Distribution Of Reservoir Facies Research Articles

Lithofacies, stratigraphy, and provenance study of upper sandstone, Blue Nile (Abay) Basin, Ethiopia: insight to the distribution of reservoir facies

Lithofacies, stratigraphy, and provenance study of upper sandstone, Blue Nile (Abay) Basin, Ethiopia: insight to the distribution of reservoir facies

Integrated geological data, 3D post‐stack seismic inversion, depositional modelling and geostatistical modelling towards a better prediction of reservoir property distribution for near‐field exploration: A case study from the eastern Sirt Basin, Libya

De‐risking the hydrocarbon potential in near‐field exploration is one of the most important procedures in the exploration of hydrocarbons, and it requires the integration of various data to predict the reservoir characteristics of the prospect area more accurately. In this work, wells and 3D seismic data from the Libyan producing oil fields were utilized to demonstrate how well this technique worked to improve and describe the hydrocarbon potential of the carbonate geobody that corresponds to the Palaeocene Upper Sabil Formation, which was revealed by new seismic data. This study integrates different types of data, including 3D seismic, seismic acoustic impedance, depositional history and geostatistical analysis, to predict the facies, reservoir porosity and permeability distributions and then visualize them in a 3D reservoir model. The 3D seismic data analysis revealed the presence of a clear seismic anomaly geobody (GB) that has never been penetrated by any well. The sedimentological analysis for the well adjacent to the GB indicated a deep‐water depositional environment as turbidites surrounded by deep‐water mud dominated facies. The Upper Palaeocene interval in the study area was subdivided based on the depositional facies and seismic stratigraphy into eight zones that were used to build the reservoir model framework. According to the porosity permeability relationships, the carbonate facies has been classified into five E‐Facies, that is, soft highly argillaceous limestone, hard argillaceous limestone, porous limestone (<20% porosity, and >30% shale volume), medium quality limestone (10–20% porosity, and >30% shale volume) and tight limestone (<10% porosity, and >30% shale volume). The rock physics and inversion feasibility analysis indicated that the acoustic impedance (AI) can be used to predict the porosity but not the lithology or the fluid content. The Bayesian classification has shown excellent results in predicting and modelling the reservoir facies distribution within the study area, utilizing the integration of gross depositional maps (GDEs), wells and seismic data. The reservoir quality of the GB was predicted by using the post‐stack seismic inversion, which indicated a high porosity interval (25%–30%). Moreover, the statistical analysis integrated with the well and seismic data was used to predict the GB permeability. The predicted permeability was reasonably high (40–60 mD). The final E‐facies show an excellent match with the input well data and an excellent match with the blind wells that were used for result quality control (QC) with higher vertical resolution. The developed model can be used as a guide for de‐risking the studied GB hydrocarbon potential in the studied basin, and it can be applied in other similar geological conditions worldwide for exploring underexplored reservoirs and de‐risking their hydrocarbon potential.

Reservoir heterogeneity analysis using multi-directional textural attributes from deep learning-based enhanced acoustic impedance inversion: A study from Poseidon, NW shelf Australia

Reservoir heterogeneities play a crucial role in governing reservoir performance and management. Traditionally, detailed and inter-well heterogeneity analyses are commonly performed by mapping seismic facies change in the seismic data, which is a time-intensive task. Many researchers have utilized a robust Grey-level co-occurrence matrix (GLCM)-based texture attributes to map reservoir heterogeneity. However, these attributes take seismic data as input and might not be sensitive to lateral lithology variation. To incorporate the lithology information, we have developed an innovative impedance-based texture approach using GLCM workflow by integrating 3D acoustic impedance volume (a rock property-based attribute) obtained from a deep convolution network-based impedance inversion. Our proposed workflow is anticipated to be more sensitive toward mapping lateral changes than the conventional amplitude-based texture approach, wherein seismic data is used as input. To evaluate the improvement, we applied the proposed workflow to the full-stack 3D seismic data from the Poseidon field, NW-shelf, Australia. This study demonstrates that a better demarcation of reservoir gas sands with improved lateral continuity is achievable with the presented approach compared to the conventional approach. In addition, we assess the implication of multi-stage faulting on facies distribution for effective reservoir characterization. This study also suggests a well-bounded potential reservoir facies distribution along the parallel fault lines. Thus, the proposed approach provides an efficient strategy by integrating the impedance information with texture attributes to improve the inference on reservoir heterogeneity, which can serve as a promising tool for identifying potential reservoir zones for both production benefits and fluid storage.

