Clastic Reservoirs Research Articles

Wettability, hysteresis and fracture–matrix interaction during CO2 EOR and storage in fractured carbonate reservoirs

Relative permeabilities show significant dependence on the saturation path during CO2 enhanced oil recovery (EOR) and storage. This dependence (or hysteresis) is particularly important for water-alternating-gas (WAG) injection, a successful CO2 EOR and storage method for clastic and carbonate reservoirs. WAG injection is characterized by an alternating sequence of drainage and imbibition cycles. Hysteresis is hence common and results in residual trapping of the CO2 phase, which impacts the volume of CO2 stored and the incremental oil recovery. The competition between hysteresis and geological heterogeneity during CO2 EOR and storage, particularly in carbonate reservoirs, is not yet fully understood.In this study, we use a high-resolution simulation model of a Jurassic Carbonate ramp, which is an analogue for the highly prolific reservoirs of the Arab D formation in Qatar, to investigate the impact of hysteresis during CO2 EOR and storage in heterogeneous carbonate formations. We then compare the impact of residual trapping (due to hysteresis) on recovery to the impact of heterogeneity in wettability and reservoir structure. End-member wettability scenarios and multiple wettability distribution approaches are tested, while, effective fracture permeabilities are computed using discrete fracture networks (DFN), ranging from sparsely distributed background fractures to fracture networks where intensity varies with proximity to faults.The results enable us to analyze the efficiency of oil recovery and CO2 sequestration in carbonate reservoirs by comparing the impact of physical displacement processes (e.g., imbibition, drainage, residual trapping) and heterogeneous rock properties (e.g., wettability, faults, fractures, layering) that are typical in carbonate reservoirs. We show that although the fracture network properties have the greatest impact on the fluid flow, the effect of wettability and hysteresis is nontrivial. Our results emphasize the need for wettability to be accurately measured and appropriately distributed in a reservoir simulation model. Similarly, our results indicate that hysteresis effects in cyclic displacement processes must be accounted for in detail to ensure that simulation models give accurate predictions.

碳酸盐岩储层非均质性研究现状及发展趋势

储层非均质性是指储层由于在形成过程中受沉积、成岩作用和构造作用的影响，在空间分布及内部各种属性上都存在的不均匀的变化。其对油气的开发利用以及中老油田剩余油的再开发具有重要作用，所以储层非均质性一直是储层研究的重点、难点。随着我国大部分陆相碎屑岩油气田已进入中晚期，所以海相碳酸盐岩型油气藏在我国的油气田勘探开发中日益重要。随着塔里木、四川盆地的海相碳酸盐岩型油气田的勘探取得重大突破后，碳酸盐岩储层非均质性的研究与评价愈显重要。通过查阅大量资料以及借鉴碎屑岩储层非均质性研究手段，归纳总结碳酸盐储层非均质性的研究现状、表征、研究方法等内容，随着多学科相结合以及储层地质建模技术的应用，碳酸盐岩储层非均质性的研究必定会达到一个新的阶段。 Reservoir heterogeneity refers to the spatial distribution and various internal attributes of reser-voir are uneven, because of the effect of depositional environment, diagenesis and tectonic in the process of reservoir formation. Reservoir heterogeneity plays an important role on exploitation of oil and gas as well as redevelopment of the residual oil in old fields, so it has been the difficulty and emphasis of reservoir research. With most of continental clastic oil-gas fields entering into the middle or last period of development, the exploration and development of marine carbonate oil- gas fields become increasingly important. As the exploration of marine carbonate oil-gas fields in Tarim, Sichuan Basin made a major breakthrough; the research and evaluation of carbonate reservoir heterogeneity become more and more important. Summarizing the research status, cha-racterization, research methods and so on of carbonate reservoir heterogeneity by referring to large amount of data and drawing lessons from clastic reservoir heterogeneity research tools, with the combination of multiple disciplines and the application of technology of reservoir geologic modeling, carbonate reservoir heterogeneity research will reach a new stage.

