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Conceptual depositional model for the Kharaib Dense 1, Shuaiba 3 and Shuaiba 2 units (including also Kharaib Dense 1) in the study area.
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Reservoir quality of carbonate rocks is usually controlled by the interplay of both the primary depositional and secondary diagenetic parameters. The assessment of the respective impact of these controls together with the understanding of the field-scale sedimentological organisation and diagenetic trends assist in the reconstruction of reservoir a...
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... Aptian is marked by a notable crisis in carbonate production (e.g. Follmi, 2012), the first signs of which is reflected by higher clay/organic matter content within Shuaiba 2. For this reason, the depositional model of Shuaiba 2 has been separated from the illustration of the depositional organisation of the Kharaib Dense 1 and Shuaiba 3 deposits ( Figure 5). Depositional model. ...
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... Kharaib Dense 1 to Shuaiba 2 succession developed into four depositional environments ranging from an inner ramp (IRME.a and IRME) to outer ramp settings (OR; Figure 5). Depositionally, the Kharaib Dense 1 deposits reflect the most proximal position while Shuaiba 2 represents the most distal deposits of the whole succession. ...
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... Shuaiba 3 depositional model ( Figure 5) comprises distal mid-ramp and outer ramp depositional environment. Whilst the latter is characterised by homogeneous mudstones/wackestones due to very low-energy conditions, the former is heterogeneous as it includes wacke-packstones to floatstones beds interbedded with mudstone/wackestone textures. ...
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The present work focuses on the upper Cretaceous (Cenomanian-early Campanian) carbonate successions in selected wells from northwestern Iraq. These successions are represented by Gir Bir (Cenomanian-early Turonian), Wajna (late Santonian) and Mushorah (early Campanian) Formations. The succession has affected by early burial near-surface, unconformi...
Citations
... Traditionally, lithofacies attributes such as depositional environment, mineralogy, and texture have been utilized as primary controls because they resonate with geologists' knowledge and experience. In this approach, petrophysical parameters were mapped to depositional attributes, which provided spatial rules (e.g., Al Awadi et al., 2017;Jeong et al., 2017). ...
Commonly used carbonate rock-typing methods estimate statistical relationships between geological parameters and the core-to-log domain and distribute the resulting petrophysical rock types in reservoirs, with spatial guidance from depositional concepts. This approach is based on the paradigm that there are statistically meaningful relationships between lithofacies and rock properties. We challenge this paradigm by introducing a petrophysical rock-typing method that is unbiased by sedimen-tological concepts. The advanced rock-typing method presented in this paper combines electrofacies, pore types from core and logs, and statistically relevant depositional attributes to define highly predictable petrophysical rock types. Spatial rules are derived from the determination of petrophysical categories in well domains or via distribution in porosity cubes from seismic data. We present the implementation of this workflow in four case studies representing marine and lacustrine carbonates in green to mature field development settings from the Middle East, Brazil, and Angola. Our results unanimously show late burial diagenesis as the primary process correlating with petrophysical properties relevant to reservoir characterization in both core and log domains; early and shallow diagenesis has a minor correlation, whereas lithofacies show negligible correlation. This indicates that diagenetic modification should be used as a primary driver for populating reservoir quality parameters in space, whereas sedi-mentary lithofacies and their distribution are virtually irrelevant. Advanced rock-typing provides a systematic approach to defining petrophysical rock categories and the spatial trends that underpin reservoir behaviors and can be applied in exploration,
... The Kharaib formation has depositional environments ranging from distal mid-ramp to inner ramp setting, and the upper part of the Kharaib formation is composed of clean carbonates with textures mainly ranging from wackestones to floatstones/ rudstones. The Shuaiba formation overlays the Kharaib formation, and the mid to lower part of Shuaiba formation has mud-dominated textures (Jeong et al. 2017). Three cores with a diameter of 1.5 inches were retrieved from the Shuaiba and Kharaib formations: Core A and B from the Shuaiba formation at a depth of 2330.1 m and 2378.1 m, respectively, and Core C from the Kharaib formation at a depth of 2402.7 m. ...
... The simulation results were limitedly compared with the experimental results obtained from the core analysis at the investigation site. The orange asterisk symbols indicate the experimentally measured porosity and permeability of the cores retrieved from the study area (Jeong et al. 2017). The porosity ϕ of cores ranged over 0.05-0.30, ...