Seismic reservoir characterization of the syn-rift lower Miocene Rudeis Formation in the July oilfield, Gulf of Suez basin, Egypt: Implication for reservoir quality assessment

The Lower Miocene Rudeis Formation is among the most potential oil-bearing sedimentary sequences in the Gulf of Suez (GOS), representing the main producer of Egyptian oil. This study concerns primarily with revealing the reservoir characteristics and facies distribution, as well as the implication of the predominant diagenetic factors on the quality of the Lower Miocene syn-rift Rudeis reservoir in the July oilfield. Therefore, this study integrates 2D seismic, and wireline logs, as well as conventional and special core analyses to determine the reservoir characteristics and facies distribution. The interpreted data elucidate four different seismic facies in the Rudeis Formation with a net pay thickness ranging from 29 to 233 m in the studied wells of 16.3% average porosity, 62.9% average oil saturation, and 9.3% average shale volume. Four seismic facies (SF1-SF4) were interpreted and correlated with the Rudeis clastic deep-water turbiditic succession. The 3D static property models revealed that the best reservoir facies in terms of low shale content and water saturation, as well as high porosity, coincide with the submarine channels and fans containing coarse-grained, clean sandstones. From the core analysis, the Lower part of the Rudeis sequence is subdivided into five reservoir rock types (RRTs). The RRT1 is characterized by the best reservoir quality; it is composed of quartz arenites, sublithic arenites, and subfeldspathic arenites. In contrast, the RRT5 represents the lowest reservoir quality; it consists of very coarse siltstone, laminated glauconitic siltstone, and highly compacted dolomitic and calcareous quartz arenites. The poor reservoir characteristics of the RRT5 are attributed to tight compaction, cementation, and early dolomitization phase, whereas the highest quality of the RRT1 is related to fracturing and dissolution processes. The RRT1 rocks are mostly associated with the submarine channel and fan facies, whereas the poor quality RRT5 sediments were accumulated as hemipelagic/background. This integrated workflow study can be applied to further case studies in the Middle East, Africa, and the other analogues all over the world.

Improved reservoir characterization by means of supervised machine learning and model-based seismic impedance inversion in the Penobscot field, Scotian Basin

The present research work attempted to delineate and characterize the reservoir facies from the Dawson Canyon Formation in the Penobscot field, Scotian Basin. An integrated study of instantaneous frequency, P-impedance, volume of clay and neutron-porosity attributes, and structural framework was done to unravel the Late Cretaceous depositional system and reservoir facies distribution patterns within the study area. Fault strikes were found in the EW and NEE-SWW directions indicating the dominant course of tectonic activities during the Late Cretaceous period in the region. P-impedance was estimated using model-based seismic inversion. Petrophysical properties such as the neutron porosity (NPHI) and volume of clay (VCL) were estimated using the multilayer perceptron neural network with high accuracy. Comparatively, a combination of low instantaneous frequency (15–30 Hz), moderate to high impedance (7000–9500 gm/cc∗m/s), low neutron porosity (27%–40%) and low volume of clay (40%–60%), suggests fair-to-good sandstone development in the Dawson Canyon Formation. After calibration with the well-log data, it is found that further lowering in these attribute responses signifies the clean sandstone facies possibly containing hydrocarbons. The present study suggests that the shale lithofacies dominates the Late Cretaceous deposition (Dawson Canyon Formation) in the Penobscot field, Scotian Basin. Major faults and overlying shale facies provide structural and stratigraphic seals and act as a suitable hydrocarbon entrapment mechanism in the Dawson Canyon Formation's reservoirs. The present research advocates the integrated analysis of multi-attributes estimated using different methods to minimize the risk involved in hydrocarbon exploration.

