Variations In Reservoir Quality Research Articles

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.

REVIEW OF THE LOWER-PALAEOZOIC RESERVOIR PROSPECTIVITY OF W. IRAQ WITH REFERENCE TO JORDAN

The Palaeozoic basin of Jordan and Iraq occupies the NW part of the Arabian Plate. The Lower Palaeozoic succession is the most under-explored succession in Iraq, particularly in western Iraq where it is considered the most promising target for future exploration. The western Iraqi subsurface and Jordan geology are characterized by similar major chrono-stratigraphic rock units. In western Iraq, the Akkas-1 well is the only gas and condensate discovery in sandstone reservoirs of Early Silurian and Late Ordovician age. Lower Silurian sandstones of the Akkas Formation are an oil reservoir characterized by a mean porosity of 6.5% and permeability of 0.2mD. Underlying Upper Ordovician sandstones of the upper part of the Khabour Formation are also reservoir, but for sweet gas and condensate. The latter are comparable to both the Risha and Wadi Sirhan discoveries in Jordan. Several deeper potential sandstone reservoirs (of older Ordovician and Cambrian ages) are also present across the region. Equivalent Ordovician age Jordanian reservoirs are primarily developed in homogeneous, highly mature quartz arenites of storm-dominated clastic-shelf stratigraphies. Within the Risha Field and the Wadi Sirhan area, are also end-Ordovician (Hirnantian) glaciogenic and periglacial sandstones with more variable reservoir quality characteristics compared to the underlying quartz arenites. These often comprise highly immature arkoses (as diamictites) that provide a mineralogically much less stable assemblage in which there is a possibility of developing secondary porosity. Sedimentological and XRD mineralogical studies suggest that diagenesis is an important factor in developing of reservoir quality. Nevertheless, reservoir quality is a major exploration risk where burial was significant that led to quartz overgrowth and clay cementation. It is notable that some sandstone reservoirs have chlorite-clay coatings, which prevented formation of the quartz overgrowth and preserved good reservoir quality. The widespread occurrence of associated source and seal rocks together with the proven and potential reservoirs, suggests that Lower Palaeozoic prospects below the deserts of western Iraq are promising targets for future hydrocarbon exploration.

Grain assemblages and diagenesis in organic-rich mudrocks, Upper Pennsylvanian Cline shale (Wolfcamp D), Midland Basin, Texas

Grain assemblages in the organic-rich Cline shale in the Midland Basin are dominated by components of extrabasinal derivation (11.4 to 98.5 vol. %; average volume: 82.6%). Major extrabasinal components include K-rich clay minerals, detrital quartz, albite, K-feldspar, micas, and lithic fragments. Intrabasinal components include mainly biosiliceous allochems (sponge spicules and radiolarians), agglutinated foraminifera, Ca-phosphate peloids, clay-rich peloids, organomineralic aggregates, intraclasts, and other biocalcareous allochems. Authigenic minerals are most evident as grain replacements, euhedral ankerite, Ca-phosphate cement, and precipitates in large pores. A strongly localized spatial distribution of diagenetic products at micron to centimeter scales is observed in most siliciclastic samples, except in biosiliceous allochem-rich ones in which abundant intergranular pore-filling clay-size microquartz cement is observed. Compaction is evident in the Cline shale because of low porosity and generally low cement volumes. Neither textural variation nor bulk mineral composition alone is sufficient to confidently decipher the rock bulk property (e.g., total organic carbon) and reservoir quality variation (e.g., porosity and permeability). However, a good negative relationship between the ratio of extrabasinal to intrabasinal grains and favorable reservoir properties is observed in the Cline shale. Specifically, higher porosity, permeability, and total organic carbon are observed in samples representing the extreme end members of intrabasinal-derived biosilica-rich layers. Nickel, a recognized proxy for paleoproductivity, exhibits a positive relationship with intrabasinal grain content and reservoir properties. X-ray fluorescence–based analysis of nickel can be a rapid and cost-effective way to delineate favorable unconventional reservoir quality in the Cline shale.