... Solid and cross symbols indicate the simulation results from cubical subdomains and resized cylindrical domains, respectively. Orange asterisk symbols and lines are related to the experimental results(Jeong et al. 2017). a Results of Core A and B b Results of Core C, and c Results of simulations and the permeability estimated by the conventional Timur-Coates model Content courtesy of Springer Nature, terms of use apply. ...
Due to the heterogeneity of carbonate rocks, some small pores partially undertaking flows are unresolved in X-ray CT images, therefore have been not appropriately considered in direct flow simulation. By the data fusion of two non-destructive measurements from X-ray CT imaging and nuclear magnetic resonance measurement, this study proposes the construction of ternary-phase domain including resolved apparent-pore, unresolved gray-pore, and resolved solid voxels. Gray-pore voxel containing the unresolved pore is characterized as a microporous structure with equivalent local hydraulic properties according to CT number and pore size distribution. From X-ray CT images of reservoir carbonate rocks from Abu Dhabi, ternary-phase domains are constructed consistently to figure out local and overall flow behaviors despite the different image resolutions. Stokes–Brinkman flow simulation shows that although some apparent-pore volumes are disconnected from each other due to limited resolution, fluid flow can be passed by the gray-pore region. Additionally, a modified hydraulic tortuosity model is proposed to evaluate the tortuosity of the ternary-phase domain because the conventional hydraulic tortuosity model for the binary-phase domain underestimates the tortuosity of the ternary-phase domain.
... These intervals vary in thickness from 30 cm to 2.70 m (average of 0.76 cm) in subzone 3U and 15 cm-90 cm (average of 0.43 cm) in subzone 2. These packstone to grainstone and rudstone-grainstone intervals are poorly correlatable between wells (Fig. 22), exposing the difficulty in predicting lateral facies variability, and suggesting a limited lateral extension of these depositional bodies. Such small-scale variability has also been identified in different fields in Abu Dhabi (Alsharhan, 1990;Jeong et al., 2017;Ehrenberg et al., 2016Ehrenberg et al., , 2018. These small-scale heterogeneity and facies trends of subzones 3U and 2 have been reported to represent the deposition of sediments transported over relatively short distances, under the influence of moderate to strong hydrodynamic activity, or storm activity (e.g. ...
Outcrop observations offer valuable insights into depositional architecture as a primary control on facies and reservoir properties variability, in contrast to subsurface cases, where observation points are limited to well locations. Two dominantly high-energy shallow-water carbonate case studies were analysed, including outcrops of a Bathonian-Callovian (Middle Jurassic) carbonate succession in the Maciço Calcário Estremenho (MCE) region, central Lusitanian Basin, Portugal and a Barremian (Lower Cretaceous) subsurface carbonate reservoir from Abu Dhabi (U.A.E.). The MCE succession comprises a range of inner ramp deposits, which consist of oobiointraclastic grainstones, biointraclastic grainstone-rudstones and coral/algal boundstones, mostly defining sandbody and coral biostrome units which represent potential reservoir facies, as suggested by their textural types and locally significant porosity, though now mostly occluded by calcite cements. The succession is exposed in recently-cut quarry faces showing minimal weathering, hence allowing for detailed observations on depositional geometries. The U.A.E. case study is a world-class reservoir characterized by mid-ramp to high-energy inner-ramp facies, ranging from biomicritic wackestones to biointraclastic packstones, bioclastic packstones, grainstones and rudstone-grainstones, interpreted using core and thin section data from four onshore wells.
In the analysed outcrops, strong continuity of main major bedding surfaces is observed at larger scales (dozens to hundreds of metres), with strong spatial variability seen at smaller centimetre to metre scales and depositional geometries varying from tabular, wedge-like, lensoid bodies and coral buildups. The subsurface case also shows strong continuity of larger-scale depositional packages (at kilometre scale) and moderate to strong small-scale heterogeneities at centimetre to metre scales. Discontinuity-bounded intervals are observed in the younger section of this reservoir generally showing stronger vuggy porosity and coarser skeletal grains at the base, while the youngest set of these intervals are characterized by an abundance of rudist fragments. The interpreted depositional geometries in this reservoir consist of tabular, wedge-like and lenticular geobodies of limited lateral extension.