Integrated Geological and Petrophysical Approaches for Characterizing the Pre-Cenomanian Nubian Sandstone Reservoirs in Ramadan Oil Field, Central Gulf of Suez, Egypt

The present study integrates multidisciplinary geological and petrophysical approaches to characterize and evaluate the potential of the pre-Cenomanian Nubian sandstone reservoirs in the Ramadan oil field, the central offshore part of the Gulf of Suez, Egypt. The different petrophysical parameters of the Nubian sandstone reservoirs (shale volume, porosity, water saturation as well as gross and net-pay thicknesses) were mapped, and 3D slicing models for the hydrocarbon phases saturation were constructed to understand the reservoir heterogeneity and the distribution of the best reservoir facies. The petrophysical results of the pre-Cenomanian Nubian succession highlight very good reservoir intervals in the Nubian C sandstones containing thick pay zones (> 120 m). On the other side, the Nubian A and B reservoir rocks are less prospective with pay zone horizons (< 10 m). Integrated reservoir models and wireline log analysis elucidate that clay volume is the most detrimental factor to the reservoir quality as the pay zone thickness and hydrocarbon saturation often increase where the clay volume decreases. Therefore, the presence of scattered pay zone intervals in Nubian A and B is mainly related to their elevated clay content which acts as barriers for fluids flowing within the reservoir facies. The Nubian C succession contains three different reservoir rock types (RRT) with variable compositional and petrophysical properties. RRTI and RRTII sandstones comprise quartzose sandstones with very low clay content (< 10%) and are characterized by an open pore system dominated by macropores. These sandstones are less impacted by overburden pressure and therefore can preserve their depositional porosity and permeability. On the other hand, RRTIII reservoir rocks are clay rich (> 10%) with abundant mesopores that are more prone to compressibility and hence reduction of the pore volume and pore throat. The present study highlights the significance of comprehensive integration between wireline logs, cores, and 3D reservoir models in directing exploration endeavors toward prospective reservoirs in mature basins.

VALIDATION OF EXTENDED ELASTIC IMPEDANCE BASED ON MINIMUM ENERGY ANGLE. A CASE STUDY APPLICATION FOR OPTIMIZED PETROLEUM RESERVOIR CHARACTERIZATION

This work intends to showcase a validation of the applicability of Extended Elastic Impedance (EEI) inversion method in reservoir characterization and modeling. In order to achieve that, deterministic seismic inversion and extended elastic impedance (EEI) analysis were applied to obtain quantitative estimates of reservoir properties over the Pu field of the West African Congo basin. Optimum EEI angles corresponding to the reservoir properties were then analyzed using well logs data, together with a lithology indicator. Pre-stack seismic data were simultaneously inverted into density, acoustic and gradient impedances cubes, through model based inversion algorithm. The last two broadband inverted volumes were then projected to corresponding Chi angles proportionate to petrophysical indicators, thus resulting to two broadband EEI volumes. At well locations, the EEI versus petrophysical parameters linear trends were then applied to convert EEI volumes into porosity and shale volumes based on specified lithology. In order to generate reservoir facies distribution, minimum angle was applied based on background EEI, thus allowing for mapping of reservoir facies. In order to validate the EEI approach, a Geo-statistical model was further developed for the same field. Hence, from porosity, shale content and background EEI cubes, a comparison was made between the properties generated from the EEI and that generated based on geo-statistical method, which shows that EEI is a robust way of reservoir characterization that pinpointing favorable reservoir potentials which shall guide future drilling locations.

