlap method and the quantitative ternary graph method. The curve overlap method can be applied to visually distinguish reservoir fluid types through the differentiation of formation water resistivity. Compared with some earlier quantitative methods, the ternary graph method can achieve an efficiency of 87.7% in identifying the type of reservoir fluid. Finally, the reliability of both methods is verified by case studies.

Robot-assisted radical cystectomy with intracorporeal reconstruction of urinary diversion by mechanical stapler: prospective evaluation of early and late complications.

Radical cystectomy with pelvic lymph node dissection is the gold standard treatment for non-metastatic muscle-invasive bladder cancer and high-risk non-muscle-invasive bladder cancer. For years, the traditional open surgery approach was the only viable option. The widespread of robotic surgery led to its employment also in radical cystectomy to reduce complication rates and improve functional outcomes. Regardless of the type of approach, radical cystectomy is a procedure with high morbidity and not negligible mortality. Data available in the literature show how the use of staplers can offer valid functional outcomes, with an acceptable rate of complications shortening the operative time. The aim of our study was to describe the perioperative outcomes and complications associated with robot-assisted radical cystectomy (RARC) with intracorporeal urinary diversion (ICUD) using a mechanical stapler. From January 2015 to May 2021, we enrolled patients who underwent RARC with pelvic node dissection and stapled ICUD (ileal conduit or ileal Y-shaped neobladder according to the Perugia ileal neobladder) in our high-volume center. Demographic features, perioperative outcomes and early (≤30 days) and late (>90 days) post-operative complications according to the Clavien-Dindo classification, were recorded for each patient. We also analyzed the potential linear correlation between demographic, pre-operative as well as operative features and the risk of post-operative complications. Overall, 112 patients who underwent RARC with ICUD were included with a minimum follow-up of 12 months. Intracorporeal Perugia ileal neobladder was performed in 74.1% of cases while ileal conduit was performed in 25.9%. The mean operative time, estimated intraoperative blood loss, and LOS were 289.1 ± 59.7 min, 390.6 ± 186.2 ml, and 17.5 ± 9.8 days, respectively. Early minor and major complications accounted for 26.7% and 10.8%, respectively. Overall late complications were 40.2%. The late most common complications were hydronephrosis (11.6%) and urinary tract infections (20.5%). Stone reservoir formation occurred in 2.7% of patients. Major complications occurred in 5.4%. In the sub-analysis, the mean operative time and the estimated blood loss improved significantly from the first 56 procedures to the last ones. RARC with ICUD performed by mechanical stapler is a safe and effective technique. Stapled Y-shaped neobladder did not increase the complication rate.

Analysis of the effect of formation dip angle and injection pressure on the injectivity and migration of CO2 during storage

Carbon dioxide (CO2) geological storage (CGS) can help realize the plan of “Carbon Neutrality”. Injection capacity and storage safety are crucial factors in evaluating CO2 storage efficiency. Deep saline aquifers are major sites for CGS. This study focused on evaluating the CO2 injection amount, migration safety and leakage risk. A three-dimensional (3D) model of the Shenhua CO2 capture and storage (CCS) project in the Ordos Basin, China, was established to discuss the impact of injection pressure (1.3P (equal to 1.3 times the top reservoir formation hydrostatic pressure), 1.4P, and 1.5P) and formation dip angle (0°, 5°, 10°, 15°) with fault on the total CO2 injection and migration safety. Twelve schemes were designed for simulation. Based on the results, faulting provided a pathway for CO2 leakage, posing a threat to CO2 storage safety. Injection pressure and formation dip angle had significant effects on injectivity and migration during CO2 storage. The influence of the injection pressure on the CO2 injection amount was more evident than that of the dip angle, though formation dip angle had a significant impact on the CO2 migration during storage. Increasing the injection pressure and formation dip angle increased the gas and dissolved-phase CO2 migration and decreased the CO2 leakage time and storage safety. The CO2 leakage through the fault occurred after 160, 110 and 80 years in a 15° sloping formation with 1.3P, 1.4P, and 1.5P, respectively. The CO2 injection amount was the largest for the 0° formation with 1.5P. These results provide fundamental information for CO2 storage safety and capacity, suggesting that un-faulted reservoirs with smaller dip angles should be selected for CGS projects; however, larger injection pressures can result in greater injection amounts, decreasing the migration safety of CO2 during storage.

Deep dive into net pay layers: An in-depth study in Abadan Plain, South Iran

This study focuses on the intricate process of discerning productive layers within reservoir formations, taking the Sarvak Formation as a primary case. The employed methodology combines geology, comprehensive log interpretations, and petrophysical analyses to facilitate the evaluation of these productive layers. Initially, routine well logs are interpreted to determine key petrophysical parameters such as shale content, porosity, and water saturation. Subsequently, core measurement results are utilized for calibrating these log interpretations. The study further determines cut-off values through a calculated method of 5% cumulative hydrocarbon volume against porosity, shale content, and water saturation. These cut-off values are then applied to the petrophysical results to enhance their reliability. To resolve any inconsistencies or uncertainties in petrophysical evaluation, petrographical analyses, including scanning electron microscope imaging and thin section studies, are employed. The Sarvak Formation is categorized into seven distinct subzones, each thoroughly investigated to ascertain their respective productivity potential. The final results illustrate a substantial heterogeneity within the Sarvak Formation, revealing a range of diagenetic processes including compaction, dissolution, and cementation. Despite this complexity, three subzones are identified as the most productive layers with the maximum net pay, demonstrating the efficacy of the integrated approach.