Pressure Transient Analysis for Finite Conductivity Multi-staged Fractured Horizontal Well in Fractured-Vuggy Carbonate Reservoirs

Transient pressure analysis has been considered as a robust method to identify the flow behaviors, estimate reservoir parameters and hydraulic fracturing parameters. Compared with conventional clastic reservoirs, complex pore systems in fractured–vuggy carbonate reservoirs are posing significant research challenges. Although pressure transient analysis(PTA) models for different style wells in carbonate reservoirs have been widely studied, limited study has been conducted for multi-fractured horizontal well (MFHW) in these reservoirs. Thus, this paper is an investigation on PTA for MFHW of fractured-vuggy carbonate reservoirs. Based on source function theory, mirrors reflection and superposition principle,, the finite conductive MFHW’s bottom-hole pressure solution for fractured-vuggy carbonate reservoirs is obtained by the Laplace transform and the Stehfest inversion method. Log-log type curves are drawn by numerical algorithms and eight flow regimes are identified. Finally the influences of sensitivity parameters such as fracture number, fracture spacing, half length of fracture, storativity ratio, inter-porosity flow coefficient on unsteady flow behaviors of MFHW are discussed in depth.

Diagenesis and origin of calcite cement in the Flemish Pass Basin sandstone reservoir (Upper Jurassic): Implications for porosity development

The Flemish Pass Basin is a deep-water basin located offshore on the continental passive margin of the Grand Banks, eastern Newfoundland, which is currently a hydrocarbon exploration target. The current study investigates the petrographic characteristics and origin of carbonate cements in the Ti-3 Member, a primary clastic reservoir interval of the Bodhrán Formation (Upper Jurassic) in the Flemish Pass Basin.The Ti-3 sandstones with average Q86.0F3.1R10.9 contain various diagenetic minerals, including calcite, pyrite, quartz overgrowth, dolomite and siderite. Based on the volume of calcite cement, the investigated sandstones can be classified into (1) calcite-cemented intervals (>20% calcite), and (2) poorly calcite-cemented intervals (porous). Petrographic analysis shows that the dominant cement is intergranular poikilotopic (300–500 μm) calcite, which stared to form extensively at early diagenesis. The precipitation of calcite occured after feldspar leaching and was followed by corrosion of quartz grains. Intergranular calcite cement hosts all-liquid inclusions mainly in the crystal core, but rare primary two-phase (liquid and vapor) fluid inclusions in the rims ((with mean homogenization temperature (Th) of 70.2 ± 4.9 °C and salinity estimates of 8.8 ± 1.2 eq. wt.% NaCl). The mean δ18O and δ13C isotopic compositions of the intergranular calcite are −8.3 ± 1.2‰, VPDB and −3.0 ± 1.3‰, VPDB, respectively; whereas, fracture-filling calcite has more depleted δ18O but similar δ13C values. The shale normalized rare earth element (REESN) patterns of calcite are generally parallel and exhibit slightly negative Ce anomalies and positive Eu anomalies. Fluid-inclusion gas ratios (CO2/CH4 and N2/Ar) of calcite cement further confirms that diagenetic fluids originated from modified seawater. Combined evidence from petrographic, microthermometric and geochemical analyses suggest that (1) the intergranular calcite cement precipitated from diagenetic fluids of mixed marine and meteoric (riverine) waters in suboxic conditions; (2)the cement was sourced from the oxidation of organic matters and the dissolution of biogenic marine carbonates within sandstone beds or adjacent silty mudstones; and (3) the late phases of the intergranular and fracture-filling calcite cements were deposited from hot circulated basinal fluids.Calcite cementation acts as a main controlling factor on the reservoir quality in the Flemish Pass reservoir sandstones. Over 75% of initial porosity was lost due to the early calcite cementation. The development of secondary porosity (mostly enlarged, moldic pores) and throats by later calcite dissolution due to maturation of organic matters (e.g., hydrocarbon and coals), was the key process in improving the reservoir quality.

