Poor Reservoir Research Articles

Impacts of lithologic characteristics and diagenesis on reservoir quality of the 4th member of the Upper Triassic Xujiahe Formation tight gas sandstones in the western Sichuan Basin, southwest China

Abstract The 4th member of the Upper Triassic Xujiahe Formation has become a primary target for tight gas exploitation in the western Sichuan Basin in past decades. Finding relatively high porosity reservoirs in tight sandstones is significant for successful tight gas exploration. In this study, the Xu4 sandstone was studied by a variety of experimental methods, including core observation, thin-section and cathodoluminescence observation, porosity and permeability measurement, mercury intrusion, scanning electron microscopy, X-ray diffraction, electron probe micro-analyzer and fluid inclusion, to determine the reservoir characteristics and also diagenesis evolution and to discuss their impacts on the reservoirs. The Xu4 sandstones are mainly litharenites, feldspathic litharenites and sublitharenites. Among these, calcarenaceous sandstone (CS sandstone) and sandstone with a high kaolinite content (KS sandstone) are classified by their special compositions. The reservoir quality of the Xu4 sandstone is poor, and among the five types of sandstone, the reservoir quality of the KS sandstone is generally better than that of the other types. The diagenetic variations of the Xu4 sandstone are complicated by compaction, kaolinite and quartz cementation, two stages of carbonate cementation, and two stages of dissolution of feldspar and some unstable rock fragments. The KS sandstone is the product of feldspathic litharenite that underwent early-stage dissolution of feldspar during eodiagenesis because of the acidic fluids in the sandstone. This process resulted in a low K+/H+ ratio of the pore fluids, i.e., acidic fluids derived from atmospheric fresh water and fluids of adjacent strata bearing coal seams. The determination of the diagenetic evolution indicated that the poor reservoir quality can be attributed to strong compaction or extensive cementation (mainly calcite cementation). However, the occurrence of relatively high porosity reservoirs varies among the sandstones. For CS sandstone, weak early carbonate cementation is essential. For sublitharenite, feldspathic litharenite, and litharenite, late dissolution of feldspar and less cement are necessary for the formation of relatively high-quality reservoirs. Due to their high porosity, almost all of the KS sandstones are relatively high-quality reservoirs.

Can carbonate cementation be inhibited in continental red bed sandstone?

The Lower Cretaceous Bashijiqike Formation in Kuqa depression belongs to a continental red bed sandstone with poor reservoir quality, and is deeply buried to 5.5–7.0 km but some successions can host porosity >10% and permeability larger than 10 mD. Carbonate cements are important pore-filling constituents, and they control the reservoir quality and heterogeneity of Bashijiqike sandstones. Red hematite-bearing grain-coating clay minerals inhibit the pore occluding quartz cements and preserve intergranular pores. Here we investigate the ability of grain-coating clays to inhibit carbonate cements. Thin sections, scanning electron microscopy (SEM), X-ray diffraction (XRD), and cathode luminescence (CL) analysis were performed to investigate the petrography, pore systems, diagenesis and diagenetic minerals of the red bed sandstones. The results show the hematite-bearing grain coatings give the ‘‘red bed’’ colors of the sandstones. The sandstones are heavily mechanically compacted, and the predominant pore-filling cements include carbonates and clay minerals, while quartz cements are volumetrically not important in reducing porosity. The grain-coating clays are mainly hematite-bearing mixed-layer illite and smectite. The paragenetic sequences of various types and generations of diagenetic events were reconstructed. Sandstones containing effective mixed-layer illite and smectite coatings, in which the intergranular pores can be preserved, have high porosities. Carbonate cement is never found in sandstones with effective grain coating clays, and carbonate cement precipitates where there are no sufficiently thick and continuous grain coats. The clay coatings retard or inhibit eogenetic calcite cements and progressively restrict late-stage carbonate (dolomite) cementation during burial. The hematite-bearing grain-coating clays help the red bed sandstones retain good reservoir quality at great depths.