Diagenesis and reservoir quality in high-resolution sandstone sequences: An example from the Middle Jurassic Ravenscar sandstones, Yorkshire CoastUK

A section of the Middle Jurassic Ravenscar sandstones exposed between Cloughton Wyke and Burniston Bay was studied to understand fine-scale variation in reservoir quality that can affect flow properties at the reservoir scale. The study has identified two 3rd-order depositional sequences consisting of twelve 4th-order high-resolution sandstone sequences deposited mostly in a lower delta plain. Although these sandstones exhibit a narrow range in porosity values, however, a sharp disparity exists in their permeability which can have implications at the scale of reservoir development. Diagenetic studies have revealed that mechanical compaction produced the same effect for most of these sandstones. However, dissolution and cementation vary, hence, are mostly responsible for the sharp contrast in their reservoir quality. The distributary channel sandstones developed during normal regression of the area in the FS9 sequence are considered the best reservoir sand bodies. However, these LST sandstones are compartmentalised by authigenic illite, quartz and kaolin into two reservoir segments. The upper portion lacks illite with resultant higher permeability values above 1100 mD (ave. 2217 mD) and classified as reservoir group 4. In contrast, the lower part contains illite with relatively lower permeability values in the range of 300–1100 mD (ave. 879 mD) and classified as reservoir group 3 together with the transgressive crevasse channel sandstones in the FS11 sequence. The presence of illite cement in these sandstones is linked to the occurrence of k-feldspar, hence, facilitated illitization of kaolin in contrast to group 4, which lacks this mineral. The other transgressive sandstones deposited in interdistributary bay, crevasse delta, back-barrier lagoon, lagoon, and estuarine environments which form reservoir groups 1 and 2 have permeability values in the range of 0–50 mD (ave. 6 mD) and 50–300 mD (ave. 184 mD) respectively. These sandstones have complex styles of diagenetic cement with variable higher volumes of total authigenic cement consisting of quartz, kaolin, illite, chlorite and calcite than reservoir groups 3 and 4, hence, have significantly reduced their reservoir potential. Therefore, for effective reservoir development of these sandstone reservoirs in the North Sea and elsewhere in the world with a similar geological setting, detailed reservoir characterisation involving linking lithofacies, sequence stratigraphy and diagenesis at high-resolution are essential for understanding the distribution of reservoir flow properties.

Depositional and diagenetic controls on reservoir quality: Example from the upper Cretaceous Mishrif Formation of Iraq

The Cenomanian-Turonian Mishrif Formation at the H field in southeastern Iraq displays a wide range of rock fabrics that result in highly variable reservoir quality and flow properties. Reservoir quality in this field is controlled by the complex interplay of depositional and diagenetic factors. Depositionally, seven main productive facies are recognized, which are organized into six sequences; reservoir quality occurs primarily in the grain dominated high energy shoal, shallow open marine, and rudist biostrome facies. A major change in stratigraphic style occurs midway through the reservoir, with a lower portion that is dominated by laterally continuous upward shoaling cycles (that are often shoal or tidal flat capped) and an upper part that is more heterogeneous and dominated by lagoonal and back-shoal facies. While diagenesis has overprinted and altered this initial framework, karsting - resulting in both enhanced reservoir quality due to leaching and reduced reservoir quality due to cementation, brecciation and fines infiltration - associated with sequence boundaries within and at the top of the Mishrif Formation represents the major flow-significant diagenetic effect in the reservoir. Here, diagenesis has followed the stratigraphic pattern established at the time of deposition, and reinforced its impact on reservoir quality. Mishrif reservoir quality is ultimately controlled by sea-level history, in that high energy, grain dominated textures and facies associated with sea-level highstands have the best reservoir quality, while meteoric diagenesis has produced low reservoir quality (and reservoir boundaries) at karsted exposure surfaces that formed during sea-level falls. Recognition that reservoir quality, both good and bad, results from congruent depositional and diagenetic effects ultimately driven by the sea-level history of the succession provides an important key to understanding and predicting reservoir quality in the H field and in other carbonate fields with similar depositional and diagenetic histories.