Evolution of small-scale flow barriers in German Rotliegend siliciclastics

Abstract Many siliciclastic reservoirs contain millimetre-scale diagenetic and structural phenomena affecting fluid flow. We identified three major types of small-scale flow barriers in a clastic Rotliegend hydrocarbon reservoir: cataclastic deformation bands; dissolution seams; and bedding-parallel cementation. Deformation bands of various orientations were analysed on resistivity image logs and in core material. They are mainly conjugates, and can be used to validate seismically observable faults and infer subseismic faults. Bedding-parallel dissolution seams are related to compaction and post-date at least one set of deformation bands. Bedding-parallel cementation is accumulated in coarser-grained layers and depends on the amount of clay coatings. Apparent permeability data related to petrographical image interpretation visualizes the impact of flow barriers on reservoir heterogeneity. Transmissibility multiplier calculations indicate the small efficiency of the studied deformation bands on flow properties in the reservoir. Deformation bands reduce the host-rock permeability by a maximum of two orders of magnitude. However, host-rock anisotropies are inferred to reduce the permeability by a maximum of four orders of magnitude. The relative timing of these flow barriers, as well as the assessment of reservoir heterogeneities, are the basis for state-of-the-art reservoir prediction modelling.

Fluvial reservoirs stacked in thin deltaic successions of the Lower Cretaceous Grand Rapids Formation, east-central Alberta, Canada

The Manatokan Field in east-central Alberta offers a unique opportunity to characterize paralic sandstone reservoirs in 3D using a dense network of well data (approximately [Formula: see text]). Within the [Formula: see text] study area, the 100-m thick Lower Cretaceous Grand Rapids Formation is dominantly composed of sediment deposited in two depositional environments: river-dominated deltas and marine-influenced fluvial rivers. Up to 33 individual fluvial bodies, occurring at five stratigraphic levels and eroding into deltaic parasequences, are identified in the oil-charged upper part of the formation. The width and thickness of fluvial bodies typically range from 50 to 9000 m and from 5 to 50 m, respectively. Examination of cores, wireline logs, and strategically located 3D seismic data indicates that fluvial bodies are dominantly filled by inclined heterolithic deposits emplaced as downflow translation point bars (PBs) separated by mud-filled abandoned channels. Although individual PBs are relatively small ([Formula: see text]), the dense subsurface data set provides the means to build facies maps that illustrate their internal architecture and the distribution of reservoir heterogeneities. Reservoir-quality sandstone occurs on the upstream portion of PBs and usually forms continuous beds along the base of fluvial bodies that extend underneath abandoned channel deposits. High reservoir connectivity along the base of these heterolithic fluvial bodies constitutes a major advantage for heavy oil reservoir production driven by gravity. Core evidences also indicate potential communication between fluvial bodies and surrounding deltaic sandstones or older underlying fluvial reservoirs, which may lead to unexpected results during field development. The Grand Rapids Formation provides a good subsurface analogue of complex marginal-marine clastic reservoirs, and its study may help to explain unanticipated production results in similar hydrocarbon areas.

Diagenesis and Diagenetic Evolution of Deltaic and Neritic Gas‐Bearing Sandstones in the Lower Mingyuefeng Formation of Paleogene, Lishui Sag, East China Sea Shelf Basin: Implications for Depositional Environments and Sequence Stratigraphy Controls