Facies and depositional environments of the Upper Muschelkalk (Schinznach Formation, Middle Triassic) in northern Switzerland

Subsurface sedimentary strata in northern Switzerland, such as the Middle Triassic Upper Muschelkalk, are attracting interest as potential reservoirs for CO2 sequestration and for geothermal energy production. Characterizing facies in such strata aids prediction of reservoir properties in unexplored areas. Although well studied elsewhere, the Swiss Upper Muschelkalk has received little attention despite containing the southern-most deposits of the Central European Basin. The Upper Muschelkalk represents the deposits of a storm-dominated, homoclinal carbonate ramp, developed during a basin-wide 3rd-order transgressive–regressive cycle. Our facies analyses of nine boreholes across northern Switzerland reveal 12 lithofacies, eight lithofacies associations and four types of metre-scale 5th-order cycles corresponding to at least 23 short orbital eccentricity cycles. During the 3rd-order transgression, crinoidal bioherms developed across Switzerland followed by deep-ramp environments. Subsequently, tempestites were deposited up to and after the basin-wide maximum flooding surface. Lateral tempestite correlations indicate that Switzerland lay within an open-marine, mid-ramp environment during almost half of the depositional history. Mid-ramp deposits pass upwards to prograding shelly shoals, which sheltered a back-shoal lagoon containing patchy oolitic shoals. At the top of the Upper Muschelkalk, back-shoal sediments give way to coastal sabkha facies, which were overlain by oolitic shoals during a marine transgression. Shortly thereafter the top of the Upper Muschelkalk was dolomitized by brines from an overlying hypersaline environment that was later removed by a basin-wide erosive event. Overall, the paucity of porous shoal facies, unlike in southern Germany, has resulted in poor primary reservoir properties in the Upper Muschelkalk of Switzerland.

Grading evaluation and prediction of fracture-cavity reservoirs in Cambrian Longwangmiao Formation of Moxi area, Sichuan Basin, SW China

Abstract By using core, thin section, well logging, seismic, well testing and other data, the reservoir grading evaluation parameters were selected, the classification criterion considering multiple factors for carbonate reservoirs in this area were established, and the main factors affecting the development of high quality reservoir were determined. By employing Formation MicroScanner Image (FMI) logging fracture-cavity recognition technology and reservoir seismic waveform classification technology, the spatial distribution of reservoirs of all grades were predicted. On the basis of identifying four types of reservoir space developed in the study area by mercury injection experiment, a classification criterion was established using four reservoir grading evaluation parameters, median throat radius, effective porosity and effective permeability of fracture-cavity development zone, relationship between fracture and dissolution pore development and assemblage, and the reservoirs in the study area were classified into grade I high quality reservoir of fracture and cavity type, grade II average reservoir of fracture and porosity type, grade III poor reservoir of intergranular pore type. Based on the three main factors controlling the development of high quality reservoir, structural location, sedimentary facies and epigenesis, the distribution of the 3 grades reservoirs in each well area and formation were predicted using geophysical response and percolation characteristics. Follow-up drilling has confirmed that the classification evaluation standard and prediction methods established are effective.

Fatehgarh lacustrine turbidite potential, Barmer Basin, India

Global discovered resources of oil and gas in giant stratigraphic and structural-stratigraphic combination traps have increased by nearly 50% in the last 17 years. Among the biggest contributors are the large discoveries in deepwater turbidite systems in passive margins and rift basins. The current study area is located in the Barmer Basin in northwestern India. Barmer Basin is a prolific petroliferous basin with major oil discoveries in structural plays including Mangala, Bhagyam, and Aishwariya fields. The principal reservoirs in the structural highs are high-quality fluvial sandstones of the Paleocene Fatehgarh Formation. Lacustrine turbidite plays have been discovered in the overlying Paleocene Barmer Hill Formation, albeit with moderate to poor reservoir quality. The potential exists, however, for finding off-structure lacustrine deepwater turbidite plays in the Paleocene Fatehgarh with reservoir quality comparable to the high-quality fluvial facies encountered updip in the structural plays. An integrated approach was adopted to identify stratigraphic entrapments across the basin to chase high-quality Fatehgarh reservoirs. Gross depositional environment maps integrating new geoscientific data were created, followed by well-calibrated seismic geomorphology and seismic facies interpretations to identify the distal lacustrine deepwater turbidite system fed by the updip fluvial Fatehgarh systems. Worldwide, the critical risk elements associated with such plays are reservoir presence, quality, and lateral seal. Geophysical tools like unsupervised seismic waveform classification, spectral decomposition, and seismic inversion were applied to the available seismic data, and the results were integrated with the regional geology and well facies information to derisk the critical risk segments.