A novel workflow for geothermal exploration: 3D seismic interpretation of biohermal buildups (Upper Jurassic, Molasse Basin, Germany)

The Upper Jurassic carbonates are the prime target for deep geothermal exploration in the Molasse basin, South Germany. The carbonates have a thickness of over 500m (1640 ft) and consist of two major facies: (1) bedded marly limestone and (2) massive limestone and dolostone. The massive limestone facies is composed of sponge-microbial biohermal buildups It is considered the main geothermal reservoir facies. Only this facies type may be (1) karstified, (2) dolomitized, and/or (3) faulted and fractured, and therefore can yield very high flow rates of >100 l/sec = 26 gps. The main data source used in this study is the 3D seismic survey of the Freiham geothermal field in the western part of Munich/Germany. Blended in were cutting logs to describe the lithology from 2 wells and borehole image logs from the two geothermal wells. Lithologies derived from these wells were upscaled in support of the seismic interpretation. The study presents an integrated workflow of 3D seismic attribute analysis to analyze the distribution and quantification of reservoir facies (massive limestone) versus non-reservoir facies (bedded marly limestone) per time slice. The attribute “sum of magnitude” is mapped for 9-time slices based on the vertical resolution of the Freiham 3D cube. The seismic facies interpretation is compared with upscaled borehole image facies associations of two geothermal wells. BHI log data is calibrated with an interpretation of the depositional environment based on cutting analysis Reservoir geometries were derived from an outcrop analog study to better understand the 3D seismic facies interpretation and to construct the conceptual depositional model of the Upper Jurassic carbonates. This technique is commonly used in hydrocarbon exploration but is not yet adapted to geothermal projects, which are often based on little data, smaller company sizes, tight budgets, and limited access to specialized geomodelling software and experience. The approach of using 3D seismic attribute analysis presented in this study provides a quantitative subsurface model of geothermal reservoir facies in the Freiham geothermal field. It is quick and straightforward and can easily be applied in the exploration workflow for similar fields and reservoirs.

Influence of rift geometry over successive post-rift sedimentation: Tectonostratigraphy of the eastern Kopeh Dagh Belt (NE Iran)

Well, seismic (2D and 3D) and AHe age data, complemented by field surveys, were analyzed with the objective of investigating the tectono-stratigraphic evolution of syn- and post-rift sedimentary basins in the eastern Kopeh Dagh Belt (NE Iran), a region well known for its important oil and gas occurrences. The study was focused on evaluating how and when the geometry of syn-rift structures influenced the development of the post-rift sedimentation. Our results show that the Middle Jurassic rifting stage influenced the geometry of the post-rift basins. Carbonate buildup of the Upper Jurassic (Mozduran reservoir) was formed in the low relief accommodation zones between the Middle Jurassic opposing half-grabens in parallel to the sedimentation of argillaceous carbonates within the adjacent troughs. This geometry was also transmitted to the Lower Cretaceous, affecting the deposition of a relevant siliciclastic system (Shurijeh reservoir). The role of rifting was crucial in the distribution of reservoir facies and the generation of the structural-stratigraphic traps in the study area, which were also affected by late tectonic inversion. Uplift and denudation is likely to have occurred up to Late Miocene.

Production data-based facies analysis for well placement in thin-layered reservoir

The exploitation of a thin-layered reservoir with thickness less than 5 m (16 ft) needs to rely upon sedimentary facies analysis, due to the low resolution of seismic data and sparse well data. However, the ambiguity of facies interpretation creates uncertainty in facies and reservoir mapping. The study aims to better define facies distribution, predict sand-body architecture, and consequently reduce risks in planning development wells, by integrating production data (dynamic) with conceptual geological models (static). An example is shown from the M1 Member of the Napo Formation in the B and G Oilfields (Block J), Oriente Basin, Ecuador. The M1 reservoir is a thin-layered sandstone reservoir below seismic resolution. Core and well-log facies interpretation indicates depositional facies of a tide-dominated estuary. Production data during the water injection phase of field development can delineate the detailed geometry of the sand bodies. The injector-producer rate responses can determine the connectivity of sand bodies. Well performance during primary recovery can capture the scale of single reservoirs because the initial production rates and the cumulative oil production of individual wells are generally proportional to the size of sand bodies. A facies model was thereby generated. Two step-out wells were planned using this model and drilled successfully. The results demonstrate that the integration of dynamic and static data is critical to understanding reservoir facies distribution.