AbstractGas‐bearing deposits in the Lower Mingyuefeng Formation of Paleogene, Lishui Sag, East China Sea Shelf Basin consist of shoreface sandstones of the highstand systems tract (HST) and transgressive systems tract (TST), and deltaic sandstones of the lowstand systems tract (LST) and falling stage systems tract (FSST). Detailed petrographic observations suggest that the diagenetic features and related evolution of these deposits cannot be simply characterized and demonstrated in the depth domain. However, the occurrence of diagenetic minerals systematically depends on the studied interval within the HST, TST, LST, and FSST; therefore, diagenesis in this region can be better constrained when studied in the context of the depositional environments and sequence stratigraphic framework. The eogenetic processes in such settings include: (1) microcrystalline siderite precipitated as concretions in almost all environments and systems tracts, which inhibited further mechanical compaction; (2) grain dissolution and kaolinitization occurred in shoreface HST sandstones and deltaic LST and FSST sandstones; (3) glaucony was locally observed, which did not clearly reflect the controls of facies or sequence stratigraphy; and (4) cementation by pyrite aggregates occurred in the shoreface HST sandstones and deltaic LST sandstones. The mesogenetic diagenesis includes: (1) partial conversion of kaolinite into dickite in deltaic LST sandstones, and minor chlorite cementation in deltaic FSST sandstones; (2) transformation of kaolinite into illite and quartz cementation in deltaic LST and FSST sandstones; (3) frequent precipitation of ankerite and ferroan calcite in shoreface TST sandstones and early HST sandstones, forming baffles and barriers for fluid flow, with common calcite in shoreface HST sandstones as a late diagenetic cement; and (4) formation of dawsonite in the deltaic LST and FSST sandstones, which is interpreted to be a product of the invasion of a CO2‐rich fluid, and acts as a good indicator of CO2‐bearing reservoirs. This study has thus constructed a reliable conceptual model to describe the spatial and temporal distribution of diagenetic alterations. The results may provide an entirely new conceptual framework and methodology for successful gas exploration in the continental margins of offshore China, thus allowing us to predict and unravel the distribution and quality evolution of clastic reservoirs at a more detailed and reliable scale.

Acid fluids reconstruction clastic reservoir experiment in Qaidam saline lacustrine Basin, China

The Qaidam Basin is a large salt lake basin on the Tibetan Plateau where oil and gas flow has recently been discovered in lacustrine clastic reservoir; the organic acids released during the evolution of organic matter in saline lacustrine basins could improve reservoirs in certain cases. The alteration of clastic rock reservoirs by the acid fluids is a complicated physical and chemical process. This experiment simulated interactions between the organic acids and the minerals in reservoir rocks in underground temperature and pressure conditions, and analyzed the influences of interactions on pore properties and pore structures and their formation mechanisms. These influences and alterations are divided into dissolution and precipitation interactions. Feldspar, gypsum, ankerite are likely to be dissolved, and calcite can be precipitated by weakly acidic solutions, which occupies some reservoir space. For the gypsum-containing clastic reservoirs, gypsum is more likely to be dissolved and the supersaturated Ca2+ generated with gypsum dissolution leads to the precipitation of calcite. The chemical process of ankerite dissolution provides iron ions and magnesium ions to the chlorite forming reaction and the chlorite can easily block the pore throats, leading to decline of permeability.

Sedimentary facies and lithologic characters as main factors controlling hydrocarbon accumulations and their critical conditions

Taking more than 1000 clastic hydrocarbon reservoirs of Bohai Bay Basin, Tarim Basin and Junggar Basin, China as examples, the paper has studied the main controlling factors of hydrocarbon reservoirs and their critical conditions to reveal the hydrocarbon distribution and to optimize the search for favorable targets. The results indicated that the various sedimentary facies and lithologic characters control the critical conditions of hydrocarbon accumulations, which shows that hydrocarbon is distributed mainly in sedimentary facies formed under conditions of a long-lived and relatively strong hydrodynamic environment; 95% of the hydrocarbon reservoirs and reserves in the three basins is distributed in siltstones, fine sandstones, lithified gravels and pebble-bearing sandstones; moreover, the probability of discovering conventional hydrocarbon reservoirs decreases with the grain size of the clastic rock. The main reason is that the low relative porosity and permeability of fine-grained reservoirs lead to small differences in capillary force compared with surrounding rocks small and insufficiency of dynamic force for hydrocarbon accumulation; the critical condition for hydrocarbon entering reservoir is that the interfacial potential in the surrounding rock (Φn) must be more than twice of that in the reservoir (Φs); the probability of hydrocarbon reservoirs distribution decreases in cases where the hydrodynamic force is too high or too low and when the rocks have too coarse or too fine grains.

