Variations In Reservoir Quality Research Articles

The joint controls of tectonism, sedimentation and diagenesis on reservoir quality in the East China Sea Basin

Variation in reservoir quality is especially important in low-permeability and tight sandstone reservoirs. By using log, seismic and core test data, we developed a method that uses tectonism, sedimentation and diagenesis to evaluate sweet spot distribution of the third (Mbr 3), fourth (Mbr 4) and fifth (Mbr 5) members of the Oligocene Huagang Formation in the Xihu Depression, East China Sea Basin. Sweet spot maps of the Mbr 3, Mbr 4 and Mbr 5 sandstone reservoirs were compiled by superposing tectonic locations, depositional microfacies and diagenetic facies. Sweet spots were classified into three types. Mbr 3 exhibits type I and type II sweet spots, Mbr 4 exhibits type I, type II and type III sweet spots, and Mbr 5 exhibits type II and type III sweet spots. In the Oligocene, tectonism and climatic controlled the depositional microfacies, sandstone grain size and clastic composition of the Mbr 5, Mbr 4 and Mbr 3 members, which were deposited in a braided river delta setting that ranged from delta-front distal part to proximal part. From late Oligocene to present, along with depositional microfacies, diagenetic stage, diagenetic facies and reservoir properties, the joint control of tectonism, sedimentation and diagenesis determined the distribution of diagenetic facies, and was used to develop a synthetic pattern for reservoir quality variation.

Target-based sedimentary diagenesis simulation and three-dimensional diagenesis evolution modeling

Deposition and diagenesis are important factors affecting the quality of oil and gas reservoirs. Previously reported diagenesis studies mainly involve qualitative analysis, such as the determination of diagenetic events and diagenetic evolution sequences and modeling of two-dimensional diagenetic evolution, with less effort devoted to quantitative numerical simulation and three-dimensional diagenetic evolution models. This study proposes a new method for target-based diagenesis simulation by integrating the discrete element method, the quartet structure generation set method, and morphological algorithms. This new hybrid method can quantitatively simulate the effects of mineral grain deposition, compaction, cementation, dissolution, and replacement. Since specific minerals can undergo specific diagenetic alterations through mineral labeling, the sequence and path of diagenesis can be predefined in this method. Taking the sandstone reservoir of Lower Member 3 of the Shahejie Formation in Linnan Sag, Huimin Depression, Bohai Bay Basin, East China as an example, the new simulation method used the constructed diagenetic evolution sequence based on thin section identification and geochemical analysis to systematically simulate deposition and diagenesis in the study area and to construct a three-dimensional diagenetic evolution model. The predicted porosity, permeability, and pore size distribution of the simulated digital rocks are in good agreement with the experimental values, which validates the high accuracy of the simulation method. Based on these three-dimensional multi-mineral evolution models, the evolution trends of porosity and permeability during the sedimentation and diagenesis process were elucidated, revealing the variation in reservoir quality in the studied area and indicating reservoir sweet spots. The constructed 3D diagenesis evolution models are widely applicable and can be used not only for permeability simulation but also for the study of electrical, acoustic, and mechanical properties of reservoirs.

Integrated Core and Log Data to Determine the Reservoir Flow Unit and Rock Facies for Mishrif Formation in South Eastern Iraq

This work represents study the rock facies and flow unit classification for the Mishrif carbonate reservoir in Buzurgan oil Field, which located n the south eastern Iraq, using wire line logs, core samples and petrophysical data (log porosity and core permeability). Hydraulic flow units were identified using flow zone indicator approach and assessed within each rock type to reach better understanding of the controlling role of pore types and geometry in reservoir quality variations. Additionally, distribution of sedimentary facies and Rock Fabric Number along with porosity and permeability was analyzed in three wells (BU-1, BU-2, and BU-3). The interactive Petrophysics - IP software is used to assess the rock fabric number, flow zones, and reservoir quality index. The Mishrif Formation has four distinct rock types and groups that have been recognized using the approach. The first rock type represents a poor reservoir quality (mud-dominated fabrics) with rock-fabric numbers equals to 2.5-4, the second rock type reveals a moderate reservoir quality (wackestone-Packstone Microfacies), the third rock type depicts a good reservoir quality (grain-dominated packstone) with rock-fabric numbers equals to 1.5-2.5 and 0.5-1.5.