Integrating sedimentology and ichnology with rock typing and flow units: Implications for clastic reservoir characterization

Shallow marine clastic reservoir facies prediction, correlation, distribution, thickness, and quality remains a challenge. This study integrates sedimentology and ichnology with reservoir rock typing and flow units to characterize the Lower Cretaceous Wabiskaw Member reservoir. An integrated geologic depositional model is presented using sedimentological data (rock types, sedimentary structures, grain size), ichnological data (trace fossils intensity, size, diversity), reservoir characteristics (porosity, permeability), and well log data. The Wabiskaw Member strata are characterized using four facies associations (composed of nine sedimentary facies). Facies association 1 (FA-1) comprises dark grey to blue-grey mudstone with a distinctly lenticular appearance (Facies 1, 2). Ichnologically, a stressed archetypal Cruziana Ichnofacies represent FA-1. Facies association 2 (FA-2) is fine-lower medium-grained sandstone with thin mudstone interbeds (Facies 3, 4). A stressed ichnological suite of mixed Skolithos-Cruziana Ichnofacies is present in FA-2. Facies association 3 (FA-3) is dark grey to bluish-grey mudstone with minor sandstone interbeds (Facies 5, 6). Trace fossils of archetypal Cruziana Ichnofacies are present in FA-3. Facies association 4 (FA-4) comprises upper fine to lower fine glauconitic sandstone (Facies 7, 8, 9) with a high-density trace fossil assemblage. FA-1 and FA-2 represent deposition in a wave-influenced prodelta to delta front settings, whereas FA-3 and FA-4 represent deposition in the offshore-shoreface environment. The reservoir quality of various reservoir facies (F-3, F-4, F-7, F-8) is evaluated by comparing facies reservoir characteristics (porosity, permeability, pore throat radii, flow-storage capacity, oil saturation, and thickness). F-4 is the best and most productive reservoir (pore throat radius >20 μm, 18% flow, and 4% storage capacity) in the study area. F-7 is ranked second-best in reservoir quality based on petrophysical characteristics (pore throat radius between 10 and 20 μm, 36% storage 47% flow capacity). F-8 is ranked third in reservoir quality with pore-throat radii ranging from 4 to 10 μm (mesoporous), 23% storage, and ≤5% flow capacity. F-3 is ranked last amongst the Wabiskaw Member reservoir facies. It is micro-porous (pore-throat radii ranging from 2 to 4 μm) with 37% storage and ≤5% capacity flow.

Bayesian Theorem Application to Model Reservoir Facies Distribution on Deltaic Depositional Environment, Case Study of Browse Basin

Successful Hydrocarbon exploration and reservoir characterization always related with good understanding of geology and geophysics aspect. One of the fundamental issues is to get reliable parameter distribution and quantify the confidence level of the parameter model in 3D. The case study in this paper will be applied in Browse field that and the result will be a distribution model in 3D of facies and hydrocarbon fluid. The workflow that will be introduced in this paper is the combination between rock physics analysis, simultaneous seismic inversion and Bayesian estimation theorem. Rock physics analysis includes well log conditioning and correlation analysis between reservoir parameter (porosity, saturation, Vshale, etc) with seismic parameter (acoustic impedance, vp/vs, shear impedance, etc) to obtain facies classification in well log scale. The simultaneous seismic inversion method is used to obtain seismic parameter cube to be correlated with rock physics result to drive the facies distribution. Bayesian estimation theorem assembles initial knowledge about a model before observing the inversion attributes. The probability density function later will be used to drive the facies distribution combined with well log data and seismic data; and also estimate the confidence level distribution in 3D. The result can be used to identify new play in the Browse field.

Characterization of reservoir sands using 3D seismic attributes in the coastal swamp area of Niger Delta Basin