Innovation and prospect of geophysical technology in the exploration of deep oil and gas

Abstract The global situation of distribution, reserves and production of deep oil and gas are examined systematically, the progress and exploration achievement of onshore China deep geophysical technology are summarized, and the challenges and developing direction of deep geophysical technology are pointed out. Aiming at the exploration of deep onshore strata in China, the article analyzes the key geophysical problems, such as low signal-to-noise ratio, low resolution, low imaging accuracy and low amplitude-preservation, in the exploration of deep clastic, carbonate, and volcanic reservoirs, and presents the corresponding technical countermeasures such as wide-line large-array 2-D acquisition, wide-azimuth and high-density 3-D acquisition, anisotropic pre-stack depth migration (PSDM), reverse-time migration (RTM), complex structure modeling, and quantitative reservoir prediction. The analysis from two aspects, imaging of deep complicated structures and prediction of deep complicated reservoirs, shows that wide-frequency, amplitude-preservation, high-accuracy and information integration are the challenges to and key issues in the geophysical technology. It is pointed out that wide-frequency seismic acquisition, rock physical modeling of complex reservoirs, high-accuracy prestack amplitude-preservation imaging, comprehensive evaluation of complex reservoirs, non-seismic techniques, and drilling steering with seismic data are the key geophysical techniques needed to be developed in the future.

Petrophysical analysis of a clastic reservoir rock: a case study of the Early Cambrian Khewra Sandstone, Potwar Basin, Pakistan

The Khewra Sandstone is widely distributed throughout the Potwar Basin of Pakistan. Its reservoir aspects are evaluated by the interpretation of well log data recorded from Kal-01 and Kal-02 wells in the Kal Oil Field, eastern Potwar Basin. The encountered thickness of the Khewra Sandstone in Kal-01and Kal-02 varies from 60 m to 120 m. On the basis of lithological interpretation from wireline logs the formation is divided into four facies: 1) shale interbedded with minor siltstone and sandstone, 2) sandstone with alternating siltstone and claystone/shale, 3) claystone/shale, siltstone interbedded with fine to medium grained sandstone and 4) fine to coarse grained sandstone with channels. The log derived average porosity in Khewra Sandstone is about 14–22% with permeability ranges from 20–58 mD. Thus, it possesses a large storage capacity for moveable hydrocarbons in Kal Oil Field. Facies 4, in the upper part of the Khewra Sandstone, is interpreted as potential reservoir interval with hydrocarbon saturation ranges from 77–79%. Based on isopach map, the formation is interpreted to be well developed in NE-SW which gradually thins basinward to the west and northwest direction. The play fairway analysis suggested very high chances of hydrocarbon entrapment is in the Kal Oil Field.

Petro-Elastic Log-Facies Classification Using the Expectation–Maximization Algorithm and Hidden Markov Models

Log-facies classification methods aim to estimate a profile of facies at the well location based on the values of rock properties measured or computed in well-log analysis. Statistical methods generally provide the most likely classification of lithological facies along the borehole by maximizing a function that describes the likelihood of a set of rock samples belonging to a certain facies. However, most of the available methods classify each sample in the well log independently and do not account for the vertical distribution of the facies profile. In this work, a classification method based on hidden Markov models is proposed, a stochastic method that accounts for the probability of transitions from one facies to another one. Differently from other available methods where the model parameters are assessed using nearby fields or analogs, the unknown parameters are estimated using a statistical algorithm called the Expectation–Maximization algorithm. The method is applied to two different datasets: a clastic reservoir in the North Sea where four litho-fluid facies are identified and an unconventional reservoir in North America where four lithological facies are defined. The results of the applications show the added value of the introduction of a vertical continuity model in the facies classification and the ability of the proposed method of inferring model parameters such as facies transition probabilities and facies posterior distributions. The application also includes a sensitivity analysis and a comparison to other statistical methods.