Carbonate Reservoir Quality Variations in Basins with a Variable Sediment Influx: A Case Study from the Balkassar Oil Field, Potwar, Pakistan.

The carbonate reservoir quality is strongly reliant on the compaction process during sediment burial and other processes such as cementation and dissolution. Porosity and pore pressure are the two main factors directly affected by mechanical and chemical compactions. Porosity reduction in these carbonates is critically dependent on the overburden stress and subsidence rate. A variable sediment influx in younger basins may lead to changes in the reservoir quality in response to increasing lithostatic pressure. Deposition of molasse sediments as a result of the Himalayan orogeny caused variations in the sedimentation influx in the Potwar Basin of Pakistan throughout the Neogene times. The basic idea of this study is to analyze the carbonate reservoir quality variations induced by the compaction and variable sediment influx. The Sakesar Limestone of the Eocene age, one of the proven carbonate reservoirs in the Potwar Basin, shows significant changes in the reservoir quality, specifically in terms of porosity and pressure. A 3D seismic cube (10 km2) and three wells of the Balkassar field are used for this analysis. To determine the vertical and lateral changes of porosity in the Balkassar area, porosity is computed from both the log and seismic data. The results of both the data sets indicate 2-4% porosities in the Sakesar Limestone. The porosity reduction rate with respect to the lithostatic pressure computed with the help of geohistory analysis represents a sharp decrease in porosity values during the Miocene times. Pore pressure predictions in the Balkassar OXY 01 well indicate underpressure conditions in the Sakesar Limestone. The Eocene limestones deposited before the collision of the Indian plate had enough time for fluid expulsion and show underpressure conditions with high porosities.

Lamina Variation and Its Relationship with Sedimentary Facies in Alkaline Lacustrine, Permian Fengcheng Formation, Junggar Basin, Northwest China.

The Permian Fengcheng Formation in the Mahu Sag was deposited in a volcanic-alkaline lacustrine evaporative environment and contains a unique variety of fine-grained sediments. This study examines, at a millimeter-scale, the influence of sedimentary microfacies on variability of lamina quality in fine-grained sediments in the second member of the Fengcheng Formation (P1f2). The methods used include thin-section identification, X-ray diffraction (XRD), X-ray fluorescence (XRF), scanning electron microscopy (SEM), nitrogen adsorption, and nuclear magnetic resonance (NMR). Six types of lamina were identified in two different lithofacies: fan-delta front facies (FDFF) and semideep/deep lacustrine facies (SDDLF). The laminae in FDFF are predominantly feldspar-quartz laminae (FQL), reedmergnerite laminae (RL), shortite laminae (SL), alkaline mineral laminae (AML), and chert laminae (CL). The laminae in SDDLF are predominantly FQL, RL, SL, CL, and dolomite laminae (DOL). Variations in reservoir quality, oil-bearing properties, and the fracability of laminae in different sedimentary facies are determined by the combined effects of lamina density, mineral composition, rock structure, organic matter abundance, and microfractures. Analysis of these factors indicates superior reservoir qualities in FDFF. In SDDLF, the pore structure is limited by high lamina density, chert content, and fine grain size with the NMR porosities of FQL, RL, SL, and CL being 1.32, 0.18, 0.84, and 0.39%, respectively. However, in FDFF, the combination of high organic matter content, feldspar, pyrite, and clay minerals has a superior effect on the organic matter and minerals deposited resulting in better pore structure and more storage space for shale oil. The NMR porosities of FQL, RL, SL, and CL are 2.81, 2.53, 1.80, and 1.12%, respectively. Overall, analysis of lamina variations and their relationships with sedimentary facies indicates that the reservoir in FDFF may offer more favorable targets for "sweet spot" evaluation.