The multi-scale heterogeneity in both these case studies is strongly influenced by depositional factors related to hydrodynamics and the balance between carbonate factory productivity and accommodation space, affecting lateral facies migration and creating complex depositional patterns. This study illustrates how the perception of heterogeneity, though reflecting an intrinsic property of carbonate rocks, is influenced by the scale of observation and, from a reservoir perspective, both cases show that addressing small-scale heterogeneities and associated geological factors in higher detail is vital in defining conceptual geological models for a better understanding of the reservoir.
... Yose et al. 2006;Al Mansoori et al. 2008;Ehrenberg et al. 2008; Buchem et al. 2010a, b;Lawrence et al. 2010;Yin et al. 2010;Koppen et al. 2015;Paganoni et al. 2015;Wazir et al. 2015;Wu and Ehrenberg 2016;Jeong et al. 2017;Jingjing et al. 2018). ...
This work presents a new open-source carbonate reservoir case study, the COSTA model, that uniquely considers significant uncertainties inherent to carbonate reservoirs, providing a far more challenging and realistic benchmarking test for a range of geo-energy applications. The COSTA field is large, with many wells and large associated volumes. The dataset embeds many interacting geological and petrophysical uncertainties in an ensemble of model concepts with realistic geological and model complexity levels and varying production profiles. The resulting number of different models and long run times creates a more demanding computational challenge than current benchmarking models.
The COSTA model takes inspiration from the shelf-to-basin geological setting of the Upper Kharaib Member (Early Cretaceous), one of the most prolific aggradational parasequence carbonate formations sets in the world. The dataset is based on 43 wells and the corresponding fully anonymised data from the north-eastern part of the Rub Al Khali basin, a sub-basin of the wider Arabian Basin. Our model encapsulates the large-scale geological setting and reservoir heterogeneities found across the shelf-to-basin profile, into one single model, for geological modelling and reservoir simulation studies.
The result of this research is a semi-synthetic but geologically realistic suite of carbonate reservoir models that capture a wide range of geological, petrophysical, and geomodelling uncertainties and that can be history-matched against an undisclosed, synthetic 'truth case'. The models and dataset are made available as open-source to analyse several issues related to testing new numerical algorithms for geological modelling, uncertainty quantification, reservoir simulation, history matching, optimisation and machine learning.
... The reservoir quality of carbonate rocks is usually controlled by the interplay of both the primary depositional and secondary diagenetic parameters. The assessment of the respective impact of these controls together with the understanding of the field-scale sedimentological organization and diagenetic trends assists in the reconstruction of reservoir architecture (Jeong et al. 2017). ...
The reservoir characterization and rock typing is a significant tool in performance and prediction of the reservoirs and understanding reservoir architecture, the present work is reservoir characterization and quality Analysis of Carbonate Rock-Types, Yamama carbonate reservoir within southern Iraq has been chosen. Yamama Formation has been affected by different digenesis processes, which impacted on the reservoir quality, where high positively affected were: dissolution and fractures have been improving porosity and permeability, and destructive affected were cementation and compaction, destroyed the porosity and permeability. Depositional reservoir rock types characterization has been identified depended on thin section analysis, where six main types of microfacies have been recognized were: packstone-grainstone, packstone, wackestone-packstone, wackestone, mudstone-wackestone, and mudstone. By using flow zone indicator, four groups have been defined within Yamama Formation, where the first type (FZI-1) represents the bad quality of the reservoir, the second type (FZI-2) is characterized by the intermediate quality of the reservoir, third type (FZI-3) is characterized by good reservoir quality, and the fourth type (FZI-4) is characterized by good reservoir quality. Six different rock types were identified by using cluster analysis technique, Rock type-1 represents the very good type and characterized by low water Saturation and high porosity, Rock type-2 represents the good rock type and characterized by low water saturation and medium–high porosity, Rock type-3 represents intermediate to good rock type and characterized by low-medium water saturation and medium porosity, Rock type-4 represents the intermediate rock type and characterized by medium water saturation and low–medium porosity, Rock type-5 represents intermediate to bad rock type and characterized by medium–high water saturation and medium–low porosity, and Rock type-6 represents bad rock type and characterized by high water saturation and low porosity. By using Lucia Rock class typing method, three types of rock type classes have been recognized, the first group is Grain-dominated Fabrics—grainstone, which represents a very good rock quality corresponds with (FZI-4) and classified as packstone-grainstone, the second group is Grain-dominated Fabrics—packstone, which corresponds with (FZI-3) and classified as packstone microfacies, the third group is Mud-dominated Fabrics—packstone, packstone, correspond with (FZI-1 and FZI-2) and classified as wackestone, mudstone-wackestone, and mudstone microfacies.
