Agnihotri, Praveen (ADNOC Onshore) | Pandey, Vikram (ADNOC Onshore) | Thakur, Parmanand (ADNOC Onshore) | Al Mansoori, Maisoon (ADNOC Onshore) | Rebelle, Michel (Total SA) | Smith, Steve (Baker Hughes, a GE Company) | Bhatt, Pranjal (Baker Hughes, a GE Company) | Zhunussova, Gulzira (Baker Hughes, a GE Company) | Hassan, Syed (Baker Hughes, a GE Company)
Holistic assessment of project economics and subsurface characterization provides a framework to handle challenging reservoirs. Capturing ranked uncertainties based on their impact on the project and meticulous working towards de-risking the project is key for the success of the entire project. Committing increased production from the field is dependent on proper evaluation of the reservoir.
This paper reviews characterization of a tight reservoir deposited in the intra-shelf Bab basin during lower Aptian time. Initial stage reservoir characterization is critical in formulating reservoir development plan and estimating a realistic assessment of rates and volumes for the field.
The target formation is a low-permeability (average permeability 0.5 mD) heterogeneous carbonate reservoir sitting directly above and adjacent to a producing carbonate reservoir. It is essential to understand communication between the zones. The pilot well is drilled with 225 ft of conventional core and quad-combo logs. Advanced logs such as resistivity image, cross-dipole acoustic, nuclear magnetic resonance, vertical interference test (VIT), formation pressure (including pressure transient data), and fluid samples were acquired. The main objectives of the evaluation program were to determine the formation pressure, collect representative oil sample(s), conduct vertical interference tests between the sub-zones and collect appropriate data for geomechanical and rock-physics characterization.
Thorough pre-job planning and cross-discipline cooperation during the operation provided high fidelity log data and interpretation of the data into a coherent result. This included integration of image data with vertical interference tests from the wireline formation tester (WFT) where barriers were confirmed. In addition, NMR permeability was matched and calibrated using pretest mobility measurements and formation pressure data was combined with full waveform advanced acoustic processing to explain the communication between the upper target zone and the lower producing reservoir. Advanced acoustic analysis helped to fully characterize the target formations with stoneley permeability, azimuthal anisotropy, and presence of fractures.
This paper demonstrates the importance of multi-disciplinary team effort in characterization of challenging reservoirs. It highlights the importance of holistic planning before the execution phase, and keeping a focus on the larger goal while executing individual aspect of a complicated project.
Formation evaluation measurements have evolved over decades and occasionally it benefits the industry to provide a review of how the latest logging measurements fit together in an integrated manner, for successful evaluation of a challenging reservoir.
Bin Ishaq, Wala (ADNOC Sour Gas) | Al Darmaki, Fatima (ADNOC Sour Gas) | Lucas, Noel (ADNOC Sour Gas) | Al Mansoori, Mohamed (ADNOC Sour Gas) | Deville De Periere, Matthieu (Badley Ashton and Associates Ltd) | Foote, Alexander (Badley Ashton and Associates Ltd) | Bertouche, Meriem (Badley Ashton and Associates Ltd) | Durlet, Christophe (Laboratoire Biogeosciences)
In the onshore sector of the United Arab Emirates, the Lower Arab D Member (Kimmeridgian) typically encompasses a thick succession of rather homogeneous low-energy mid-ramp carbonate mudstones interbedded with minor storm-induced cm-scale skeletal-rich floatstones. Within these deposits, the pore volume is dominated by locally abundant matrix-hosted micropores, along with variably abundant open to partially cemented fractures, primary intraparticle macropores and rare moulds and vugs. As a result of this variably developed pore system, measured porosity varies from poor to very good, while permeability changes from extremely poor to rarely good. Detailed petrographic observations (thin-sections, SEM) carried out within six cored wells in a sour gas reservoir highlight that the variations in reservoir properties are primarily linked to the micron-scale variations in the micritic fabric. Indeed, anhedral compact micrites with coalescent intercrystalline contacts are associated with very small and poorly connected micropores, while polyhedral to subrounded micrites with facial to subpunctic intercrystalline contacts show locally well-developed micropores and therefore better reservoir potential. δ18O and δ13C isotope measurements do not discriminate both micritic fabrics, indicating a recrystallisation of the matrix within shallow burial conditions. However, bulk XRF measurements, and especially SiO2, Al2O3 and Fe2O3 content indicate that poorly porous anhedral compact micrite host more insoluble material and have been prone to a greater compaction compared to porous polyhedral micrites. Log-derived elastic properties, including Young's Modulus (YME) along with porosity data, have been used in two wells to explore the potential relationship between micritic fabric, porosity, permeability and elastic properties. With the evolution of micritic fabric from anhedral compact to polyhedral / subrounded, Young's Modulus decreases with increasing porosity, indicating a decrease in the overall stiffness of the rock. Based on these two learning wells, specific porosity and YME cut-offs have been identified to discriminate the various micrite fabrics. Those cut-offs have been successfully tested in four other wells used as a blind test for the vertical prediction of the micritic fabrics, in which accurate predictions reached up to 90%. Following these results, porosity and YME cut-offs have been used to produce the first model of the distribution of the various micritic fabrics at the field-scale. These results have a fundamental impact on how sedimentologically homogenous microporous limestones can be described and predicted at the well and field-scales, especially in the context of exploring tight carbonate plays associated with intrashelf basins.