Evolution and controls of high reservoir quality in Oligocene sandstones from moderate to deep burial, Nanpu Sag, Bohai Bay Basin, China

The Oligocene sandstones characterized by highly variable reservoir quality are the main hydrocarbon exploration and development targets in the Nanpu Sag, Bohai Bay Basin, China. In this study, the evolution and controls of reservoir quality in Oligocene sandstones from moderate to deep burial were investigated using petrographic and petrological data. The results show that the Oligocene sandstones are mostly fine-to coarse-grained, subangular to subrounded roundness, moderately sorted feldspathic litharenites and lithic arkoses with an average Q/F/R distribution of 48.4: 29.1: 22.5. Three anomalously high porosity/permeability zones (AHPZs, hereinafter named AHPZ-I, AHPZ-II, and AHPZ-III, respectively) are developed at depth ranges of 2300–3100 m, 3200–3550 m, and 3700–4200 m, respectively. Notably, the three zones are featured by distinctly different pore types: mainly primary pores in AHPZ-I; pore combination (average primary pore volume > average secondary pore volume) in AHPZ-II; primary pores with a few microfractures in AHPZ-III. The pore-throat sizes controlling permeability in anomalously high porosity sandstones (AHPS) decrease steadily from AHPZ-I to AHPZ-III-1 and then increase significantly at AHPZ-III-2. The AHPS reservoirs are characterized by low displacement pressure, large pore throat and mercury intrusion saturation, and high free fluid index (FFI) and reservoir quality index (RQI).Compaction greatly degraded the reservoir quality of Oligocene sandstones; carbonate cementation further restricts the formation of high-quality reservoirs. The sandstones with low content (<10 %) of carbonate cements tend to have larger primary porosity and secondary porosity, hence a larger RQI. The formation of AHPZ-I and AHPZ-II is attributed to higher content of rigid particle components, lower carbonate cements, and strong dissolution. Moreover, good sorting, responsible for a higher original porosity, also plays a positive role in the cause of AHPZ-I. The coarse-grained particles and early petroleum emplacement are the keys to the preservation of primary porosity in AHPZ-III. The petroleum emplacement effectively inhibits the feldspar dissolution and kaolinite precipitation in the deeply buried sandstones with depths larger than 4000 m. In addition, the generation of crushed microfractures in coarse grains leads to relatively low porosity and high permeability.

Evaluation of low permeability conglomerate reservoirs based on petrophysical facies: A case study from the Triassic Baikouquan Formation, northern Mahu Sag, Junggar Basin, China

The determination of high-quality intervals in oil reservoirs has always been challenging work while their petrophysical attributes are relatively low. To date, extensive reservoir evaluation studies have been undertaken to locate favorable zones for oil exploration and exploitation. However, without the geological constraint principles, the selected evaluation parameters depend heavily on experience or pure mathematical methods. Hence, we propose a reservoir evaluation method based on petrophysical facies to undertake the reservoir quality assessment for the conglomerate reservoirs of the Triassic Baikouquan Formation in the northern Mahu sag, Junggar Basin, western China. The lithofacies and diagenetic facies were first identified based on laboratory data. Subsequently, petrophysical facies types were recognized by the combination of lithofacies and diagenetic facies. Afterward, capillary pressure curves of different petrophysical facies were clustered to clarify the reservoir quality variation in distinct geological origins. Consequently, the evaluation standard was established and the reservoir quality distribution was analyzed and drawn out. These results indicate that there exist 4 rock types in the Baikouquan Formation (from RT1 to RT4). The distributional status of the optimal reservoir (RT1) and the worst reservoir (RT4) are primarily determined by grain size, while rock type 2 (RT2) and rock type 3 (RT3) are predominantly controlled by dissolution and compaction. Moreover, an evident positive association exists between the rock type and the single well production capacity, which reveals that the utilization of petrophysical facies to assess reservoir quality is reliable. It is concluded that reservoir evaluation based on petrophysical facies harbors the potential to be a pivotal tool for reservoir property assessment and prediction of favorable porosity and permeability zones.