Diagenetic impacts on hydraulic flow unit properties: insight from the Jurassic carbonate Upper Arab Formation in the Persian Gulf

The Upper Arab reservoir in the central Persian Gulf was examined for depositional, diagenetic, sequence stratigraphic and petrophysical features. This succession is composed of eight sedimentary facies that deposited on a carbonate ramp. Three-third-order sequences prograded across the Late Jurassic Arab Platform. This interval was complicated by multiple diagenetic phases including eogenesis and mesogenesis that strongly influenced reservoir properties. Dolomitization, dissolution, cementation and compaction are major diagenetic processes which played an essential role in increasing or decreasing reservoir quality. Four hydraulic flow units (HFU) were determined by flow zone indicator approach for evaluation of the reservoir quality. In addition to depositional features, diagenetic alterations have changed general HFUs characterizations such as porosity, permeability and pore-throat size. Likewise, via Lucia classification, HFUs of the Arab reservoir were grouped based on the integration of geological and petrophysical attributes in detail. Among diagenetic processes, dolomitization and dissolution have positive effects while cementation and stylolitization have a negative effect on HFUs characteristics in the studied reservoir. Put another way, since diagenetic alterations lead to the intensification of heterogeneity in carbonate reservoir, prediction of the relationship between pore type and pore throat size is a problematic issue. Recognition of the hydraulic flow units considered as a practical tool for grouping reservoir rocks and characterizing heterogeneity using porosity and permeability relationship. Finally, specifying of the contribution of various diagenetic imprints in each hydraulic flow unit in a sequence stratigraphic framework results in a conceptual reservoir model that could predict reservoir quality variations across the field.

Frequency-dependent AVO analysis using the scattering response of a layered reservoir

Sensitivity of reservoir properties to broadband seismic amplitudes can be weak, which makes interpretation ambiguous. Examples of challenging interpretation scenarios include distinguishing blocky reservoirs from fining sequences, low gas saturation from high gas saturation, and variable reservoir quality. Some of these rock and fluid changes might indicate stronger sensitivity to amplitudes over narrow frequency bands, which is a characteristic of frequency-dependent amplitude variation with offset (FAVO). We have developed a FAVO model for reservoir characterization, following a seismic scattering phenomenon through a set of isotropic elastic layers. The frequency dependency in our model comes from the time delays due to wave propagation within layers. The FAVO modeled response is a complex-valued amplitude varying with angle and frequency, and it is a function of the seismic velocities and thicknesses of individual layers, along with the conventional AVO response at all interfaces. Our FAVO seismic analysis consists of two main steps: (1) forward modeling using well logs to understand rock and fluid sensitivity to amplitudes to identify tuning frequencies with maximum amplitude excursions and (2) seismic analysis at tuning frequencies. With well-log models, we observed that the frequency-dependent tuning response is primarily dependent on the lithology stacking pattern of a reservoir; in the cases studied, the fluid and reservoir quality have secondary effects on the frequency dependence of the amplitudes. We evaluate synthetic models and field data from the Columbus Basin, Trinidad, to illustrate our frequency-dependent seismic analysis methods. For one of the sandstone reservoirs, a frequency-dependent attribute indicates better spatial resolution of the anomaly than a conventional amplitude extraction. FAVO attributes are complementary to conventional AVO attributes.

Diagenetic alteration and its control on reservoir quality of tight sandstones in lacustrine deep-water gravity-flow deposits: A case study of the Yanchang Formation, southern Ordos Basin, China

Abstract The tight oil sandstone reservoir of the Upper Triassic Yanchang Formation is one of the main targets for hydrocarbon exploration in the Ordos Basin, China. Sandstones of the Upper Triassic Yanchang Formation within lacustrine deep-water gravity-flow deposits are characterized by ultralow porosity, ultralow permeability, and complex diagenetic alterations and sedimentary lithofacies. However, the diagenetic alterations and their controls on the reservoir quality of the Chang 6 tight sandstones remain poorly understood. This study integrated a variety of techniques, such as casting thin section analysis, scanning electron microscopy (SEM), back-scattered electron imagery (BSE), X-ray diffraction (XRD), cathodoluminescence (CL) microscopy, and fluid inclusion, to investigate the lithofacies, diagenetic history, and diagenetic intensity, and also evaluate their controls on reservoir quality. The research results indicated that the Chang 6 sandstones exhibit variable intensity of diagenetic alterations among the various lithofacies, which leads to variable reservoir quality. Mechanical compaction was the most important factor reducing primary porosity. Sandstones of the Ss lithofacies (siltstone to very fine-grained sandstones with graded bedding or ripple laminations) showed the highest loss of primary porosity. Carbonate cements were commonly present in sandstones of the Sc (fine-grained and cross-bedded sandstones) and Sm (fine-grained and massive sandstones) lithofacies near the sandstone–mudstone bounding surface. Sandstones with more authigenic illite rims were able to resist compaction to some extent and were favorable to the preservation of porosity; however, abundant pore-filling illite aggregates commonly bridged pore throats, causing a significant reduction in reservoir quality. Feldspar dissolution porosity leads to a slight enhancement in reservoir quality. Intergranular pores and feldspar dissolution pores are most abundant in the sandstones away from the sandstone–mudstone bounding surface of the Sc lithofacies, resulting in the best reservoir quality, which is followed by sandstones of the Sm lithofacies. Ultimately, four evolution patterns of diagenetic alterations that formed best, moderate, or poor reservoir quality were summarized by linking diagenetic alterations to lithofacies. The research results are conducive to the evaluation of reservoir quality and to understanding the genetic mechanisms of tight sandstones, so they should facilitate hydrocarbon exploration and production in similar lacustrine deep-water gravity-flow reservoirs.