Experimental Investigation of Pore Structure and Movable Fluid Traits in Tight Sandstone

Whether the variation of pore structures and movable fluid characteristics enhance, deteriorate, or have no influence on reservoir quality has long been disputed, despite their considerable implications for hydrocarbon development in tight sandstone reservoirs. To elucidate these relationships, this study systematically analyzes pore structures qualitatively and quantitatively by various kinds of direct observations, indirect methods, and imaging simulations. We found that the uncertainty of porosity measurements, caused by the complex pore-throat structure, needs to be eliminated to accurately characterize reservoir quality. Bulk water was more easily removed, while surface water tended to be retained in the pores, and the heterogeneity of pore structures was caused by the abundance of tiny pores. The rates of water saturation reduction in macropores are faster than those for tiny pores, and sandstones with poor reservoir quality show no marked descending of lower limits of movable pore radius, indicating that the movable fluid would advance exempted from the larger pores. This study suggests that the deterioration of reservoir quality is strongly affected by the reduction of larger pores and the aqueous phases tended to remain in the tiny pores in the forms of surface water.

Nebular history of an ultrarefractory phase bearing CAI from a reduced type CV chondrite

Ultrarefractory (UR) phases in CAIs could have formed at higher T compared to common CAI minerals and thus they potentially provide constraints on very high-T processes in the solar nebula. We report a detailed characterization of an UR phase davisite bearing CAI from a reduced type CV chondrite. Absence of secondary iron- and/or alkali-rich phases and occurrence of LIME olivine indicate that primitive chemical and isotopic compositions are preserved in the CAI. Davisite occur only in one lithological unit that consists of three chemically and isotopically distinct parts: i) $^{16}$O-poor regions with reversely-zoned melilite and davisite; ii) $^{16}$O-rich regions consisting of unzoned, gehlenitic melilite, diopside and spinel; and iii) spinel framboids composed of $^{16}$O-rich spinel and $^{16}$O-poor melilite. Random distribution of chemical and isotopic heterogeneities with sharp boundaries in the CAI indicates its formation by an aggregation of mineral assemblages formed and processed separately at different time and/or space. Although isotope exchange prior to the final agglomeration of the CAI cannot be ruled out, we suggest that modification of chemical and isotopic composition of porous CAI precursors or aggregation of isotopically distinct mineral assemblages are alternative scenarios for the origin of O-isotopic heterogeneity in CAIs. In either case, coexistence of spatially and/or temporally distinct $^{16}$O-rich and -poor gaseous reservoirs at the earliest stage of the solar system formation is required. The grain-scale oxygen isotopic disequilibrium in the CAI indicate that post-formation heating of the CAI was short, which can be achieved by rapid outward transport of the CAI. High Ti$^{3+}$/Ti$^{\mathrm{tot}}$ ratios of pyroxene and presence of LIME olivine document that the entire CAI formation process took place under highly reducing conditions.

Pressure management via brine extraction in geological CO2 storage: Adaptive optimization strategies under poorly characterized reservoir conditions

Industrial-scale injection of CO2 into the subsurface increases the fluid pressure in the reservoir, which if not properly controlled can potentially lead to geomechanical damage (i.e., fracturing of the caprock or reactivation of faults) and subsequent CO2 leakage. Brine extraction is one approach for managing formation pressure, effective stress, and plume movement in response to CO2 injection. The management of the extracted brine can be expensive (i.e., due to transportation, treatment, disposal, or re-injection), with added cost to the carbon capture and sequestration (CCS); thus, minimizing the volume of extraction brine is of great importance to ensure that the economics of CCS are favorable. The main objective of this study is to demonstrate the use of adaptive optimization methods in the planning of brine extraction and to investigate how the quality of initial site characterization data and the use of newly acquired monitoring data (e.g. pressure at observation wells) impact the optimization performance. We apply an adaptive management approach that integrates monitoring, calibration, and optimization of brine extraction rates to achieve pre-defined pressure constraints. Our results show that reservoir pressure management can be extremely benefited by early and high frequency pressure monitoring during early injection times, especially for poor initial reservoir characterization. Low frequencies of model calibration and optimization with monitoring data may lead to optimization problems because either pressure buildup constraints are violated or excessively high extraction rates are proposed. The adaptive pressure management approach may constitute an effective tool to manage pressure buildup under uncertain reservoir conditions by minimizing the volumes of extracted brine while controlling pressure buildup.