Regional variations in Archie parameters and reservoir quality of Bahariya Formation at North Western Desert, Egypt

Regional variations in Archie parameters and reservoir quality of Bahariya Formation at North Western Desert, Egypt

Controls on reservoir quality of the Nanushuk Formation (Albian–Cenomanian), North Slope, Alaska

Recent hydrocarbon discoveries in the Albian–Cenomanian Nanushuk Formation on the North Slope of Alaska have revived interest in exploration of the Colville basin. The Nanushuk forms a segment of the Brookian sequence and together with the genetically related Torok Formation comprises part of a giant clinothem filling the western two-thirds of the basin. It consists of a succession of intertonguing marine and nonmarine strata interpreted as marine shelf, deltaic, strandplain, and fluvial deposits. Deposition occurred in two deltaic complexes, one sourced from large drainage basins extending west of present-day Arctic Alaska, the other from smaller catchment areas with headwaters in the ancestral Brooks Range to the south.The Nanushuk Formation consists of medium- to very fine-grained lithic sandstone and siltstone comprised largely of monocrystalline and polycrystalline quartz, chert, and argillaceous sedimentary and metasedimentary rock fragments. With progressive burial and compaction, ductile deformation of the argillaceous detritus is the principal mechanism of porosity and permeability loss in the sandstone. Cements are a minor component and have minimal effect on diagenesis of the strata. Reservoir quality varies extensively across the North Slope and understanding the factors controlling reservoir potential is a critical aspect of recent exploration programs.Two groups of sandstone are recognized based on differences in reservoir quality: a low-porosity group with maximum porosity less than 20 percent, and a high-porosity group with higher porosity values for a given permeability and maximum porosity exceeding 30 percent. Variation in reservoir quality within each group is delimited by depositional texture which is a primary, local control. The disparity between the groups results from differences in the maximum burial depth (Dmax) the rocks experienced which is a secondary, regional control. Linear regression models for porosity–Dmax and permeability–Dmax relations enable forecasting the reservoir potential of sandstone and siltstone containing only minor cement.

Scale discrepancy paradox between observation and modelling in fractured reservoir models in oil and gas industry

AbstractThe appraisal and development of fractured reservoirs are challenging tasks because of the combined variations in reservoir quality and natural fracture distribution. Fracture models are built routinely to support both appraisal and development decisions for such reservoirs. One of the key objectives of these models is to generate three-dimensional (3D) fracture properties for dynamic flow simulations. In this paper, we illustrate the discrepancy between the scale of observation required to build a thorough geological understanding of the subsurface and the simplification imposed by modelling. We use a case study carried out in the context of an exploration campaign of a Cretaceous carbonate reservoir in Egypt. After describing the regional geological setting of the area, we share a series of detailed observations on open-hole logs, cores, thin-sections and borehole images. These observations are focused on reservoir architecture, fracture typology and fracture connectivity. Observations are then integrated with the regional geological context to build a conceptual fracture model and to characterize the uncertainty affecting the essential parameters of this model. The conceptual model, combined with 3D seismic data, is used to define a fracture modelling strategy. This strategy includes a drastic simplification of the conceptual model to generate 3D discrete fracture network scenarios that are calibrated using pressure communication data from the exploration wells. Another extreme simplification is then necessary to populate 3D simulation grids. In the case study presented, the key tuning parameters to obtain a dynamic match are the grid cell orientation and the width of the modelled fault damage zone.