Continuous permeability predictions in heterogeneous reservoirs using Vshale and microstructure calibrated free-fluid models (a combined study of a Niger Delta field and the tight gas sandstone of the southern North Sea)

The well-established free-fluid model from NMR technique provides continuous permeability values that closely match with core permeabilities better than most theoretical models especially when it is core calibrated for field specific use. However, only few wells have NMR logs in a field while marginal fields may not have any due to economic reasons. This study explored means of achieving one of the overriding objectives of most marginal field operators, which is to reduce the overall cost of production to the attainable minimum. The free-fluid model was modified into two simple and cost-effective models in order to optimize its applicability to predict permeability in the absence of NMR data. The two new models, which were developed for the single and double porosity systems analyzed in this study, consist of calibration parameters that can be empirically determined to account for variation in reservoir quality based on the rock type profile per field. A non-matrix parameter, α, was introduced into the model derived for tight gas sandstone being regarded as a double-porosity formation. This inclusion represents the permeability contribution of natural fractures or any crack-like pores to the different flow units. By using the alternative version to the known free-fluid model, continuous permeability curves that match experimental results were predicted without NMR logs.

Influence of sedimentary facies on reservoir quality and distribution of diagenetic features in the Funing Formation, Wanglongzhuang Oilfield, Subei Basin, Eastern China

The Paleogene clastic sediments of the Funing Formation, which is characterized by slump-fan, delta-front, and beach-bar deposits, are important targets for oil and gas exploration in the Wanglongzhuang Oilfield, Subei Basin, eastern China. Three categories of reservoir quality are distinguished on the basis of petrographic and petrophysical experiments such as nuclear magnetic resonance (NMR) and mercury injection (MI). A paragenetic sequence for diagenetic evolution of each sedimentary facies has been reconstructed to determine the mechanisms for the variations in reservoir quality of the formation and the influence of the sedimentary facies on the distribution of diagenetic features in each of its members. The maturity of the organic material, textural relationships, and the distribution pattern of diagenetic minerals suggest that the study area underwent mainly mesodiagenesis. The mesodiagenesis A and mesodiagenesis B stages induced different diagenetic features in the target reservoir; the beach-bar sand of the E1f2 unit and the delta-front sand of the E1f4 unit underwent mostly only cementation; the delta-front deposits of the E1f3 unit, however, suffered more from mechanical and chemical compaction than from cementation. The loss of porosity in the fluxoturbidites of E1f4 due to compaction was just as large as the loss by cementation. The gravity-flow channel, sand-bar, and distributary-channel deposits have a higher porosity and permeability than the sand-beach and estuarine-bar deposits.

Mechanical compaction in chlorite-coated sandstone reservoirs – Examples from Middle – Late Triassic channels in the southwestern Barents Sea

Abstract The relationship between diagenetic evolution and reservoir quality in large-scale Middle – Late Triassic aged channel systems (up to 20 km wide) in the southwestern Barents Sea is investigated through core plug data, XRD, SEM- and modal analyses. The studied channel systems are likely sourced from the southeastern Uralide mountain range and are characterized by chemically unstable clastic sediment and well-developed, porosity-preserving chlorite coatings. Chlorite coatings occupy potential quartz nucleation sites on the framework grain surfaces and likely prevent significant chemical compaction in deeply buried sandstones. Porosity-reduction is believed to follow mechanical compaction trends of similar sandstone compositions. Modelling and prediction of porosity preservation in Middle - Late Triassic channel sandstones in the study area is therefore possible, if temperature histories and sandstone compositions are well constrained. The tidally influenced channel and fluvial-dominated channels in this study show significant variation in reservoir quality. These differences are found to be linked to amount of allogenic matrix and grain size, which significantly reduces the permeability in the tidally influenced channel. If seismic distinction between different channel types is impossible, the distribution of permeability is considered unpredictable. Chlorite coatings in the investigated channels are interpreted to be diagenetic overprints of a precursor clay phase, which appears to have a strong link to the Uralian provenance. Coating precursor emplacement likely occurs prior to significant burial, but the exact physical conditions enabling this process remain elusive without systematic laboratory and analogue studies.