The key ‘flow drivers’ of an Early Cretaceous reservoir are described and correlated region-wide in Abu Dhabi – these are identified as being the same features in a series of fields and being layer-controlled. Three geological drivers control water-cut evolution, showing consistent stratigraphic relationships and, hence, will they provide guidance in both modelling and developing other fields, and in predicting water movement paths elsewhere. This is the first time that assessment and correlation of the key flow drivers has been made country-wide: in different basin settings with different hydrocarbons but with a comparatively consistent reservoir framework. Fractures organised in mechanical layers, connected and diagenetically modified burrows and preferential dissolution comprise the factors. These flow drivers are not randomly oriented within the reservoir but display distinct vertical arrangement that reflects an initial depositional motif. A fining- and deepening-upwards motif results in the algal floatstones concentrated in the lowermost 1/3rd, whilst the burrowed pack- and wackestones dominate the middle ~1/3rd. In the uppermost part nodular stylolitised mudstones prevail, where microporosity dominates and where the strength contrasts increasing cementation result in increasing fracture-prone thin layers that amalgamate towards top reservoir. Despite showing broad stratigraphic discretisation, in detail, some of these features overlap vertically. For example, burrows and fractures may be co-located near their interface; similarly, algal textures may be intertwined with minor fractures in pseudo-stratigraphic layers near base reservoir. This occurs consistently in all fields, irrespective of variation in overall reservoir thickness. Depositional heterogeneity is the key control on the basic reservoir framework, however, the flow driver development (K contrast severity) is further suppressed / accentuated by local to regional diagenetic modification. As all three heterogeneity systems are observed at the same relative vertical position, this reflects a high degree of depositional consistency on the platform passive margin.
Intensity of factors vary from field to field, also systematically between crest and flank areas of a given field. Example wells illustrate the development of all key drivers, to a greater or lesser extent in all fields: thereby, providing a relative ‘flow driver’ potential as a static model input and a dynamic model H-M sensitivity. Factors controlling the basic heterogeneity framework are stratigraphic / depositional, subsequently modified by diagenetic effects. Diagenesis can be represented by field-wide (depth on structure) or local (fault-proximal) controls, which can be compared with other factors, including hydrocarbon type (gas/oil), trap style and deformation intensity, water cut evolution, development scenario, amongst others. Implications of understanding these consistencies in relationships are applicable regionally, and can be used in learnings from one field to another, investigating the reservoir development impact of these drivers under different development schemes, and in assessing simulation history- matching within brownfields and for upcoming greenfield development.
Kumar, Kamlesh (Petroleum Development Oman) | Awang, Zaidi (Petroleum Development Oman) | Azzazi, Mohamed (Petroleum Development Oman) | Hamdi, Abdullah (Petroleum Development Oman) | Hughes, Brendan (Petroleum Development Oman) | Abri, Said (Petroleum Development Oman)
The microporous rock types in Upper Shuaiba are low permeability ( 1mD) rocks occurring in thin (2-5 m) formations within the extensive Upper Shuaiba carbonate formations in Lekhwair. These microporous rocks constitute a significant volume of hydrocarbon in-place. Unlike the higher quality rudist-rich and grainstone rock types, appraisal pilots in the microporous areas have shown poor performance with waterflood development, which is the preferred development concept in the entire Lekhwair field. Two work streams are active in parallel to identify a technically and commercially feasible development option: Phase 1, technology trials to enable a successful waterflood implementation, and Phase 2, further studies to screen the potential of enhanced oil recovery (EOR) techniques and other light tight oil development. The technology trial work stream, initially considered four initiatives targeting injectivity improvement. To date, trials are complete for abrasive jetting and designer acid stimulation, early results are available for Directional Acid Jetting, and evaluation of Fracture Aligned Sweep Technology (FAST) is ongoing with hydraulic fracturing evaluation accelerated to Phase 1 due to synergies with the FAST evaluation.