Quality variations and controlling factors of deepwater submarine-fan reservoirs, Rovuma Basin, East Africa

The mechanisms causing quality variations and key control factors of submarine-fan reservoirs in the gas field X of the Rovuma Basin, East Africa are analyzed based on core and well-log data in this paper. Depositional fabric, lithofacies difference and characteristics of genetic units are the fundamental reasons of reservoir quality variations. In the case of weak cementation, porosity and permeability of submarine-fan reservoirs are controlled by grain sorting and clay content, respectively. Reservoir quality variations for 5 main lithofacies are related to variable depositional fabrics and calcite cementation. Among them, massive medium-coarse sandstones with weak cementation have the highest porosity and permeability, and coarser or finer sandstones have poorer reservoir quality. The existence of bottom current can develop laminated sandstones, improving the pore structure and physical properties greatly. Lithofacies vary among different types, locations and stages of genetic units, and they control the distribution patterns of submarine-fan reservoir quality: the physical properties of channel shaft or lobe main body are better than those of the channel or lobe edge. The sandstone sorting and physical properties are gradually improved from near-source to far-source. When multi-stage sand bodies are superimposed, the sand-mud ratio in the later stage is higher than that in the earlier stage, making the physical properties get better in the later stage.

Subtle reservoirs and implications for hydrocarbon exploration in terrestrial lacustrine fan-delta deposits: Insights from the Triassic Baikouquan Formation, Mahu Sag, Junggar Basin, western China

Petroleum reserves are abundant in the large-scale lacustrine fan delta reservoirs containing mixed oil in the Baikouquan Formation (MA131 Block, Junggar Basin). However, detecting such subtle reservoirs in the lacustrine foreland basins is challenging. High-resolution sequence stratigraphy, sedimentary basin evolution, and reservoir models are established by integrating the results obtained via wireline log data, cores, thin sections, and seismic data. A fifth-order sequence stratigraphic framework for the Baikouquan Formation is established, which enables the reconstruction of the sedimentary basin evolution and further detailing of the reservoir model, such that the correlation to multistage progradation and retrogradation of the fan delta complex can be determined. The study of core samples led to the identification of eight microfacies, of which sandy debris flows and distributary channels dominate approximately 80% of the depositional system. Stratal slices enable the characterization of the northern Xiazijie and eastern Madong fan-delta systems. The northern Xiazijie fan delta is widely distributed throughout sequences SSQ1–SSQ6, whereas the Xiazijie fan delta underwent, in general, gradual retrogradation during the formation of sequences SSQ6 and SSQ7. The eastern Madong gravity flow fan-delta system only developed during the formation of sequences SSQ1–SSQ5 at the location of an abrupt slope break. There are nine categories of reservoir models in the study area based on the source rocks, faults, and reservoirs. Geomorphology and climate are crucial in controlling the sedimentary infill. Deep faults and an unconformity between the Permian and the Triassic of the Mahu Sag played a decisive role in controlling the hydrocarbon migration pathways. The faults, source rocks, and microfacies together exert considerable control on hydrocarbon accumulation. Within the nearshore fan-delta front, variable reservoir quality can be observed. Crucial factors in improving reservoir quality are fine-grain size and relatively low clay content. This study may facilitate subtle reservoir characterization in other basins.

Enhancing subsalt imaging through advanced identification and suppression of interbed multiples and mode-converted reflections — Gulf of Mexico and Brazil case studies

In our case studies, the success of subsalt exploration and development wells depended heavily on the characterization of highly heterogeneous lacustrine microbial carbonates. Acoustic and elastic inversions have proved to be a good proxy for identification of reservoir quality variation for exploration and development well placements. However, qualitative and quantitative usage of subsalt seismic amplitudes requires proper illumination and good signal-to-noise ratio. If properly imaged, mode-converted reflections and interbed multiples can be complementary to the P-wave image. But, in conventional P-wave-oriented imaging, both types of events cannot be imaged correctly. They appear as coherent noise and negatively impact the overall exploration and development project outcomes, especially in areas with poor illumination. This paper consists of two parts: first, we investigate the potential problems resulting from converted waves and interbed multiples in data from two different basins — the Gulf of Mexico and the Campos Basin in offshore Brazil — and show our approach to attenuate them to reveal the true structures. The second part focuses on advanced identification of interbed multiples in modeling and migration methods. To facilitate the various strategies to attenuate interbed multiples, “interpretation” of the various events plays a significant role. Vertical seismic profile (VSP) data are excellent for the purpose; however, these data are only available at well locations, if they are recorded. As a result of many years of technology advancement, pseudo VSP data can be constructed effectively from standard streamer survey data. Two methods are highlighted in this paper for building pseudo VSP data in a full two-way sense, based on a typical Brazil-type salt model: Marchenko-based processing and full-wavefield migration. Major subsalt plays in the Gulf of Mexico and emerging plays in Brazil should benefit significantly from elimination of these kinds of coherent noise.