Rift-related magmatism influences petroleum system development in the NE Irish Rockall Basin, offshore Ireland

Large volumes of hydrocarbons reside in volcanically influenced sedimentary basins. Despite having a good conceptual understanding of how magmatism impacts the petroleum systems of such basins, we still lack detailed case studies documenting precisely how intrusive magmatism influences, for example, trap development and reservoir quality. Here we combine 3D seismic reflection, borehole, petrographical and palaeothermometric data to document the geology of borehole 5/22-1, NE Irish Rockall Basin, offshore western Ireland. This borehole (Errigal) tested a four-way dip closure that formed to accommodate emplacement of a Paleocene–Eocene igneous sill-complex during continental break-up in the North Atlantic. Two water-bearing turbidite-sandstone-bearing intervals occur in the Upper Paleocene; the lowermost contains thin ( c . 5 m), quartzose-feldspathic sandstones of good reservoir quality, whereas the upper is dominated by poor-quality volcaniclastic sandstones. Palaeothermometric data provide evidence of anomalously high temperatures in the Paleocene–Eocene succession, suggesting the poor reservoir quality within the target interval is likely to reflect sill-induced heating, fluid flow, and related diagenesis. The poor reservoir quality is also probably the result of the primary composition of the reservoir, which is dominated by volcanic grains and related clays derived from an igneous-rock-dominated, sediment source area. Errigal appeared to fail due to a lack of hydrocarbon charge: that is, the low bulk permeability of the heavily intruded Cretaceous mudstone succession may have impeded the vertical migration of sub-Cretaceous-sourced hydrocarbons into supra-Cretaceous reservoirs. Break-up-related magmatism did, however, drive the formation of a large structural closure, with data from Errigal at least proving high-quality, Upper Paleocene deep-water reservoirs. Future exploration targets in the NE Irish Rockall Basin include: (i) stratigraphically trapped Paleocene–Eocene deep-water sandstones that onlap the flanks of intrusion-induced forced folds; (ii) structurally trapped, intra-Cretaceous, deep-water sandstones incorporated within intrusion-induced forced folds; and (iii) more conventional, Mesozoic fault-block traps underlying the heavily intruded Cretaceous succession (e.g. Dooish). Similar plays may exist on other continental margins influenced by break-up magmatism. Supplementary material: Borehole-related reports, and litho- and composite logs are available at https://doi.org/10.6084/m9.figshare.c.4803267

Evaluation of pore structures in volcanic reservoirs: a case study of the Lower Cretaceous Yingcheng Formation in the Southern Songliao Basin, NE China

Different pore types and variable pore structures can determine reservoir potentials of volcanic rocks. Therefore, it is of great importance to understand the pore structures of volcanic reservoirs. With the Lower Cretaceous Yingcheng volcanic rocks, this study attempts to investigate and evaluate the micro pore structures of a volcanic reservoir through: (1) measuring porosity and permeability of core samples; (2) identifying pore types within thin sections; (3) characterizing pore structures with pressure-controlled mercury injection. The Lower Cretaceous Yingcheng volcanic rocks exhibits low porosities (on average 7.39%) and very low permeability (on average 0.283 × 10−6 m2). Three major pore types were identified from the Lower Cretaceous Yingcheng volcanic reservoir, including primary pores, secondary pores and fractures. Additionally, the pore structures of the Lower Cretaceous Yingcheng volcanic reservoir can be classified into three types. Type I pore structure primarily occurs in the volcanic breccia, crystal tuff and tuffites. The corresponding pore system is dominated by primary intergranular pores, intragranular dissolved pores and devitrified micropores with porosity and permeability higher than 5.4% and 0.05 × 10−6 µm2, respectively. Corresponding mercury intrusion curves are characterized by low displacement pressure, high maximum mercury saturation and mercury withdrawal efficiency. Type II pore structure is commonly observed in the tuff and tuffites, while primary intergranular pores and secondary micropores dominate pore system with porosity of 2.5–5.4% and permeability of 0.012–0.05 × 10−6 m2. The mercury intrusion curves are similar to the type I. Type III pore structure is also pervasively developed in the crystal tuff and tuffites. Intragranular dissolved micropores are most important ones with porosity and permeability less than 2.5% and 0.01 × 10−6 m2, respectively. Different from type I and II pore structure, the mercury intrusion curves of the type III have high-displacement pressure, low maximum mercury saturation and mercury withdrawal efficiency, indicating poor reservoir quality.