In early 80's in ADNOC Onshore standard well completion design for gas producers in Reservoir Y of Bab field was a combination of L-80 carbon steel with a downhole continuous corrosion inhibitor injection above the Chemical Injection Valve (CIV) and Corrosion Resistant Alloy (CRA) Incoloy 825 / SM25Cr-75 below the CIV and packer. In 1994 (after 10 years of operation), due to the fact that no integrity issues were observed, it was decided to maintain the same design strategy was followed in all new gas producer wells in this reservoir. Identical design strategy was followed for Reservoir X (Project-I) gas wells which presented less severe fluid conditions.
Taher, Ahmed (ADNOC Upstream) | Celentano, Maria (ADNOC Upstream) | Franco, Bernardo (ADNOC Upstream) | Al-Shehhi, Mohammed (ADNOC Upstream) | Al Marzooqi, Hassan (ADNOC Upstream) | Al Hanaee, Ahmed (ADNOC Upstream) | Da Silva Caeiro, Maria (ADNOC Upstream)
In early Aptian times, subtle tectonic movements may have been activated along the NW-SE strike-slip faults and have resulted in a vertical displacement along these faults. The displacement would have allowed the carbonate-producing organisms to colonize along the shallower southern margin and generate well developed reservoir facies. The basinal facies were deposited to the north of the shelf margin, which is known to be the Bab Basin.
Significant oil was discovered in the Shuaiba shelf facies. However, the lagoonal and basinal facies have potential for discovering a significant volume of hydrocarbon, especially in the fields that are located in the Upper Thamama hydrocarbon migration pathways. This potential is supported by the absence of an effective seal separating Thamama Zone-A from Shuaiba basinal facies above, which allowed for the Zone-A hydrocarbon to migrate vertically into the Shuaiba basinal facies. In addition, this potential was supported by the hydrocarbon shows while drilling and by the interpreted well logs, which confirm the presence of movable hydrocarbon in the Shuaiba lagoonal and basinal facies.
The Shuaiba Formation is comprised of two supersequences (
The Shuaiba basinal facies were deposited in an intrashelf basin that was enclosed by the Shuaiba shelfal facies sediments. This resulted in restricted water circulation, anoxic condition and deposition below the wave base. Such depositional environment is favourable for source rock preservation.
Lithologically, Shuaiba basinal facies consist of pelagic lime-mudstone, wackestone and packstone with abundant planktonic microfossils. These facies are characterized by low permeability values, but their porosity can reach up to 20%. The lagoonal sediments consists of a deepening sequence of carbonate sediments, with shallow marine algal deposits at the base and fine hemipelagic to pelagic carbonates in the upper section.
The differences between the Shuaiba Shelf and the Shuaiba Basin are mainly in permeability values. By applying the latest technology in horizontal drilling and hydraulic fracturing, the Shuaiba basinal facies will produce a significant volume of hydrocarbon.
Kumar, Kamlesh (Petroleum Development Oman) | Azzazi, Mohamed (Petroleum Development Oman) | Hamdi, Abdullah (Petroleum Development Oman) | Awang, Zaidi (Petroleum Development Oman) | Nicholls, Christopher (Petroleum Development Oman) | Lawati, Yousuf (Petroleum Development Oman) | Huseini, Hamood (Petroleum Development Oman) | Abri, Said (Petroleum Development Oman) | Sharji, Hamed (Petroleum Development Oman)
The Upper Shuaiba reservoirs in Lekhwair consist of carbonate formations extending over a very large area (40 km × 40 km). Earlier development projects identified thicker, well-appraised formations, resulting in successful waterfloods. In contrast, challenges have been encountered in some of the waterflood pilots attempting to unlock future development areas. An integrated evaluation of these poor performing areas led to the development of a rock type catalogue that mapped out different rock types and their properties. Initial developments were mostly in high permeability rock types (Rudist Rich and Grainstone) whilst the underperforming pilots are associated with microporous rock characterized by low permeability (~1 mD) and thin formations (2-5m). These microporous rocks are associated with a large hydrocarbon volume in place. Resolving this development challenge is critical in maintaining the company's long-term production targets.