... Diagenesis is often studied in detail by examining petrographic thin sections where cross cutting relationships allow the paragenetic order to be established. Some studies have found that the impact of dissolution and cementation is minor in Thamama Group reservoirs, emphasizing the role of fracture network in creating connectivity (Jeong et al., 2017). ...
Most of the hydrocarbon reservoirs in the world are carbonates, and most of these carbonate reservoirs are fractured. Fractures can form due to tectonic activity, mainly associated with fold and faults, and as a result of diagenesis. In many cases, the fractures in carbonates are cemented due to fluid flow, where these fluids precipitate cements. The presence of fractures can enhance reservoir fluid flow if the fractures were open and connected. This thesis focuses on carbonate reservoir fractures, and understanding the evolution of fluids from the cements that have precipitated within them. This thesis relates regional tectonic events to the formation of fractures, and of the environment and temperature of the fluids of precipitation in cement fractures the Early Cretaceous Thamama Group, in the United Arab Emirates (UAE). First, samples were studied from the subsurface in a highly faulted oil Field (A) located in South East Abu Dhabi. Core samples were taken from wells close to major faults in the field in both oil and water legs. Second, fractures in outcrop in Wadi Rahaba, Ras Al Khaima (RAK) in the Northern Emirates were studied where the Upper Thamama Group is exposed. The field study in the outcrop included the fracture orientation and cement types. The fractures in the outcrop were divided into two main generations, F1, (en-echelon) and F2 and they were both fully or partially cemented. The main tectonic events that affected the fracture formation in the Thamama Group are foreland autochthon in the Precambrian to Lower Cretaceous, a frontal triangle zone in Neogene and Dibba zone which consists of Hawasina units (Triassic to Cretaceous), and the Sumeini units (Lower to Middle Cretaceous). F1 is related to the NS orientation fracture system consistent to the Arabian Trend sets caused by Cenozoic compression. F2 is related to the EW orientation fracture system matching Tethyan extensional trend sets. Petrographic analysis of the subsurface thin sections revealed the presence of three main sets of fractures. Fracture Set 1 (cemented), Fracture Set 2 (open) and Fracture Set 3 (cemented, only in Lower Thamama). The fracture cement included equant and blocky calcite as well as saddle dolomite. Cathodoluminescence (CL) analysis assigned the number of cement zones in each cement type in the fractures, and revealed more cement zones in the Lower Thamama reservoirs than the Upper. The most important diagenetic events were cementation and dissolution, which took place towards the end of the paragenetic sequence. The reservoirs contained significant amounts of stylolites, dissolution seams and bitumen, which were associated with most of the dissolution events. mMg/mCa obtained from in situ elemental analysis showed variation through the calcite and dolomite cement zones in the different reservoirs of the Thamama Group. This was inferred to be due to temperature changes. The Upper Thamama Reservoirs (A, B, and C) show lower mMg/mCa (0.072-0.48) than the Lower Thamama reservoirs (F,G) (0,4-1.3), meaning that the Upper Thamama fracture calcite cements were precipitated at higher overall temperatures than the Lower Thamama reservoirs. Mn-Fe analysis allowed an understanding of the redox index through the different cement zones, in both Fracture Set 1 and Fracture Set 3. Analysis of Sr showed the absence of exotic fluids role in the diagenetic system. In-situ (SIMS) δ18OVPDB values were obtained for the calcite cementation history of the two fracture sets in the five reservoirs of the Thamama Group. The δ18OVPDB analysis indicated that Fracture Set 1 has a longer cementation history than Fracture Set 3, and has wider range of temperatures (58-128°C). A comparison of the outcrop analysis results and the subsurface reservoir was established at the end to distinguish the similarities and differences between the subsurface and outcrop in fracture types, fracture cement types and characteristics of the elemental analysis curve behaviours. The fracture cement in both subsurface and outcrop seemed to be precipitated at deep burial environment.