Hydrocarbon accumulation and production within the Niger Delta Basin are controlled by varieties of geologic features guided by the depositional environment and tectonic history across the basin. In this study, multiple seismic attribute transforms were applied to three-dimensional (3D) seismic data obtained from “Reigh” Field, Onshore Niger Delta to delineate and characterize geologic features capable of harboring hydrocarbon and identifying hydrocarbon productivity areas within the field. Two (2) sand units were delineated from borehole log data and their corresponding horizons were mapped on seismic data, using appropriate check-shot data of the boreholes. Petrophysical summary of the sand units revealed that the area is characterized by high sand/shale ratio, effective porosity ranged from 16 to 36% and hydrocarbon saturation between 72 and 92%. By extracting attribute maps of coherence, instantaneous frequency, instantaneous amplitude and RMS amplitude, characterization of the sand units in terms of reservoir geomorphological features, facies distribution and hydrocarbon potential was achieved. Seismic attribute results revealed (1) characteristic patterns of varying frequency and amplitude areas, (2) major control of hydrocarbon accumulation being structural, in terms of fault, (3) prospective stratigraphic pinch-out, lenticular thick hydrocarbon sand, mounded sand deposit and barrier bar deposit. Seismic Attributes analysis together with seismic structural interpretation revealed prospective structurally high zones with high sand percentage, moderate thickness and high porosity anomaly at the center of the field. The integration of different seismic attribute transforms and results from the study has improved our understanding of mapped sand units and enhanced the delineation of drillable locations which are not recognized on conventional seismic interpretations.

Reservoir characterization, Facies distribution, and sequence stratigraphy of Mishrif Formation in a selected oilfield, South of Iraq

Mishrif Formation is considered the most important between the reservoirs formations in the south of Iraq because of its geographic extent. The facies were predicted in Ratawi oilfield from wireline logs that divided Mishrif Formation into two main reservoirs separated by a barrier member. So the formation is almost cupped with shale intervals in both contacts of Rumaila Formations in the bottom and Khasib Formations in the top. While the reservoir characteristics were calculated using the log set in terms of petrophysical properties. The reservoir characteristics destroy and decrease to the south of Ratawi area because of the abundance the facies of the deep marine environments. Furthermore, it was predicted that Mishrif Formation has good reservoir characteristics to the other directions, especially to the east, contrary to the previous expectations.

Constraining stratal architecture and pressure barriers in the subsalt Karachaganak Carboniferous carbonate platforms using forward stratigraphic modelling

Predicting reservoir quality and pressure barriers is a challenging task in carbonate systems. In this paper, we present new model results from the Lower Carboniferous Serpukhovian carbonates in the Karachaganak Field (Northern Kazakhstan), which is characterized by complex facies architectures and reservoir compartmentalization. The Serpukhovian sequence at Karachaganak is poorly imaged by seismic due to the presence of thick Permian salt canopies. The carbonate sequence comprises two carbonate build-ups: a larger Main build-up (MBU) in the eastern portion of the field, and a smaller isolated Western build-up (WBU). We used diffusion-based DionisosFlow forward stratigraphic modeling (FSM) coupled with a CougarFlow sensitivity analysis workflow to (1) review sub-salt seismic horizon picks based on process-modeling constraints, (2) understand the regional controls on the stratigraphic stacking patterns, (3) understand the distribution of reservoir facies, including potential lateral pressure barriers, and (4) constrain the impact and uncertainties of our choice of boundary conditions in the model. Results point out the need for revisions of existing reservoir-scale static models as FSM simulations indicate that the current seismic reflector pick for the base of the Serpukhovian Stage below the WBU is incompatible with the seismic geometries and facies distribution for this system. To reconcile modelling results with existing seismic geometries, the base of the Serpukhovian stage is expected to be about 180 m higher in the stratigraphy. This suggested revision is also supported by the drilling of a recent well that penetrated the top of the Permian 200 m higher in the stratigraphy on the WBU than anticipated. Modeling results also show that fast regional subsidence rates were the primary control for the Early Serpukhovian aggradational stacking pattern, but that slowing subsidence rate during the Late Serpukhovian due to the Uralian orogeny resulted in a switch to progradational sequence patterns. The forward stratigraphic model additionally demonstrates the major role of wind direction and short-term eustatic changes on the presence and distribution of reefs and breccia reservoir facies. Models show that the clinoforms’ angle of repose varies between the leeward and windward sides of the build-up, which leads to the deposition of mud draping on the leeward side that acted as fluid barriers. The presence and distribution of the reservoir and mud facies in the model can explain the observed reservoir compartmentalization at Karachaganak. Finally, our forward stratigraphic modeling workflow coupled with uncertainty analysis provides new quantitative constraints to understand the impact of diffusion coefficients and sediment production rates on the vertical and lateral reservoir heterogeneities and associated lateral pressure-barriers.