Reservoir characterization of the Lower Abu Madi Formation using core analysis data: El-Wastani gas field, Egypt

The Messinian (Upper Miocene) sandstones of the Lower Abu Madi unit are the main reservoirs of the El-Wastani (EW) gas field, located in the onshore Nile Delta of Egypt. Reservoir quality is highly variable and represents the major risk in locating new delineation and development wells in the field. Four lithofacies (F1, F2, F3 and F4) are characterized based on textural attributes and sedimentary structures. Facies F4, which is a medium to coarse-grained fluvial channel sandstone, exhibits the best reservoir rock quality. Four hydraulic flow units (HFU 1 through HFU 4) were delineated in the studied wells with flow zone index (FZI) values indicative of a broad range of hydraulic properties. The cementation factor (m) value, was calculated from the inverse relationship between porosity and formation factor for EW-4 and EW-6 wells, agrees with the published values of clean sandstone reservoirs. The results of grain density analyses is close to the published value of grain density of quartz, and also supported by the results of petrographic study, where quartz is the dominant framework mineral. Generally, both the permeability and porosity can be linked to the two derived electrical properties (formation resistivity factor and electrical tortuosity) in the clastic reservoirs of the Lower Abu Madi unit. This correlation is particularly evident in the western and central parts of the study area at EW-4 and EW-6 wells, where facies F4 is dominant.

Thermal Analysis: A Complementary Method to Study the Shurijeh Clay Minerals

Clay minerals are considered the most important components of clastic reservoir rock evaluation studies. The Shurijeh gas reservoir Formation, represented by shaly sandstones of the Late Jurassic-Early Cretaceous age, is the main reservoir rock in the Eastern Kopet-Dagh sedimentary Basin, NE Iran. In this study, X-ray diffraction (XRD), X-ray fluorescence (XRF), scanning electron microscopic (SEM) studies, and thermal analysis including differential thermal analysis (DTA), and thermogravimetric analysis (TGA) techniques were utilized in the characterization of the Shurijeh clay minerals in ten representative samples. The XRF studies showed that silica and aluminum oxides are present quantities. The XRD test was then used to determine the mineralogical composition of bulk components, as well as the clay fraction. The XRD patterns indicated the presence of dominant amount of quartz and plagioclase, with moderate to minor amounts of alkali feldspar, anhydrite, carbonates (calcite and dolomite), hematite and clay minerals. The most common clays in the Shurijeh Formation were illite, chlorite, and kaolinite. However, in very few samples, glauconite, smectite, and mixed layer clay minerals of both illite-smectite and chlorite-smectite types were also recognized. The XRD results were quantified, using the elemental information from the XRF test, showing that each Shurijeh exhibited low to moderate amounts of clay minerals, typically up to 21%. The amount of illite, the most dominant clay mineral, reached maximum of 13.5%, while the other clay types were significantly smaller. Based on the use of SEM and thermal data, the results of the identification of clay minerals, corresponded with the powder X-ray diffraction analysis, which can be taken into account as an evidence of the effectiveness of the thermal analysis technique in clay typing, as a complementary method besides the XRD.

Hydrocarbon-induced diagenetic alteration of the Permian White Rim Sandstone, Elaterite Basin, southeast Utah

The Permian White Rim Sandstone is a partly exhumed, primary reservoir of the Tar Sand Triangle accumulation in southeastern Utah. In the Elaterite Basin (Canyonlands National Park and Glen Canyon National Recreation Area), the White Rim Sandstone is well exposed and varies in color from white to red, orange, and brown. Superimposed on eolian and marine deposits are three diagenetic facies that impart the coloration and are defined by iron oxide cement concentration as (1) bleached white (low iron), (2) diffuse (moderate iron), and (3) concretionary (concentrated iron). A yellow alteration aureole of bleaching extends up to 10 m (32 ft) into the underlying Organ Rock Shale and up to 20 m (65 ft) into the overlying Moenkopi Formation. These formations surround the White Rim reservoir as fine-grained seals. Field, petrographic, and geochemical analyses indicate that the White Rim Sandstone records three major diagenetic stages. (1) The reservoir underwent oxidation, which led to the precipitation of thin iron grain coatings. (2) Hydrocarbon migration through the reservoir removed early grain coatings and reprecipitated disseminated and concentrated pyrite cement. (3) The pyrite was later altered to hematite or goethite by oxidizing fluids. In conventional petroleum exploration, the timing of hydrocarbon migration is often difficult to resolve. This study utilizes the record of mobilized and reprecipitated iron as a tool to constrain interpretations of the timing of hydrocarbon migration relative to seal and trap emplacement. This study has broad application as an exploration tool for deciphering fluid flow in similar clastic reservoirs.