Sedimentological investigation of 150 m drill cores and well log analyses, including gamma-ray, resistivity, sonic, neutron, density logs, were conducted to constrain the impact of depositional facies on reservoir quality distribution in limestone succession of the Yamama Formation (Early Cretaceous), Nasiriya Oilfield, southern Iraq. Understanding the factors controlling reservoir heterogeneity in carbonate reservoirs is crucial for developing geological and reservoir models. Nine microfacies were identified: peloidal oncoidal grainstones-rudstones, skeletal cortoids packstones, skeletal dasyclads wackestones, pelletal packstones-grainstones, cortoidal peloidal grainstones, ooidal peloidal grainstones, skeletal grainstones, bioturbated dolomitic wackestones, and spiculitic skeletal mudstones-wackestones. The formation was deposited in open-marine shallow-water carbonate ramp, ranging from the intertidal to outer-ramp during the Berriasian-Valanginian. The depositional ramp was characterized by grainstones shoal barriers in the distal inner-ramp. Sea level fluctuations significantly influenced the vertical facies and reservoir quality distribution. The grain-supported, distal inner-ramp shoal facies formed the reservoir units, while the mud-supported, middle-outer-ramp facies are impervious units. Diagenetic processes, including dissolution of skeletal allochems, physical and chemical compaction, dolomitization, and cementation, have variably affected reservoir quality. Dissolution enhanced porosity by creating vuggs, while compaction and cementation often reduced porosity. Nevertheless, early diagenetic circumgranular calcite and small amount of scattered equant and syntaxial calcite overgrowths helped protecting the grain-supported limestones from physical compaction and thus preserved interparticle pores (≤ 22%) at depth (>3100 m). Conversely, equant calcite cement, which occurs in substantial amounts, has reduced porosity by filling the interparticle and moldic pores. Reservoir heterogeneity of the formation is attributed to depositional facies, which control the texture of the sediments, and to various types of diagenetic alterations.
The Lekhwair Formation, a prominent geological unit within southeastern Abu Dhabi, has recently been established as an oil-bearing reservoir outside of the traditional giant fields in the region. This study utilizes petrography and petrophysical evaluation to understand the Upper Lekhwair relationship between the reservoir quality and depositional environment. Variability in the thin Upper Lekhwair units creates challenges in predicting reservoir quality while drilling horizontal wells, identifying prospects, and optimizing hydrocarbon recovery efforts. This study will expand on the regional understanding of the Upper Lekhwair depositional system and reservoir characteristics to an oil-bearing area not previously investigated.
The Lekhwair Formation was deposited on a wide carbonate ramp setting, with depositional environments ranging from proximal mid-ramp to intertidal. Well log observations across the area show variability in porosity and thickness in most of the reservoir units but little variability in the intraformational seals known as ‘Dense’ zones. Reservoir variability is predominately related to the dynamic nature of the inner-ramp shoal system, which has sub-regionally displayed rapid facies changes between grainstones and mud-dominated packstones within the same zone over short distances (e.g. 2 km). The study noted high abundance of laterally inconsistent grainstones and rudists in the upper most reservoir units. The relationship between these rapid lateral changes between inner ramp mud-dominated and grain-dominated sediment is likely related to local build-ups on the inner ramp. Unlocking this relationship will unlock new exploration strategies.
Detailed well-log interpretations, including gamma-ray, density, neutron, and resistivity, alongside petrographic analysis of 100 samples over 170 m of drill cores, have revealed factors influencing reservoir heterogeneity in the Yamama Formation, Ah’Dimah Oilfield, southern Iraq. The formation comprises four reservoir units (YA-YD) separated by four non-reservoir units (BA-BD). The reservoir units are subdivided into subunits. YB2, YB3, and YC demonstrate the best reservoir quality, while YD2 is water-bearing. Seven microfacies were identified within both reservoir and non-reservoir units, deposited in a shallow carbonate ramp. These include bioclastic wackestone, Lithocodium-Bacinella float/boundstone, peloidal cortoid intraclast grainstone, reefal bioclastic rudstone, bioclastic foraminiferal wacke/packstone, miliolidal pack/grainstone, and spiculitic foraminiferal wackestone. Despite the deep burial depth of the formation (> 4000 m), it maintained good porosity values in most intervals, reaching up to 20%. Early isopachous cement protected porosity and dissolution enhanced porosity, while cementation, compaction, and pyritization reduced it. The reservoir units correlate with depositional environments, being deposited in the shoal area, while non-reservoir units were deposited in lagoon, middle, and outer-ramp settings. The Lithocodium-Bacinella float/boundstone and reefal bioclastic rudstone facies, forming reefal patches and build-ups within the shoal, dominated in YB2 and YC. Targeting these patches northeast of Ah’Dimah Oilfield is promising for field development.
