In the western Abu Dhabi, oil fields have been discovered from the Mishrif reservoir (Cenomanian/Turonian). These fields are found in shoal/reef related stratigraphic prospects and composed of grainstone or packstone around platform margin setting. Regional understanding believes that the in-situ Shilaif mudstone is not mature enough to source the overlain Mishrif. So, it is inferred that the Mishrif reserves were charged from Shilaif kitchen of regional syncline through over 100km lateral migration from south to north. However, this accumulation pattern seems presumptive as little solid evidence was reported and little geochemistry measurement have been done previously. To enhance understanding of the Shilaif source characteristics and figure out Shilaif-Mishrif accumulation rules, cuttings, cores from Shilaif and oil samples from Mishrif & Tuwayil were taken. Subsequently, geochemistry assay, oil-source correlation and related research were carried out. The results shows the in-situ Shilaif has abundant organic content with high TOC, HI and bitumen "A" with low maturity. Tmax of Shilaif mudstone yields an average value of 430°C and calculated vitrinite reflectance about 0.6, which means an early oil generation for in-situ Shilaif source. Oil-source correlation indicates a higher maturity of crude oil in the Mishrif & Tuwayil than the in-situ Shilaif. Furthermore, similarities of biomarkers between Mishrif oil and the Ghurab syncline Shilaif source are proved. All these evidences reveal the lateral hydrocarbon migration and accumulation northwards. For the migration pathway, it is inferred the regional unconformity of TopMishrif plays an important role to transfer the hydrocarbon. In Western Abu Dhabi, truncation or depositional hiatus around TopMishrif are not as pronounced as Eastern Mishrif platform, but obvious exposure as well as leaching evidence could be observed from uppermost Mishrif and Tuwayil through core investigation. Besides, almost all the oil shows in Mishrif concentrate around the interface, which further proves the role of the unconformity. The study on Shilaif source characteristics and hydrocarbon migration mechanism enhances the insight into accumulation rules of Cretaceous Petroleum system in Western Abu Dhabi and would guide the further exploration activity.
According to the drilling results in Abu Dhabi, the sweet-gas prospective of the Silurian-Permian pre-Khuff clastics is risked by the reservoir uncertainty controlled by different types of clastics. Previous studies focused on well-scale deposition analysis barely reflects the regional sedimentary geometry nor predicts the distribution of different sand-bodies in the pre-Khuff sequences. To better map the play-fairway and to mitigate the drilling uncertainty, it is of significant importance to model the regional depositional settings with different reservoir sands based on the integrated sediment study. The regional sequence framework was based on the biostratigraphy study and log cycles. To model the original deposition, eroded sequences and re-worked sediments were re-constructed based on the near offset data. The plate-scale depositional model was integrated with Abu Dhabi sedimentary records based on cores, cutting description and log interpretation to create a statistics database of depositional settings in each sequence. Training images that accommodate the changes in sedimentary records were created adapting seismic patterns and subsequently were used for the multi-point statistics and object modeling. After the Silurian marine-delta deposition, the continuous non-deposition in southern onshore area and the intermittent erosion in offshore due to periodic salt movement suggests a successive deepening of the paleo-relief to northern Abu Dhabi. The sea-level drop since Silurian creates the marine to continent transition and results in the prograding of continent sediments to the north following the relief of the Paleozoic salt withdraw basin. The Devonian dolomite-anhydrite sediments indicate the extension of marine carbonate from Saudi, Iraq and Kuwait to northwest offshore Abu Dhabi. After the Carboniferous glaciation, the terrigenous sediments become dominant in Berwath, Unayzah and Basal Khuff Clastics. The south and east of Abu Dhabi is pre-dominantly fluvial original, while the west area records both fluvial and Aeolian deposition. The widespread of Aeolian sands is compromised by the flooding events of fluvial and sheet-flow. The mud coated fluvial sands can preserve fairly better permeability than the well-sorted Aeolian sands due to the inhibition to quartz cements, which makes it also primary reservoir target. The Western and central offshore areas at the transition of Aeolian-fluvial sands and floodplain muds are more favorable for the development of reservoir and seal interlayering. Rather than assigning one dominant facies to each pre-Khuff formation as the previous work, the regional stochastic model differentiates fluvial channels, crevasse splays, aeolian dunes, sheet-flood and marginal marine/lacustrine deposits in each sequence based on solid well data and regional statistics. Therefore, improve the understanding of the stacking patterns of reservoirs and seals that can be used to characterize the pre-Khuff hydrocarbon behavior, integrating studies of structure growth, burial and maturation history.