Determining reservoir intervals in the Bowland Shale using petrophysics and rock physics models

SUMMARY An evaluation of prospective shale gas reservoir intervals in the Bowland Shale is presented using a wireline log data set from the UK's first shale gas exploration well. Accurate identification of such intervals is crucial in determining ideal landing zones for drilling horizontal production wells, but the task is challenging due to the heterogeneous nature of mudrocks. This heterogeneity leads to stratigraphic variations in reservoir quality and mechanical properties, and leads to complex geophysical behaviour, including seismic anisotropy. We generate petrophysical logs such as mineralogy, porosity, and organic content and calibrate these to the results of core studies. If ‘reservoir quality’ is defined by combined cut-offs relating to these parameters, we find that over 100 m of reservoir quality shale is present in the well, located primarily within the upper section. To examine the link between geophysical signature and rock properties, an isotropic rock physics model is developed, using effective medium theories, to recreate the elastic properties of the shale and produce forward-looking templates for subsequent seismic inversion studies. We find that the mineralogical heterogeneity in the shale has a profound impact on modelled elastic properties, obscuring more discrete changes due to porosity, organic content and water saturation and that the best reservoir quality intervals of the shale bear a distinctive response on rock physics cross-plots. Finally, we consider the density of natural fractures in the shale by developing an anisotropic rock physics model to reflect high-angle fractures observed on micro-imagery logs. We invert crack density using shear wave splitting well log data and find a crack density of up to 4 per cent which correlates well with micro-imagery observations. Our work further supports previous authors’ core-based studies in concluding that the Bowland Shale holds good reservoir characteristics, and we propose that there are multiple intervals within the shale that could be targeted with stacked horizontal wells, should those intervals’ mechanical properties also be suitable and there be adequate stress barriers between to restrict vertical hydraulic fracture growth. Finally, our rock physics templates may provide useful tools in interpreting pre-stack seismic data sets in prospective areas of the Bowland Shale and picking the best locations for drilling wells.

Quantitative seismic interpretation of the Lower Cretaceous reservoirs in the Valdemar Field, Danish North Sea

A quantitative seismic interpretation study is presented for the Lower Cretaceous Tuxen reservoir in the Valdemar Field, which is associated with heterogeneous and complex geology. Our objective is to better outline the reservoir quality variations of the Tuxen reservoir across the Valdemar Field. Seismic pre-stack data and well logs from two appraisal wells form the basis of this study. The workflow used includes seismic and rock physics forward modelling, attribute analysis, a coloured inversion, and a Bayesian pre-stack inversion for litho-fluid classification. Based on log data, the rock physics properties of the Tuxen interval reveal that the seismic signal is more governed by porosity than water-saturation changes at near-offset (or small angle). The coloured and Bayesian inversion results were generally consistent with well-log observations at the reservoir level and conformed to interpreted horizons. Although the available data have some limitations and the geological setting is complex, the results implied more promising reservoir quality in some areas than others. Hence, the results may offer useful information for delineating the best reservoir zones for further field development and selecting appropriate production strategies.