Reservoir quality of fluvial sandstone reservoirs in salt-walled mini-basins: an example from the Seagull field, Central Graben, North Sea, UK

The Triassic fluvial sandstones of the Skagerrak Formation were deposited in a series of salt-walled mini-basins and act as important hydrocarbon reservoirs for several high-pressure, high-temperature (HPHT) fields in the Central Graben, North Sea. The HPHT reservoirs exhibit excellent reservoir quality considering their depth of burial and hence have been of high interest for hydrocarbon exploration. This research uses a multidisciplinary approach to assess the Skagerrak Formation fluvial reservoir quality from the Seagull field incorporating core analysis, petrography, electron microscopy, XRD analysis, fluid inclusion appraisal and burial history modelling. Halokinesis and salt withdrawal at the margin of the salt-walled mini-basin induced early disaggregation bands and fractures at shallow burial and led to increased influx of meteoric water and clay mineral infiltration from overlying sedimentation. The density of disaggregation bands correlates with the occurrence and magnitude of pore-filling authigenic clay minerals, concentrated along the margin of the salt-walled mini-basin. The fluvial channel sandstones of the Skagerrak Formation are subject to strong intra-basinal spatial reservoir quality variations despite diagenesis and low vertical effective stress having played a favourable role in arresting porosity loss.

Recent exploration results in the Lower Triassic, Bedout Sub-basin: Australia's next petroleum province?

Commencing in 2014, Quadrant Energy and partners have undertaken an active exploration program in the Bedout Sub-basin with a 100% success rate, discovering four hydrocarbon accumulations with four wells. The primary exploration target in the basin, the Middle Triassic Lower Keraudren Formation, encompasses the reservoirs, source rocks and seals that have trapped hydrocarbons in a self-contained petroleum system. This petroleum system is older than the traditional plays on the North-West Shelf and before recent activity was very poorly understood and easily overlooked. Key reservoirs occur at burial depths of 3500–5500 m, deeper than many of the traditional plays on the North-West Shelf and exhibit variable reservoir quality. Oil and gas-condensate discovered in the first two wells, Phoenix South-1 and Roc-1, raised key questions on the preservation of effective porosity and productivity sufficient to support a commercial development. With the acquisition and detailed interpretation of 119 m of core over the Caley Member reservoir in Roc-2 and a successful drill stem test that was surface equipment constrained to 55 MMscf/d, the productive potential of this reservoir interval has been confirmed. The results of the exploration program to date, combined with acquisition of new 3D/2D seismic data, have enabled a deeper understanding of the potential of the Bedout Sub-basin. A detailed basin model has been developed and a large suite of prospects and leads are recognised across a family of hydrocarbon plays. Two key wells currently scheduled for 2018 (Phoenix South-3 and Dorado-1) will provide critical information about the scale of this opportunity.

Reservoir quality and diagenesis of the Permian Lucaogou Formation tight carbonates in Jimsar Sag, Junggar Basin, West China