Experimental analysis of factors influencing the development effect of multilayer gas well

Sulige gas field is characterized by complex pore structure, poor reservoir properties and low output of single-layer production. Therefore, in order to obtain higher economic profit, multi-layer commingling development is adopted in this type of gas field. According to the basic characteristics of the upper Paleozoic reservoir in Sulige gas field, there is a positive correlation between the output contribution rate of each production layer and its physical parameters and effective thickness. In order to directly analyze the inter-layer output law and its influencing factors of gas wells, a variety of formation models are designed, and the experiment of single-layer development and multi-layer combined development is carried out. It is found that permeability and original formation pressure are the main factors affecting the development effect of multi-layer well. The original formation pressure has the greatest influence on the ultimate recovery, while the permeability has the strongest influence on the average daily output and the yield contribution rate of productive layer. According to the similarity theory, the mathematical model between the gas productivity index per meter per well and permeability is fitted. Finally, the mathematical model is applied to 18 gas wells of the S-af area of sulige gas field, and the calculation accuracy reaches a high level. The validity and practicability of the formula is verified, which can provide the basis for subsequent production.

Some Technical Considerations of Gas-Hydrate Development From Chinese Permafrost Regions

Summary Review of published geological data shows that permafrost regions in China's Mohe Basin, Qilian Mountain, and Qinghai-Tibet Plateau hold promise for gas-hydrate accumulation according to identifiable source rock, migration path, and reservoir seal, among others. In addition, they show some common characteristics: source rock consisting mostly of shale, relatively poor reservoir quality, and gas migration through fractures. However, formation lithology, source-rock type, origin of organic matter, and total organic carbon (TOC) exhibit significant differences.

Core Plate Models for Experimental Study of Seepage Flow Patterns in Poor and Thin Reservoirs

We propose an artificial core plate model for studying seepage flow patterns in fractured poor and thin reservoirs. We have analyzed the pressure gradient distribution, mapped sections with different seepage flow patterns, and studied the qualitative and quantitative parameters of the seepage flow patterns for liquid in thin and poor reservoirs. The experiments have shown that the seepage flow pattern in thin and poor reservoirs depends on the permeability and heterogeneity of the rock and the presence of cracks. The presence of cracks can compensate for the negative impact of low permeability and heterogeneity of the rock. From the experimental results, we can identify three sections in the rock with different seepage flow patterns. Fracturing can significantly reduce the size of the no-flow section (by at least 72%) and can increase the size of the quasilinear seepage flow section (by at least 86%).

A renewed look at calcite cement in marine-deltaic sandstones: the Brent Reservoir, Heather Field, northern North Sea, UK