Reservoir characterization and geological controls of the Lower Cretaceous sandstones in the northern Wuerxun Sag, Hailar Basin, China

The Lower Cretaceous sandstone reservoirs in the northern Wuerxun Sag host abundant hydrocarbon resources and natural CO2 gas. Reservoir quality and heterogeneity are regarded as significant factors affecting the hydrocarbon and CO2 distribution, which have not been comprehensively investigated. In this paper the characteristics of the reservoirs are studied using well log, core, thin section and petrophysical data, and related geological controls are discussed to analyse the factors responsible for the variable reservoir quality. Results show that the Lower Cretaceous sandstones mainly include common sandstones and dawsonite-bearing sandstones, characterized by variable grain size and poor sorting. That is probably caused by the rapidly variable sedimentary facies as a result of short multiple provenances and complex fault system. The reservoir quality is regarded as poor with general low-moderate porosity (ranging from 1.20% to 27.40%, with an average of 12.32%) and low permeability (ranging from 0.01 × 10−3μm2 to 1708.00 × 10−3μm2 with an average of 19.08 × 10−3μm2). The porosity and permeability generally decrease as the burial depth increases. However dawsonite cements have caused local heterogeneity as dawsonite-bearing sandstones are of lower porosity and permeability than comparatively deeper common sandstones. In general, tectonic and depositional evolution provided the heterogeneous lithologic distribution which is the material basis of the reservoir quality evolution. Diagenesis is proposed to be primarily responsible for the reduction of reservoir quality, with compaction being the most important mechanism volumetrically. Cementation also played a role in destroying reservoir quality, with dawsonite cements causing local heterogeneit and closely related to the presence of natural CO2 gas in the Surennuoer strike-slip fault zone. There is a genetic link among the dawsonite cements, inorganic CO2 gas degassed from the magmatic intrusion bodies and the Surennuoer strike-slip fault zone. Generally this study provides a better understanding of the reservoir quality in the northern Wuerxun Sag as well as related geological controls, which can guide subsequent hydrocarbon production activities in the study area.

Physical properties of Cretaceous to Eocene platform-to-basin carbonates from Albania

Understanding acoustic velocities of sedimentary deposits is crucial for realistic subsurface imaging. The velocities rely on mineralogy, density, as well as pore volume (porosity) and pore structure. In carbonate rocks, both depositional and diagenetic histories exert a significant control on these characteristics. In order to determine this control, petrographic analysis (thin sections) associated with the analysis of the carbonate content, grain density, permeability, porosity, and acoustic measurements were performed on samples from Cretaceous to Eocene carbonate platform-to-basin series of Albania. Rock facies showed two depositional associations and four pore-type associations. Very low average permeability (<1 mD) and variable porosity values (0–14%) characterize the samples. Pore type and diagenetic alteration steered the porosity-permeability distribution. Modelling of the velocity-porosity relationship, using the differential effective medium theory (DEM), revealed that variations in the acoustic velocity were mainly driven by variations in porosity and pore type, while facies and mineralogy were of minor importance.The Albanian dataset was compared with petrophysical data retrieved from time- and deep-water facies equivalent carbonate series of the Gargano Promontory in Italy. The comparison demonstrates that the variation in acoustic velocity is limited within the Albanian samples due to the pronounced infill of primary and secondary pores. Acoustic velocity data, on the other hand, are more scattered for the Gargano and this is essentially related to the higher porosity due to the preserved primary macro-intergranular and micro-intercrystalline pores, and/or to significant development of secondary mouldic pores.This study contributes to the understanding of heterogeneities and spatial distribution of pore types resulting in different petrophysical signatures of Cretaceous platform to deep-water carbonates. The data provide a better insight into possible variations in reservoir quality and seismic signature of these types of carbonates in subsurface reservoirs.

