Objectives Conventional oil from the prolific carbonate reservoirs of Abu Dhabi has been produced over half a century from different anticlinal structures. Now, the time is right to go back to where it all started- the source rock in the depths of the syncline. The first well in the syncline provided an opportunity to characterize the reservoir quality of Cretaceous Shilaif Formation and understand the potential of the unconventional source rock oil play in Abu Dhabi. Methods The carbonate source rocks of Abu Dhabi are very different from the unconventional source rocks in the rest of the world and require a unique approach. An integrated workflow combining log, core and surface measurements has been carried out to characterize the Shilaif formation in the syncline in the south-western part of Abu Dhabi. Every measurement has a distinctive value and helps reduce uncertainties about Reservoir Quality. A critical examination of different available technologies was carried out to examine and optimize the characterization program to understand and reduce all uncertainties about reservoir quality. Results The Shilaif source rock in this syncline to the south west of Abu Dhabi is a carbonate-rich organic mudstone, which distinguishes itself by lack of clay and vertical heterogeneity. It is a hybrid source rock with simultaneous presence of both organic and inorganic pores. The extensive core analysis program provided insights about porosity, permeability and saturation, which were used to validate the log interpretation. Higher thermal maturity and stronger compaction lead to different reservoir qualities than the ones previously recognized on the nearby shallower anticlinal structures. The reservoir quality of Shilaif in the syncline (levels of oil saturation, producible pore-sizes and permeability) exceed the pay criteria known to be required to produce economic volumes of oil in other basins around the world. Geomechanical characterization shows that the rock is extremely compact and requires careful planning with respect to proper completions and appropriate fracturing strategy for this play to be successful Novel Information This is the first well in the syncline, targeting the mature source rock of Shilaif, based on previously existing literature. This paper explains the interpretation methodology workflow, that integrates all the measurements and discuss for the first time about viability of Shilaif as an economic source rock oil play in UAE, focusing on the syncline.

Diyab has served as the source rock for various major Jurassic and Cretaceous oil & gas plays in Middle East, and a number of recent studies have indicated that the Diyab formation has potential to be explored as an unconventional source rock gas play. This assessment is mainly based on 1) the known facies distribution, 2) lithology and rock properties, 3) source rock TOC and maturity 4) mud gas, and 5) Stimulation results. The objective of this paper is to identify the resource potential of Diyab source rock as an unconventional gas play in UAE. Integration of valuable measurements is of upmost importance to reduce the uncertainty in reservoir quality assessment of any exploration setting. Quantifying TOC and maturity are one of the most important aspects in evaluating the source rock potential of an unconventional play. Due to the complexities seen in several source rock plays, assessing quality through interpreting mineralogy, porosity and water saturation can also be quite challenging. To achieve that, a comprehensive mud logging analysis program was carried out in the well complemented with a comprehensive and modern logging program combined with a detailed unconventional core analysis to identify rock properties, fluid type and saturations with the scope to assess unconventional resource potential of the Diyab formation in UAE. Initial petrophysical evaluation shows that Diyab source rocks have a good Shale Gas resource potential within three different zones of interest in the Diyab formation. These zones of interest are based on, 1) Total Organic Carbon, 2) Porosity and 3) Saturation. During the petrophysical evaluation advanced mud logging analysis was used as initial calibration for TOC and mineralogy, a multi-frequency dielectric tool was used for initial saturation estimation and nuclear magnetic resonance analysis was used for porosity estimation and characterization. In the final computation, unconventional core analysis was used to refine and further calibrate the results. The level of gas saturation exceeds common pay criteria which are known to produce economic volumes of gas in other basins around the world. Diyab as a source rock and as unconventional gas play in UAE in terms of reservoir quality has never been studied in detail. This is the first time that this kind of a comprehensive evaluation program was carried out using advanced log acquisition, advanced mud logging and specific unconventional core analysis and through this paper important aspects of reservoir quality for Diyab formation will be discussed and will be of great help for future exploration plans in the Diyab unconventional gas play.

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 (Azzam and Taher, 1995, van Buchem et al., 2010 and Lyndon et al., 2010) that were deposited during the Aptian time. The lower sequence started at the early Aptian time and mainly included Hawar Member, Thamama Zone-A, the Shuaiba shelf facies and its time equivalent Shuaiba basinal facies sediments. The second sequence was deposited after the drop in sea level below the Shuaiba shelf break. This drop caused subaerial exposure of the Shuaiba shelf platform and allowed for the clastics material to influx the fine-grained over the Shuaiba basinal facies area. The clastic influx and the carbonate rich claystone of the Late Aptian sequence sediments may represent the effective top seal for the Shuaiba basinal facies and Zone-A oil accumulation. 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.

In preparation for the hydraulic fracturing campaign, the Unconventional Resources Team at Abu Dhabi National Oil Company (ADNOC) has carried out stress measurements both in open-hole and cased-hole in a number of recently drilled wells. The current paper demonstrates the results of the stress measurements in open-hole in two wells drilled in two different geological settings. The main target chosen was the unconventional Shilaif formation. One well was located on top of an anticline and the other well penetrated the Shilaif formation in a syncline. High breakdown pressures were expected (especially in the syncline). In order to cope with the challenges expected during the stress testing in such environment, a wireline formation tester that included both single packer and dual packer was used to initiate breakdown and achieve measurement of fracture closure pressure. With the expected adverse rock properties, either natural fall-off or rebound technique was employed to obtain closure pressure. The single-packer module extended the differential pressure rating up to 12,000 psia in comparison to 4,500-psia rated dual packer. The single packer was used to initiate the fracture breakdown if dual packer was not considered sufficient. Formation pressures were measured at several depths with the dual-packer operations. The stress measurements were carried out not only in the Shilaif formation, but in the shale formations above (the Tuwayil formation) and below (the Mauddud formation) in order to check if the shales could be stress barriers for a large scale hydraulic fracture. The current paper explains the procedure followed during the stress measurements and shows an example of interpretation of the pressure data acquired with wireline formation tester comprising the single-packer and dual-packer systems. The stress measurements were used to calibrate results of the geomechanical modeling.

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.