Abstract Wireline and seismic acoustic impedance imaging show that the marine part of the clastic Brent Group reservoir in the Heather Field, northern North Sea, contains much calcite cement in the flank parts of the structure. The non-marine Ness Formation and crest parts of the structure contain negligible calcite cement. This localized calcite cement has led to relatively poor reservoir performance since first oil in 1978, although a new suite of wells has boosted production with plans to keep the field active until 2030. Understanding the origin and distribution of calcite cement would help the development of more realistic reservoir models and boost production rates through optimum well location. We have thus used a suite of techniques, including standard point counting, SEM-EDS mineralogy, BSE microscopy, fluid inclusion thermometry and stable isotope analysis, to develop new and improved models of calcite distribution. Calcite seems to have attributes of both early and late diagenetic cement. A 30–40% intergranular volume in calcite cemented beds seems to support pre-compactional growth but high-temperature fluid inclusions and the presence of primary oil inclusions suggest late growth. Much calcite may have developed early but it seems to have recrystallized, and possibly undergone redistribution, at close to maximum burial or had a late growth event. Calcite cement probably originated as marine-derived micrite, bioclasts or early marine cement but adopted the isotopic characteristics of high-temperature growth as it recrystallized. Quartz grains have corroded outlines in calcite-cemented areas with one sample, with 79% calcite cement, displaying signs of nearly total replacement of quartz grains by calcite. The flank localization of calcite cement remains to be explained, although it could be due to primary depositional factors, early diagenetic loss of calcite from crestal regions or late diagenetic loss of calcite from crestal regions. Controversially, the growth of calcite seems to be associated with quartz dissolution, although the geochemical and petrophysical cause of this remains obscure. Diagenetic loss of quartz from sandstones cannot easily be explained by conventional modelling approaches and yet seems to be an important phenomenon in Heather sandstones.

Method Integration Improves Reservoir-Property Prediction in East Siberia

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191673-18RPTC, “Seismic- and Electromagnetic-Methods Integration To Increase Quality of Reservoir-Property and -Saturation Prediction in East Sibera Region,” by Pavel Mostovoy, Roman Oshmarin, and Andrey Ostankov, GazpromNeft, and Olga Tokareva and Daria Orlova, IERP, prepared for the 2018 SPE Russian Petroleum Technology Conference, Moscow, 15–17 October. The paper has not been peer reviewed. This paper describes a case study of the Chonskaya group of fields to demonstrate an approach to the integration of time-domain-electromagnetic (TDEM) electrical and seismic data when building a geological model for improving reservoir-property and -saturation prediction. Introduction The terrigenous sediments of the subsalt complex within the Nepa-Botuoba anteclise are characterized by complex geology: nonanticlinal traps, complex tectonics, lateral reservoir heterogeneity, and digenesis that controls reservoir distribution. The block structure of the Chonskaya group of fields and their poor coverage with exploration wells (Fig. 1) leave a number of uncertainties with regard to water/oil and gas/water contacts in blocks with proved oil content, as well as the main fluid types in exploration blocks. The success of predicting prospective sites for exploration drilling is influenced by minimal risks and reduced uncertainty during field development. An important task at the stage of exploration drilling is to increase the reliability of fluid contacts and reservoir properties. To improve the quality of geophysical predictions during exploration of the Chonskaya group of fields, geological exploration operations were conducted, including 3D seismic surveys and high-density electrical studies [time-domain electromagnetic and magnetic (TDEM)] on a single observation network. The area studied by TDEM and seismic surveys on the observation network in the Chonskaya group covers 3500 km2, more than 50% of the total territory of the license areas. In this regard, the methods to honor the TDEM data when building and updating complex geological models of reservoirs are being actively developed, because the TDEM signal can provide information about fluids saturating terrigenous reservoirs. To understand the capabilities of the technology for integrating seismic and electrical data and making a decision on the basis of the TDEM survey, forward modeling is necessary. On the basis of the modeling results and experience in building complex geological models, the combined use of electrical and seismic data has the potential to be used to separate pure-oil, water/oil, and pure-water zones; to predict probable fluid types in the exploration targets; and to outline zones with poor reservoir properties in terrigenous rocks of the subsalt complex within the Nepa-Botuoba anteclise. A geological model honors the TDEM data through building a geoelectrical reservoir model using a priori geological and geophysical information about target reservoirs—the kinematic and dynamic interpretation of seismic data, well-log-interpretation data, a petrophysical model, and a geological model of the reservoir (2D or 3D). Next, a comparative analysis of the synthetic geoelectrical model with the TDEM inversion data is conducted. The geological model assumptions are revised on the basis of qualitative and quantitative comparison. The revised assumptions allow reduction of the range of geological uncertainties and adjustment of the geological exploration program.