Sediment provenance analysis of the Permian from the Perth Basin using an automated Raman heavy mineral technique

The Early Permian in the onshore Perth Basin has experienced several significant discoveries in the last 8 years. Beginning with the play-opening Waitsia discovery (AWE), this was followed more recently by the Beharra Springs Deep (Beach Energy) and West Erregulla (Strike) discoveries. In addition, Late Permian sands (Dongara and Wagina sandstones) have long been recognised as excellent reservoirs in the basin. This study attempts to better understand the provenance of the Early and Late Permian sediments using automated Raman spectroscopy as a tool to identify variations in heavy mineral assemblages. Automated Raman spectroscopy analysis of heavy minerals minimises operator bias inherent in more traditional optical heavy mineral analyses. These data are integrated with publicly available chemostratigraphy data to enable a better understanding of sediment provenance variations with stratigraphy. In addition, publicly available detrital zircon geochronological data are incorporated to help further understand sediment sources. A transect of wells is investigated, from Arrowsmith-1 in the southernmost extent to Depot Hill-1 and Mt Horner-1 in the north. While the elemental (chemostratigraphy) data suggest some changes in sediment provenance through the Permian of the Perth Basin, the Raman heavy mineral data confirm a number of sediment provenance changes both at key formational boundaries (e.g. top Kingia sandstone) and complex sediment provenance variation within reservoir sandstone units. These results are integrated to demonstrate how sediment provenance holds the key to understanding controls on variable reservoir quality as well as understanding the early infill in this basin.

Diagenetic facies prediction using a LDA-assisted SSOM method for the Eocene beach-bar sandstones of Dongying Depression, East China

Prediction of complex diagenesis and the resulting variations in reservoir quality are critical for hydrocarbon exploration. In fact, the limitations of core accessibility and expensive costs of core-based experiments have posed challenges for establishment of diagenetic prediction model. Integrated petrographic and petrophysical analyses are served here to fully understand the dominant diagenetic features and their controls on reservoir quality. Six diagenetic facies representing distinct mineralogical compositions, diagenetic processes, and pore systems were then categorized. To upscale diagenetic features through correlating core diagenetic facies with geophysical well logs, linear discriminant analysis (LDA) was first employed to obtain eigenvectors that can best describe and distinguish diagenetic facies. The well logs that have stronger influence on the first and second eigenvectors and have less correlations with each other are selected to compress the feature space dimensions. The supervised self-organizing map (SSOM) predicable model was trained using dimensionally reduced well log database as input and core diagenetic facies as supervision to determine the nonlinear mapping relations between log response combination features and diagenetic facies group membership. The results showed that LDA-assisted SSOM model yielded higher accuracy as compared with commonly employed linear and non-linear predictable model. The supervised LDA-assisted SSOM method as provided here can be gainfully used to predict diagenetic facies via conventional well logs.

Diagenetic and Reservoir Quality Variation of Miocene Sandstone Reservoir Analogues from Three Basins of Southern California, USA

The Miocene sandstone deposits in the Southern California region are important hydrocarbon reservoirs. However, their development has been very challenging due to the wide variability in their reservoir quality. These sandstones have been studied from three sedimentary basins by petrographic thin section, scanning electron microscope, and X-ray diffraction to evaluate and compare the influence of diagenesis on their reservoir quality in these basins. Four petrofacies, namely P1 (sand injectite or dyke), P2 (sub-marine fan), P3 (turbidite and marine-influenced alluvial fans) and P4 (continental sandstones) have been identified. P1 and P2 characterise the sandstones in the San Joaquin forearc basin and are affected by kaolinite and extensive early calcite diagenesis. P3 and P4 delineate the sandstones in the Cajon Valley and Salton Trough strike-slip basins and are dominated by smectite, mixed illite-smectite, early calcite and late calcite diagenesis. Early calcite cement in P3 and P4 is in lower proportion than in P1 and P2. Although the dissolution of these sandstones by acidic fluids did not have a pattern, it, however, has the most considerable influence on P2 creating moldic pores which are expected to increase pore connectivity. The relatively abundant dissolution pores in P2, together with the absence of late authigenic calcite and illite clay in comparison to the other petrofacies studied are likely to make this sandstone facies the best reservoir targets in the Southern California region. These rocks are analogous to producing reservoirs in the region. However, because, petroleum accumulation in these reservoirs are compartmentalized by early calcite cement, maximum recovery using acidified fluids is recommended to dissolve the calcite-filled pores in order to increase connectivity of their pore network and enhance flow potential.