Sequence stratigraphic controls on reservoir characterization and architectural analysis: A case study of Tovo field, coastal swamp depobelt, Niger Delta Basin, Nigeria

The decline in reservoir pressure and rate of production have prompted a series of studies to better characterize and define reservoir architecture in anticipation of ultimate recovery of the hydrocarbon deposits by a fluid-injection program in the Tovo field located in the coastal swamp depobelt of the Niger Delta Basin. This study utilizes the integration of well logs, biostratigraphic and 3D seismic data sets to establish a third-order sequence stratigraphic framework consisting of fourth-order sequences. It facilitates the construction of predictive depositional models that elucidate reservoir facies distribution, and architecture. Three types of reservoir deposits that are generally composed of channel and shoreface sandstone facies have been considered: lowstand fluvial sediments with a bulging geometry, marine-influenced sandstone deposits defined by strike-oriented tabular geometry, and highstand fluvial channel sandstone deposit characterized by dip-oriented lobate geometry. Intrareservoir shale, discontinuous shale stringers and/or shale lensoids, which are products of channel avulsion, overbank sedimentation, and marine flooding define the internal reservoir architecture. Their overall reservoir quality is very good. However, the fluvial-dominated sandstone deposits show a wide range of porosity and permeability across individual wells. Conversely, the marine-influenced reservoir deposits show better lateral and vertical sand connectivity as suggestive of near similar in the range of porosity and permeability values across the field, implying a better oil sweep efficiency and fluid-injection potential. The results of this study suggest that the depositional environment of sandstone reservoirs of the basin is complex but not infinite in facies distribution. The spatial distribution of these sandstone reservoir facies is related to changes in local accommodation space in the basin. This study, therefore, demonstrates the importance of evaluating the impact of sequence stratigraphic controls on reservoir characterization and architecture of hydrocarbon-bearing sandstones for optimum exploration and production in clastic depositional settings.

Structural and stratigraphic evolution of the Mid North Sea High region of the UK Continental Shelf

Interpretation of newly acquired seismic and legacy well data has led to a greater understanding of the Upper Paleozoic–Recent geological evolution of the Mid North Sea High (MNSH), an under-explored region of the North Sea. The position of granite-cored blocks controlled the distribution of Devono-Carboniferous highs and basins before Variscan uplift led to peneplanation and the creation of the Base Permian Unconformity. The MNSH became the dominant feature during the Permian when it formed a west–east-striking ridge between the Southern and Northern Permian basins. Following a period of non-deposition, sedimentation was renewed in the Late Permian–Triassic before Middle Jurassic doming caused uplift to the NE. Subsequent Late Jurassic North Sea rifting transected the MNSH to create the Western Platform between the Central Graben and Moray Firth rift arms. Following Cretaceous post-rift deposition, the area experienced a significant easterly tilt in the Cenozoic that led to the demise of the MNSH as a prominent topographical feature. The tectonic and stratigraphic evolution exerts a strong control over reservoir facies distribution, source-rock deposition and maturation. However, the area is not barren of petroleum potential. Despite the lack of Upper Carboniferous source rocks over large areas, hydrocarbon potential is evident through shows in legacy wells, indicating the Lower Carboniferous as a potential source rock. Cenozoic uplift to the west imparted a regional tilt, the effects of which remains key to unlocking the area's prospectivity since it reconfigured structures and formed remigration pathways from Lower Carboniferous and Jurassic source rocks. Thematic collection: This article is part of the Under-explored plays and frontier basins of the UK continental shelf collection available at: https://www.lyellcollection.org/cc/under-explored-plays-and-frontier-basins-of-the-uk-continental-shelf

The Hayfield Sandstone Play: the characterisation of a Mesoproterozoic sourced, Proterozoic sandstone reservoired, tight oil and gas play in the Beetaloo Sub-basin