Genetic unit averages of pseudo-normalized pore throat radius for improved permeability predictions (Niger Delta as case study)

Recent studies in permeability modeling demonstrate a relationship between measured permeability and normalized pore throat radius $$ \overline{{R_{\text{tot}} }} $$ that can be used as a predictor over six (6) orders of magnitude in permeability for the clastic reservoirs using Niger Delta dataset. The practical significance of this relationship indicates that the response variable (core permeability) is strictly valid within the confidence interval: 0.005 ≤ $$ \overline{{R_{\text{tot}} }} $$ (µm) ≤ 10. The proposed model was validated extensively exhibiting an excellent correlation coefficient and statistical significance as depicted by their p and t tests. A major input parameter for the proposed $$ \overline{{R_{\text{tot}} }} $$ permeability model is the pore throat radius at any given pressure step (R pi ). This is an intrinsic component of capillary pressures obtained from mercury injection capillary pressures (MICP) test. The proposed model is hampered due to unavailability of MICP dataset for all wells drilled to generate the R pi parameter. This paper seeks to develop genetic unit averages of pseudo-normalized pore throat radius as input parameter to the $$ \overline{{R_{\text{tot}} }} $$ proposed model for improved permeability modeling. We also present an upscaling from core plug scale to well log scale–pseudo normalized pore throat radius for application in uncored well intervals for various depositional environments within the study area. The statistical significance of the coefficient of the proposed model depicts the sample statistic to be too unlikely to have occurred by chance, with their p values strictly below the α level of 0.05. The proposed model validation indicates an excellent adjusted correlation coefficient and lower errors based on analysis of variance (ANOVA) using approximately 1000 routine core and well log dataset from the four distinct environments of deposition.

Evolution of deepwater sedimentary environments and its implication for hydrocarbon exploration in Qiongdongnan Basin, northwestern South China Sea

Over the past several years, a number of hydrocarbon reservoirs have been discovered in the deepwater area of Qiongdongnan Basin, northwestern South China Sea. These oil/gas fields demonstrate that the evolution of the deepwater sedimentary environment are controlling the formation and distribution of large-scale clastic reservoirs. Integration between seismic and borehole data were necessary to best clarify the distribution and quality of these deepwater reservoirs. Geochemical and paleobiological evidence from discrete samples was also applied to document specific information regarding the sedimentary environment. Results show that the Qiongdongnan Basin has existed as a thriving marine environment since Oligocene, when several rifting depressions developed throughout the entire Qiongdongnan Basin. Triggered by the faults activities, several distinct provenances supplied the coarse sediments, transporting and depositing them in deep parts of the rifting depressions. A fan delta system then formed nearby the source in the deeper area of these rifting depressions. The sedimentary environment of Qiongdongnan gradiationally became deepwater since early Miocene. Consequently, abundances of sediments were transported from Hainan Island and Southern Uplift, and then sunk into the basin center. The submarine fans revealed by many boreholes in this area verified them as good reservoir. Because the area reached its lowest sea level at late Miocene and the Southern Uplift subsidenced under sea level, not providing any sediment, so that the carbonate mesa and biorhythms characteristic of this area also developed during this period. In the west part of Qiongdongnan Basin, sediments transported from Vietnam increased in response to the Tibetan Uplift. Consequently, a central canyon developed along the center of Qiongdongnan Basin, which has been confirmed by several boreholes as a favorable hydrocarbon reservoir. The clarification of the deepwater sedimentary environment’s evolution is potentially highly beneficial to future hydrocarbon exploration in the deepwater area of Qiongdongnan Basin.