Sedimentology, geochemistry and reservoir properties of Upper Jurassic deep marine sediments (Hareelv Formation) in the Blokelv-1 borehole, Jameson Land Basin, East Greenland

The fully cored Blokelv-1 borehole was drilled through Upper Jurassic strata in the central part of the Jameson Land Basin, central East Greenland. The borehole reached a total depth of 233.8 m with nearly 100% recovery of high-quality core. An extensive analytical programme was undertaken on the core; sedimentological interpretation and reservoir characterisation were based on facies analysis combined with conventional core analysis, bulk geochemistry and spectral gamma and density scanning of the core. The Upper Jurassic Hareelv Formation was deposited in relatively deep water in a slope-to-basin setting where background sedimentation was dominated by suspension settling of organic-rich mud in oxygen-depleted conditions. Low- and high-density gravity-flow sandstone interbeds occur throughout the cored succession. About two-thirds of the high-density turbidite sandstones were remobilised and injected into the surrounding mud-rock. The resulting succession comprises nearly equal amounts of mudstones and sandstones in geometrically complex bodies. Ankerite cementation occurs in 37% of the analysed sandstones in varying amounts from minor to pervasive. Such ankerite-cemented sandstones can be identified by their bulk geochemistry where Ca > 2 wt%, Mg > 1 wt% and C > 1 wt%. The analysed mudstones are rich in Al, Fe, Ti and P and poor in Ca, Mg, Na and Mn. The trace-metal content shows a general increase in the upper part of the core reflecting progressive oxygen depletion at the sea floor. The reservoir properties of the Blokelv-1 sandstones were evaluated by both conventional core analysis and using log-derived porosity and permeability curves. The high-density turbidite beds and injectite bodies are a few centimetres to several metres thick and show large variations in porosity and permeability, in the range of 6–26 % for porosity and 0.05–400 mD for permeability. Individual sandstone units that are 1–7 m thick yield a net vertical reservoir thickness of 40 m with porosities of 15–26% and permeabilities of 1–200 mD. Heterolithic sandstone–mudstone units are generally characterised by poor reservoir quality with porosities of 2–14% and permeabilities of 0.1–0.6 mD.

Correlating diagenetic facies with well logs (conventional and image) in sandstones: The Eocene–Oligocene Suweiyi Formation in Dina 2 Gasfield, Kuqa depression of China

The lithology, mineralogy, texture, pore systems, and diagenesis of the Eocene–Oligocene Suweiyi Formation sandstones in Dina 2 Gasfield of Kuqa depression were investigated by integrating thin sections, scanning electron microscope (SEM) images with X-ray Diffraction and routine core analysis. The results reveal that carbonates and clay minerals are the dominant pore-filling constituents, while quartz cements and evaporate minerals occur in only minor amounts. Compaction played an important role in reducing intergranular porosity, especially in the clay-rich or poorly sorted successions. Framework grains dissolution greatly enhance total porosity. The pore systems consist of intergranular and intragraular dissolution porosity, micropores and minor intergranular pores. Four diagenetic facies are identified according to lithologic characteristics, diagenesis, as well as diagenetic minerals, and they are: (1) tightly compacted facies (high degree of compaction but low degree of cementation and dissolution); (2) carbonate (calcite) cemented facies; (3) clay mineral (illite and mixed-layer illite/smectite) filling facies; and (4) dissolution (of framework grains) facies. Diagenetic facies are correlated with the conventional well logs, and the well log expressions for diagenetic facies are summarized, then the diagenetic facies in uncored intervals and wells can be predicted based on the qualitative well log characteristics. Image logs were used to derive the porosity spectrum (porosity distribution histogram) by applying the typical Archie's formula to the flushed zone. Then the porosity spectrum is integrated with the conventional logs to predict the diagenetic facies, and the results can be evidenced by thin section observation, and SEM analysis. Dissolution facies, which has the highest reservoir quality, tend to have bi-modal porosity spectrum, and the porosity spectrum is very broad or even contains tail distributions. In contrast, the porosity spectrum of the carbonate cemented facies and tightly compacted facies are narrow and dominantly of uni-modal behaviors, indicating the absences of large pores and a poor reservoir quality. The porosity spectrum of clay mineral filling facies can be bi-modal or uni-modal, but the porosity spectrum is narrow and contains no tail distributions. The diagenetic facies and reservoir quality in sandstones can be predicted through correlating the diagenetic facies to conventional well logs integrated with image logs.