Carbonate reservoirs of the Middle East are known for exhibiting highly heterogenous nature in terms of reservoir properties within microscopic intervals of the reservoir, making it difficult to characterize and predict. An integrated approach involving detailed understanding of the fluids volumes porosity distributions, permeability systems, rock textures, reservoir rock types, and natural fracture distribution at different scales is needed. Accurate characterization for the flow networks, complicated by fracturing and diagenesis is fundamental to achieving realistic prediction, better production performance, and increased recovery. The rock texture in carbonate reservoirs is very unstable and continuously undergoing to multiple stages of dissolution, precipitation, and recrystallization, which obscures any relationships that might have existed between depositional attributes, porosity, and permeability. Fractures make it more complex with their different morphology, often further convoluted by leaching through them. Different measurements are needed to build a realistic model of the petrophysical properties of a carbonate formation. The standard resistivity and porosity measurements are often not sufficient to resolve changes in pore size and texture, so additional measurements are required. Workflows using borehole images can be used to extract information on different textural elements and porosity types. With the newly introduced workflow secondary porosity types are distinguished from matrix porosity and proxies for permeability are calculated. This workflow integrates borehole images and other petrophysical data in sequential steps and provides important reservoir parameters. With the suggested analytical workflow, it is possible to classify the different types of pore space such as connected to vugs (vug to vug), isolated, connected to fractures, aligned at bed boundaries, or within the rock matrix. The contribution of these different pore types to the total porosity of the formation is quantified in addition to the geometric information of different types of heterogeneities. In addition, the connectedness of the different types of porosity is quantified. The connectedness log describes the quantity of connected spots detected from the electrical borehole image and is used as a predictive measure for identifying zones of higher or lower permeability. During operation it serves as an indicator for determining the perforation intervals, in static reservoir modeling it serves as a permeability driver to improve reservoir mapping. We demonstrate an example where the connectedness successfully predicted productive zones, proven by production logging.
As the demand for natural gas is increasing, the exploration and appraisal activities for unconventional gas resources is expanding and becoming significant to fulfill the global demand. These Unconventional resources are known to have complex geochemistry and rock physics. Understanding the complex nature of unconventional rocks is challenging and requires comprehensive integration with an advanced reservoir characterization approach. In this study, a comprehensive integrated rock characterization workflow was designed to understand the challenges and uncertainties associated with the Diyab Formation unconventional rocks. More than 800 ft of unconventional cores were analyzed to characterize the Jurassic carbonate succession of Jubaila, Hanifa and Tuwaiq Mountain Formations through an integrated workflow. The workflow includes core and OH logs based initial rock classification through machine learning known as "Heterogeneous Rock Analysis" (HRA). Based on HRA, the samples selection for Unconventional and advanced Geomechanical core analysis was applied, followed by core data interpretation, core to logs integration and refining reservoir quality. Unconventional and advanced core analysis in this workflow include but not limited to following types, liquid TRA, TOC, HAWK, Vitrinite Reflectance (VR), Core-NMR T2, MICP, 2D/3D SEM, Dean Stark, XRD/XRF, Geomechanics (Brazil Tensile Strength, Unconfined Compression (UCS), Single (TXC) and Multi Stage Triaxial (MTXC), Multi-Stress Compression (MSC), Biot coefficient test), etc. Core analysis results were interpreted and integrated with the logs to better understand and characterize the unconventional reservoir qualities. Sample selection was performed using all available data, to capture the variations in petrophysics as well as geomechanics and geochemistry, particularly organic matter content, and mineralogy within each identified petrophysical rock class. Core logs, plug analysis, and wireline data have been integrated and generally showed excellent agreement within the range of associated uncertainties, which can be attributed to rock tightness and resolution variations. Geochemistry (TOC, HAWK & VR) shows high concentration of kerogen, initially of type IIS but presently with low HI in which maturity reflects the dry gas window and possible condensate. Porosity ranges from 2.7% to 8% with a maximum reading reported from MICP data. The 2D & 3D SEM images provided some key findings, associated with different porosities either connected, isolated and/or organic matter porosity systems in given samples. These complex porosities systems cannot be captured by only conventional methods. The organic type of porosity is important as it provides further support to matrix porosity connectivity. Integrating this knowledge with logs, geochemistry, petrophysics and mineralogy helped to refine the initial characterized rock properties. In addition, the geomechanical understanding took the integration step further to identify potential zones for fracking and testing based on the classified stress regime.
The stress field is a complex variable that affects all drilling operations, completions and reservoir performance. From the three components of a non-rotated stress field, the maximum horizontal stress is the more difficult variable to model since cannot be directly measured and involves multiple unknowns. This study presents an advanced geomechanics modeling technique to estimate the most likely horizontal stresses by integrating advanced acoustic measurements, multi-well image interpretation and geomechanics back analysis. The study was carried out in SR wells, a new development zone in the UAE, which targets the fractured and medium porosity reservoirs rocks of Late Permian formation. The estimation of the stress field is necessary not only for well planning but also to understand the occurrence of abundant drilling induced fractures that sometimes mask the natural ones. It will help also to propose location of possible fracture treatments while analyzing possible relationships between fluid flow and the presence of critically stressed fractures. The horizontal stress field was inverted from advanced geomechanics modeling including the elimination of the gas effect, inversion of Shmax from 3-Shear moduli analysis in stress sensitive intervals, image interpretation for stress related and intrinsic features, determination of stress regime Q-factor from Integrated Stress Analysis (ISA) and performing a failure analysis to validate the stress field and calibrating the overall geomechanical model. The calculated maximum horizontal stress from 3-Shear moduli, ISA and failure analysis proved to be consistent in both SR wells, where the Normal stress regime agreed with current structural framework and local geology. The stress direction was also consistent among measurements, although some local stress rotations were observed in specific zones. High angle features such as drilling induced and natural fractures were also consistent with the modeled stress field, where the vertical stress is the maximum principal stress. Mud losses were mainly attributed to the presence of vugs, conductive seams and fracture corridors rather than induced fracturing. The inverted stress field was finally used as input in the Completion Advisor and Fracture Stability workflows and then compared against PLT data in. The results show a good correlation between critically stressed fractures and well productivity in SR wells. The last could lead to optimize the completion strategy in future wells by selecting best intervals for perforating and stimulation based in this integrated approach.
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