Waterflood is the preferred development concept as it is in line with the existing facilities and infrastructure. The existing pilots demonstrate that low water injectivity/throughput is the key challenge to waterflood feasibility. Conventional acid stimulation does not work in these formations. Four different initiatives, in addition to injection water quality monitoring and improvements, are being tried to ensure successful maturation of microporous resources: Abrasive Jetting: used to create small tunnels up to 3m into the reservoir. Controlled Directional Acid Jetting: using acid to create multiple small laterals (up to 12 m in length) into the reservoir. Designer Acid: acid tailored to improve conventional acid stimulation. Fracture Aligned Sweep Technology (FAST) as implemented in Halfdan field; which creates longitudinal fractures along the length of the well.
Abrasive Jetting: used to create small tunnels up to 3m into the reservoir.
Controlled Directional Acid Jetting: using acid to create multiple small laterals (up to 12 m in length) into the reservoir.
Designer Acid: acid tailored to improve conventional acid stimulation.
Fracture Aligned Sweep Technology (FAST) as implemented in Halfdan field; which creates longitudinal fractures along the length of the well.
The outcome of this study includes identification and mapping of the different rocktypes across the entire Upper Shuaiba; waterflood performance assessment of microporous rocks and new technology trials to accelerate the development of microporous resources. Whilst abrasive jetting has achieved limited success in improving injectivity, result from designer acid stimulation was disappointing. The other two trials are still under evaluation. In case all the initiatives fail to establish the feasibility of waterflood, alternate developments mechanisms are proposed as Phase 2 in the strategy.
This paper highlights how integration between different disciplines can help in maturation of a large resource volume, whilst accelerating its development by standardization of designs.
The field was discovered in 1992. It produces oil and associated gas from two reservoir sub units of the Upper Shuaiba USh3F1 and USh3F2, and exhibits both structural and startighraphical traps. The reservoir units are compartmentalized by NW-trending normal faults into five fault blocks within the same field towards the North East. They are vertically separated by non-reservoir low permeability mudstone facies. US3F2 is setting above Orbitolina shale. The objective is to build a new geological model in a very complex carbonate reservoir, to allow for better reservoir development, and adding new field opportunities using state of art seismic data.
Lower unit (US3F2) consists of an aggradational sequence skeletal peloid-foram packstone/wackestone, and in-situ rudist-algal boundstone/packstone build-ups, which is localized to the NE-trending axis of the field. These sequences are deposited in a low to moderate energy environment. US3F2 reaches a maximum thickness of 50 ft in the rudist build-ups, but the width of the rudist-algal boundstone facies parallel to depositional dip (SE) is only 0.5–0.7 km. Cores exhibit abundant secondary porosity with an average of 30% and permeability up to 700 mD suggesting early subaerial exposure and leaching.
Upper unit (US3F1) is either absent or very thin across the crest and thickens to over 20 ft basinward; downdip, it is separated from US3F2 by a shale unit. US3F1 consists of an upward-shallowing deposits of Orbitolina mudstone, reworked stromatoporoid-rudist floatstone, small rudist floatstone, and fine skeletal grain-dominated packstone with rudist fragments.
3D model was generated covering large area of about 15x9km of the field. The new seismic horizon and faults interpretation were used in the 3D structural modeling. Cores descriptions and photos were used to define core facies, depositional environments and vuggy intervals. Rudist buildups direction of progradation was also defined based on BHI.
Reservoir rock Fabric number (RFN) was defined based on Lucia method and populated using veriogram per zone for the vertical wells using moving average method followed by Gaussian Random simulation, co-kriged with the moving average properties as a trend, for both vertical and horizontal wells. Porosity was populated with the same method. Water saturation and permeability were calculated using Lucia height function method.
Understanding of the reservoir heterogeneity, architecture and 3D modeling using RFN based on Lucia method allowed a better distribution of reservoir properties to be used in dynamic simulation for better history match, predict waterflood performance and adding new development areas.