Oligocene stratigraphic traps at the SouthEastern, Cuu Long basin

Up to recent years, major targets of oil and gas exploration in Cuu Long basin have been carried ort at structural traps in anticlines or basement highs in PreTertiary basement, Oligocene / Miocene clastics. As petroleum resources from reservoirs of traditional types become exhausted after many years of production (the remaining unexplored potential targets do not have sufficient reserves for development and production), exploration activities in Cuu Long basin have being focused in Oligocene stratigraphic/combination traps that have been discovered in recent years. Since the 1980s, petroleum explorers have identified oil in pinchouts trap in the Southeastern Cuu Long basin. However, these prospects have been evaluated to be of low potential due to be concerned of poor reservoir quality or incomplete petroleum system (lacking of source rocks or seals). Recent exploration activities in the region have identified several stratigraphic/ combination traps not only as pinch-outs but also as traps formed by appropriate facies changes. This article discusses types of stratigraphic traps that have been recently discovered in the studied area as well as exploration methods for predicting the distribution of these traps.

Grain‐size variability within a mega‐scale point‐bar system, False River, Louisiana

AbstractPoint bars formed by meandering river systems are an important class of sedimentary deposit and are of significant economic interest as hydrocarbon reservoirs. Standard point‐bar models of how the internal sedimentology varies are based on the structure of small‐scale systems with little information about the largest complexes and how these might differ. Here a very large point bar (>25·0 m thick and 7·5 × 13·0 km across) on the Mississippi River (USA) was examined. The lithology and grain‐size characteristics at different parts of the point bar were determined by using a combination of coring and electrical conductivity logging. The data confirm that there is a general fining up‐section along most parts of the point bar, with a well‐defined transition from massive medium‐grained sands below about 9 to 11 m depth up into interbedded silts and fine–medium sand sediment (inclined heterolithic strata). There is also a poorly defined increase in sorting quality at the transition level. Massive medium sands are especially common in the region of the channel bend apex and regions upstream of that point. Downstream of the meander apex, there is much less evidence for fining up‐section. Finer sediment accumulated more readily after the establishment of a compound bar in the later stages of construction, at the terminal apex and in the bar tail. This work implies that the best reservoir sands are likely to be located in the centre of the point bar, deposited in a simple bar system. Reservoir quality decreases towards the bar edge. The early‐stage channel plug is largely composed of coarsening‐upward cycles of silt to clay and is dominated by clay and clayey silt material with poor reservoir characteristics.

Quantitative evaluation model for tight sandstone reservoirs based on statistical methods - A case study of the Triassic Chang 8 tight sandstones, Zhenjing area, Ordos Basin, China

Petroleum exploration for tight sandstone reservoirs in the Ordos Basin has attracted much attention in recent years. However, the effective evaluation of the quality of tight sandstones is challenging due to their low porosity, low permeability, non-Darcy flow, continuously or quasi-continuously distribution and strong heterogeneity. Using constant velocity mercury injection, cathodoluminescence micrography, energy spectrum analysis, scanning electron microscopy and casting thin sections, a set of parameters, including the clay mineral index, Lorentz coefficient, compositional maturity, and plane porosity are tentatively proposed to evaluate the quality of tight reservoir rocks. Coupled with statistical methods, i.e., Principal Component Analysis, Grey Correlation Analysis, Analytic Hierarchy Process and Hierarchical Cluster Analysis, a comprehensive quantitative reservoir evaluation model is established. Then, the evaluation index (REI) is calculated, and the thresholds of various types of reservoirs are determined. The case study based on the above evaluation model shows that most of the type I reservoirs are petroleum-enriched, which are favourable targets for exploration and development. By contrast with sedimentary microfacies, the sandbodies in favourable targets were deposited in ancient subaqueous distributary channels, and they show a large herringbone-like distribution. Whereas the poor type-III reservoirs and non-prospective layers are mainly located in the southeastern part of the study area. The case evaluation based on the statistical methods is consistent with the results of previous multi-parameter evaluations, which has important implications for further exploration in the study area as well as other tight sandstone reservoirs.