The Lower Permian Lucaogou Formation in the Jimsar sag, Junggar Basin is a typical tight-oil reservoir in China. For effective exploration and production, the formation of a high-quality reservoir must be thoroughly studied. In this work, the tight-oil reservoir was examined using a variety of methods, including core and thin-section observations, XRD, SEM, CL and fluid inclusion and isotope testing. The tight-oil reservoirs were primarily deposited in saline lake environments, which are dominated by variable admixture of dolomite, quartz, feldspar, tuff, calcite and pyrite. Nine main lithofacies were identified: (1) siliceous mudstone, (2) dolomitic siliceous mudstone, (3) dolomitic mudstone, (4) intraclast packstone/grainstone, (5) ooid grainstone, (6) bioclast grainstone, (7) dolomitic siltstone, (8) mixed siliclastic and intraclast grainstone and (9) brecciated dolomitic mudstone. The pore types are classified into four categories: primary intergranular, moldic, intercrystalline and fracture pores. The properties of tight-oil reservoirs are quite poor, with low porosity (ave. 7.85%) and permeability (ave. 0.110 mD) and a small pore-throat radius (ave. 0.086 μm). The tight-oil reservoirs are dominated by the aggradation of a repetitive meter-scale sedimentary facies succession that records distinct lacustrine expansions and contractions. These tight carbonates have also undergone significant diagenetic alterations, such as dolomitization, dissolution, neomorphism and fracture created intercrystalline and moldic pores, vug and fractures; chemical and mechanical compaction and carbonate cementation have decreased the reservoir quality. Variations in reservoir quality in the Jimusar sag are due to a combination of lithofacies type, high-frequency cyclic depositional architecture, dissolution intensity, dolomitization and tectonic related deformation. This integrated study has helped in understanding the reservoir heterogeneity and hydrocarbon potential of the Jimusar fine-grained rocks.

Reservoir quality along a homoclinal carbonate ramp deposit: The Permian Upper Dalan Formation, South Pars Field, Persian Gulf Basin

Permo-Triassic carbonate successions host some of the largest oil and gas reserves in the Arabian Plate, including the world's largest gas reservoirs of the Upper Dalan and the Kangan formations in the South Pars Gas Field, Persian Gulf Basin. Both formations are stratigraphically equivalent to the Upper Khuff Formation which has been long recognized as a major oil and gas reservoir in the Arabian Peninsula. The Permian Upper Dalan Formation is composed mainly of mixed carbonate-evaporite sequences that formed on a laterally continuous homoclinal carbonate ramp with significant variations in reservoir heterogeneity and quality. They can be grouped in 18 microfacies. High reservoir qualities are found within high-energy shoal environments with a tendency of the best reservoir quality to occur towards the basin in a mid-ramp setting. In contrast, low-energy tidal flat environments exhibit the poorest reservoir quality. Reservoir quality from lagoonal environments is diverse. Diagenesis has significantly affected reservoir properties by both enhancing and destroying original porosity and permeability. Bivariate plots of porosity and permeability values, combined with thin section petrography indicate that pore-filling “pervasive” and poikilotopic anhydrite cements had the greatest negative impact on the reservoir quality whereas dolomitization and dissolution of grains and cements played the most positive role. Two third-order sequence stratigraphic cycles link lithologies and depositional environments to sea-level fluctuations. HSTs are associated with better reservoir characteristics than TSTs.

Reservoir quality variations within a conglomeratic fan-delta system in the Mahu sag, northwestern Junggar Basin: Characteristics and controlling factors

The conglomeratic reservoir in the Mahu depression, northwestern margin of the Junggar basin, Northwestern China has become an important exploration target. In this study, we use well and core data to investigate the characteristics and controlling factors of conglomeratic fan-delta reservoirs. The reservoir studied here developed in a retreating fan-delta complex that is dominated by conglomerate lithofacies and conglomeratic sandstone lithofacies. A petrological analysis shows that the reservoir exhibits poor compositional maturity and textural maturity. A physical property analysis shows that the reservoir exhibits extremely low porosity and extremely low permeability, as well as strong heterogeneity in the vertical and planar views. The depositional environment and compaction result in extremely low porosity and extremely low permeability in the reservoir. About 66% porosity was destroyed by the compaction. Fan-delta evolution and provenance control the macroscopic variations in reservoir quality. Muddy matrix content, grain size and dissolution control the microscopic variations in reservoir quality. About 52.5% porosity was induced by the dissolution. This reservoir study can be compared to fan-deltas that developed in marine-connected rift basins during early stages of extension and to nearshore subaqueous fans in East China. Additionally, the results of this study may provide a reference for such systems and provide a subsurface case for similar fan-delta outcrop studies and facies reservoir modelling.