The discovery of the Barmer Basin, Rajasthan, India, and its petroleum geology

The discovery of oil and gas in the Barmer Basin in northwest India was one of the more significant global discoveries in the decade 2001–2010. The basin’s presence was suspected from gravity and magnetic data in the late 1980s but not confirmed until 1999 from seismic and drilling. The basin is a lacustrine failed rift. Biostratigraphic data, however, indicate it was intermittently connected to marine waters via either the Cambay Basin, the Kutch Basin, or across the Devikot high, temporarily forming a large, shallow estuary. At least six major tectono-stratigraphic events have caused relative lake level falls and translation of clastic reservoirs basinward. Upward of 6 km (∼20,000 ft) of Cenozoic and Mesozoic sedimentary rocks have been preserved. Prolific source rocks occur from the Mesozoic through Eocene strata. Tectonically, the basin is divided into a northern and a southern province. The north province continues to undergo inversion and erosion, and has not been buried as deeply as the south. Kinetics of the major source facies in the north are substantially different from those in the south, as well as the present-day and paleo-heat flow. These differences have made the northern part of the basin predominantly an oil province and the southern part a mixed oil and gas province. The prolific Paleocene Fatehgarh Formation contains the bulk of the 7.3 billion barrels of stock tank oil in place (STOIP) identified to date, but other reservoirs from the Mesozoic to the late Cenozoic are common and may yield significant future resource additions.

Assessing the Water Migration and Permeability of Large Intact Bituminous and Anthracite Coals Using NMR Relaxation Spectrometry

Although extensive literature has emerged on the use of nuclear magnetic resonance (NMR) relaxation spectrometry for the determination of various petrophysical properties of clastic rocks, relatively few papers have reported the use of NMR to determine the moisture migration process and permeability of large intact coals. In this study, evaporation experiments simultaneously with NMR measurements were conducted for seven coal core plugs. Differences in the relaxation time distribution at the various saturation stages provide both qualitative and quantitative information on the saturation state and migration of moisture in the coal samples. Moisture migration accrues first in the larger pores, whereas the smaller pores appear to remain water-saturated. The evaporation of moisture in large intact coals undergoes three continuous processes: Migration of free water, macro-capillary water, and micro-capillary water, among which, the migration rates of both macro-capillary water and micro-capillary water are related to the coal pore size distribution and porosity. The results of the NMR measurements also indicate that coal permeability has a relationship with the moisture migration characteristics, which make it possible to develop an NMR-derived permeability model. The Timur–Coates and the Schlumberger-Doll Research (SDR) equations, which are commonly used in NMR logging evaluations of the permeability of clastic rock reservoirs, were discussed concerning their application to coals. It is found that a modified SDR permeability evaluation model $$[K_\mathrm{SDR}=0.0224(\hbox {T}_\mathrm{2gm}^\mathrm{b})^{0.182}(\hbox {T}_\mathrm{2gm}^\mathrm{a})^{1.534}]$$ , which is a double-exponential relationship with the $$T_{2}$$ geometric mean in the full water-saturated state and in the bound water state, fits the analyzed coal samples well. The NMR-derived methods provide a framework for the determination of the moisture migration and permeability of coals.

Technologies that have transformed the Exmouth into Australia

The oil and gas fields of the Exmouth Sub-basin, offshore WA, have presented a number of significant challenges to their exploitation since the first discoveries of heavy oil and lean gas were made in the late 1980s and early 1990s. Presently, some 20 oil and gas fields have been discovered in a variety of Late Jurassic to Cretaceous clastic reservoirs from slope turbidites to deltaic sands. Discovered oils are typically heavily biodegraded with densities ranging from 14–23° API and moderate viscosity. Seismic imaging is challenging across some areas due to pervasive multiples and gas escape features, while in other areas resolution is excellent. Most reservoirs are poorly cemented to unconsolidated and thus require sand control. Modest oil columns, most with gas caps, and variable permeability, present challenges for both maximising oil recovery and minimising the influx of water and gas. Oil-water emulsions also present difficulties for both maximising oil rate and metering production. To date, more than 300 MMbbls have been produced from five developments (Enfield, Stybarrow, Vincent, Van Gogh and Pyrenees), and in 2013 the Macedon gasfield began production. This peer-reviewed paper focuses on the variety of technologies—geoscience, reservoir, drilling and production—that have underpinned the development of these challenging fields and in doing so, transformed the Exmouth into Australia’s premier oil producing basin.