The Hayfield Sandstone is a Neoproterozoic, 10–15 m thick, very fine- to fine-grained sandstone, interpreted to have been deposited in a shelfal-marine environment. The reservoir sandstone is characterised by high porosity and low matrix permeability, which is complimented by partially mineralised open fractures which may contribute significantly to overall system permeability. Hydrocarbon phase across the identified play fairway is interpreted to range from a gas with the potential for condensate and liquefied petroleum gas streams to a light, ~38 API gravity oil. The extent of the prospective play fairway and the distribution and connectivity of reservoir facies is poorly constrained due to a limited number of well penetrations and poor resolution 2D seismic data. From the wells drilled to date, the gross area of the prospective play fairway could be as low as 300 km2 or greater than 1500 km2.

Characterizing the growth of structures in three dimensions using patterns of deep-water fan and channel systems

Channel and fan systems in deep-water continental slopes respond to active deformation creating patterns within growth strata that record the history of deformation. These patterns provide important constraints on the timing and kinematics of structural deformation. We show how the location and orientation of depositional systems are affected by the emergence and growth of fault-related folds. We develop two end-member three-dimensional kinematic models to describe the reaction of channels to growing structures. In the first model, structures grow through lateral propagation, causing channels to migrate laterally outward through time. In the second model, structures grow with fixed lateral limits, and channels maintain relatively fixed positions through time. We compare our models with structures in the outer fold–thrust belt in the Niger Delta. The initiation of structural growth is recorded by a dramatic change in channel architecture with a reduction in sinuosity followed by deflection around the lateral edges of folds. Subsequently, in some examples, channels maintain relatively fixed positions through time, reflective of fold growth with fixed lateral limits, whereas other examples show channels that migrate laterally outward through time, reflecting fold growth by lateral propagation. We corroborate our interpretations by comparing our analysis of channel distribution to isopach and structure contour maps. Results indicate that structures in close proximity can grow through different mechanisms or a combination of mechanisms over different stages in their development. The resolved patterns of channel and fan systems provide insight into the complex distribution of reservoir facies, which has important implications for reservoir characterization.

Stratal architecture of a halokinetically controlled patch reef complex and implications for reservoir quality: A case study from the Aptian James Limestone in the Fairway Field, East Texas Basin

Widespread carbonate platform growth in the Cretaceous Tethys is associated with expansive reef margin and interior patch reef development. These reefs and their associated facies have the potential to be significant hydrocarbon reservoirs, but characterization is challenging because of complex facies distributions, inadequate understanding of biotic communities and processes impacting their development, and difficulties delineating timelines in systems that build their own topography. Other factors that may impact underlying topography, such as tectonics or halokinesis, further complicate the story. This study delves into these complexities in a dataset from the Fairway Field, a large oil and gas field (115 km2, 410 million barrels original oil-in-place) that produces from the Aptian James Limestone in the East Texas Basin, Texas, USA. The field contains a patch reef complex, here defined as an assemblage of patch reefs that grew near each other without necessarily being physically connected, that has significant lateral and vertical facies heterogeneity. Previous attempts at characterization have failed to fully recognize the importance of its proximity to four salt domes, which modified topography and influenced deposition prior to and during reef development. Here, we reassess the stratal architecture of the Fairway Field from a sequence stratigraphic perspective, with the goal of augmenting understanding of timing of reef development and facies distributions and ultimately building a better stratigraphic framework for a halokinetically influenced patch reef complex. Core descriptions and core-calibrated wireline-log correlation across the field yield a model that explains the relationship between halokinetic topography, energy regime, relative water depth, and reef- and reef-associated facies development. Porosity and permeability measurements taken across the field are analyzed to determine best reservoir facies and their distribution. The new stratigraphic model is useful for predicting facies architecture in other analogous reef complexes, such as those elsewhere in the Gulf of Mexico and in the Middle East; its tie to reservoir facies distributions also improves its utility for exploration purposes. Furthermore, this work demonstrates that halokinesis has a major impact on carbonate development and necessitates a new generalized model for halokinetically altered carbonate platforms.