Lv, Mingsheng (Al Yasat Petroleum Operations Company Ltd) | Al Suwaidi, Saeed K. (Al Yasat Petroleum Operations Company Ltd) | Ji, Yingzhang (Al Yasat Petroleum Operations Company Ltd) | Swain, Ashis Shashanka Sekhar (Al Yasat Petroleum Operations Company Ltd) | Al Shehhi, Maryam (Al Yasat Petroleum Operations Company Ltd) | Luo, Beiwei (Al Yasat Petroleum Operations Company Ltd) | Mao, Demin (Al Yasat Petroleum Operations Company Ltd) | Jia, Minqiang (Al Yasat Petroleum Operations Company Ltd) | Zi, Douhong (Al Yasat Petroleum Operations Company Ltd) | Zhu, Jin (Al Yasat Petroleum Operations Company Ltd) | Ji, Yu (Al Yasat Petroleum Operations Company Ltd)
Western Abu Dhabi locates in the west of Rub Al Khali Basin, which is an intra-shelf basin during the Late Cretaceous. The Shilaif source, Mishrif reservoir and Tuwayil seal forms one of the Upper Cretaceous important petroleum systems in the western Abu Dhabi Onshore. However, less commercial discoveries have been achieved within Mishrif Formation during the past 60 years since the large scale structures were not developed in western Abu Dhabi and the stratigraphic traps have not been attracted attention.
This study aims to investigate the exploration potential of both Mishrif structural and stratigraphic traps. It provided detailed study on Shilaif source rock, Mishrif shoal/reef reservoir and Tuwayil seal capability. Oil-source rock correlation, reservoir predication and basin modeling have been carried out for building Mishrif hydrocarbon accumulation model by integration of samplings, wire loggings and 2D&3D seismic data. Shilaif Formation is composed of laminated, organic-rich, bioclastic and argillaceous lime-mudstones and its generated hydrocarbon migrated trending to high structures. Three progradational reefs/shoals in Mishrif Formation were deposited along the platform margin, which are characterized by high porosity and permeability. Tuwayil Formation consists of 10-15ft shale interbedding with tight sandstone, acting as the cap rock of Mishrif reservoirs.
Mishrif hydrocarbon accumulation mechanism has been summarized as a model of structural background controls on hydrocarbon migration trend and shoal/reef controls on hydrocarbon accumulation. It is consequently concluded that Mishrif reefs/shoals overlapping with structural background are the favorable exploration prospects, and oil charging is controlled by heterogeneity inside a reef/shoal, the higher porosity and permeability, the higher oil saturation. Two wells have been proposed based on the hydrocarbon accumulation model, and discovered a stratigraphic reservoir with high testing production. This discovery encourages a new idea for stratigraphic traps exploration, as well as implicates the great exploration potential in western Abu Dhabi.
The capacity for the storage of carbon dioxide in saline aquifers remains enormous. Of all geological storage media, it provides the best storage capacity. In this study, the potential of the Shuaiba Formation, in the Falaha syncline, for geologic sequestration is assessed. A regional geo-model was built using seismic and well data (logs, cores) from the Falaha Syncline and nearby fields. The model was built to honor the heterogeneity and sequence stratigraphy of the Shuaiba carbonate platform using a five-order hierarchical conceptual model of the Shuaiba formation that merged sequence architecture and reservoir architecture together. This was achieved by honoring lithofacies, facies association packages and rock types in their corresponding depositional settings in the sequence framework. Dynamic simulations were then conducted on an upscaled geological model using a compositional reservoir simulator to determine its storage and flow capacity, plume migration pathways and to understand the physics of the fluid flow in the aquifer. Simulations are made to be conservative thus accounting for structural/stratigraphic, solubility (dissolution in resident brine) and residual trapping without accounting for the slower mineral trapping process. Detailed sensitivity studies were conducted during the simulations to understand the effect of well parameters, rock and fluid properties amongst others on the storage capacity in the aquifer. Simulation results indicate that significant volumes could be stored in the aquifer and could take a significant amount of time before the injected gas reaches the surrounding hydrocarbon producing fields. This study provides the first full field approach to characterize and to quantify the suitability of the identified aquifer for long term storage of carbon dioxide in the subsurface of UAE.