Controls on reservoir quality in exhumed basins – an example from the Ordovician sandstone, Illizi Basin, Algeria

Petroleum exploration in many North African intracratonic basins targets Early Paleozoic sandstones as the primary reservoir objective. These sandstones are often characterized by highly variable reservoir quality (0.0001–1000 mD), and the ability to predict and selectively target areas of enhanced porosity and permeability is crucial to unlock the hydrocarbon potential. The objective of this study is to characterize the primary controls on reservoir quality in an Ordovician field in the Illizi Basin of Algeria through detailed core and petrographic analysis, and establish if variations in thermal history across the field have a material impact on reservoir quality. The best reservoir quality is observed in facies where primary intergranular porosity has been preserved in fine to coarse grained quartzarenites with less than 1% fibrous illite. These lithologies are most commonly found within the high-energy, tidally reworked, post-glacial facies sandstones of the uppermost Ordovician succession. Observed differences in quartz cement volume within compositionally and texturally similar samples from the southern and northern parts of the field are interpreted to reflect variations in thermal exposure due to deeper burial. This interpretation is supported by field-wide numerical modelling of sandstone diagenesis. This study indicates that subtle variations in thermal history can have a material impact on the spatial trends in reservoir permeability. Thermal history, therefore, is an important consideration in reservoir quality studies in exhumed basins where variations in present-day burial depth will be a poor guide for evaluating reservoir quality risk across a basin or play.

Reservoir zonation based on statistical analyses: A case study of the Nubian sandstone, Gulf of Suez, Egypt

Both reservoir engineers and petrophysicists have been concerned about dividing a reservoir into zones for engineering and petrophysics purposes. Through decades, several techniques and approaches were introduced. Out of them, statistical reservoir zonation, stratigraphic modified Lorenz (SML) plot and the principal component and clustering analyses techniques were chosen to apply on the Nubian sandstone reservoir of Palaeozoic – Lower Cretaceous age, Gulf of Suez, Egypt, by using five adjacent wells. The studied reservoir consists mainly of sandstone with some intercalation of shale layers with varying thickness from one well to another. The permeability ranged from less than 1 md to more than 1000 md. The statistical reservoir zonation technique, depending on core permeability, indicated that the cored interval of the studied reservoir can be divided into two zones. Using reservoir properties such as porosity, bulk density, acoustic impedance and interval transit time indicated also two zones with an obvious variation in separation depth and zones continuity. The stratigraphic modified Lorenz (SML) plot indicated the presence of more than 9 flow units in the cored interval as well as a high degree of microscopic heterogeneity. On the other hand, principal component and cluster analyses, depending on well logging data (gamma ray, sonic, density and neutron), indicated that the whole reservoir can be divided at least into four electrofacies having a noticeable variation in reservoir quality, as correlated with the measured permeability. Furthermore, continuity or discontinuity of the reservoir zones can be determined using this analysis.

Characterization of lacustrine carbonate reservoirs in the Eocene Sikou Sag, Bohai Bay Basin, East China

With the recent discovery of new oil fields around the Bohai Bay Basin, a better understanding of the origin of its high-quality lacustrine carbonate reservoirs has become important. This paper investigates marginal lacustrine carbonates of the upper fourth member of the Eocene Shahejie Formation (Es4s) around the Sikou Sag, using core analysis, thin section petrology and geochemical data. The δ13C and δ18O values of the Sikou carbonates differ significantly from Eocene marine values, the 87Sr/86Sr ratio of carbonate minerals (0.710210–0.710844) is higher than Eocene marine water and same to the surrounding Palaeozoic carbonate bedrock and the distribution of the carbonates is controlled by the surrounding Palaeozoic carbonate bedrock, all of which indicate their lacustrine origin. The main facies associations are reef mound, shoal facies (including low-energy and high-energy shoals), higher salinity central-lake deposits, and fan delta-related deposits. The pore types are classified into four categories: depositional, fabric-selective, non-fabric selective, and fracture. The diagenetic processes improving reservoir quality are dissolution, dolomitization and fracture development. Reservoir quality of the carbonates was decreased by burial calcite cementation and compaction. High quality reservoirs in the basin are mostly distributed in dolomitzed bindstones and grainstones, deposited in the reef mound and shoal facies of shallow lakes. Owing to karstification, a high quality reservoir zone also occurs in the studied section beneath the top unconformity. Variation in reservoir quality in the Sikou Sag is due to a combination of lithofacies type, dissolution intensity, early dolomitization and tectonic related deformations. Proper lithofacies type controlled the primary porosity. Restricted depositional facies and a high-frequency cyclic depositional architecture of the strata caused lateral and vertical reservoir heterogeneity. Dissolution produced secondary pores and caused occlusion of some porosities in the rocks. In addition, tectonic deformation produced some fractures, as well as karstification is associated with tectonic uplift.