The occurrence of major hydrocarbon prone Mesozoic source rock sequences of the eastern Arabian plate is directly tied to the generation of intra-shelf basins within the giant carbonate platforms that formed during this time period. This paper investigates the driving forces behind the formation of intra-shelf basins and related source-rock/seal sequences. Results impact topics such as exploration, reservoir distribution, regional tectonics and climate modelling. A combination of large scale regional stratigraphic correlations, age dating, geochemical indicators and global climatic/tectonic events are investigated to explain differences and commonalities in basin formation and their impact on source rock seal pairs. In the Mesozoic major intra-shelf basins existed during three time periods: in the Late Jurassic during the Oxfordian to Tithonian, and in the Cretaceous during the Aptian and the Cenomanian. The late Jurassic basin is predominantly generated by plate margin tectonism possibly in conjunction with the rejuvenation of major WNW-ESE and N-S basement structures. Uplift at the eastern plate margin during the late Jurassic caused exposure at the eastern plate margin towards the Neo-Tethys, which in combination with sea level fluctuations resulted in the deposition of several large scale cycles. In central Abu Dhabi westward progradation of the Tuwaiq Mountain, Hanifa and Jubaila Sequences into an intrashelf basin are key evidence for the eastern uplift as are large scale collapse features reported from the eastern margin itself. The widespread deposition of the Arab and Hith anhydrites in the interior of the eastern Arabian plate are taken as further evidence for tectonically driven basin isolation leading to restricted evaporitic conditions. In contrast, the Cretaceous Aptian and Cenomanian intra-shelf basins formed mainly as a consequence of environmental/climatic disturbances associated with global oceanic anoxic events. During these times of global climate stress carbonate sedimentation was unable to keep up in areas with relatively high subsidence rates and laterally segregated providing the impulse for a switch from flat-topped platforms to a nascent basin topography (Hawar & Thamama A/Shuaiba during the latest Bar/Early Aptian; AP Apt 1), and Mauddud FM (latest Albian). Subsequent differential aggradation in combination with continued subsidence led to the full development of the basin topography in the early Aptian (AP Apt2–4; Bab Basin) and early Cenomanian (Shilaif Basin). Significantly, detailed carbon isotopic data indicate that climatic disturbances and the onset of oceanic anoxic events correspond to the generation of the initial topography and not to the onset of the deposition of organic rich basin fill sediments. Subsequent to deposition of organic rich sequences Cretaceous intra-shelf basins are dominated by argillaceous limestones and siliciclastics (Bab basin: Upper Bab Member - AP Apt5 and basal Nahr Umr AP-Apt6; Shilaif Basin: lower & upper Tuwayil FM). Thus, basin fill differs significantly between the late Jurassic tectonic basin featuring evaporate seals (Arab and Hith FM) and the Cretaceous climatic/constructional intrashelf basins being covered by clastic-rich sequences. Finally, it is postulated that the formation of another intra-shelf basin associated with the Valenginian Oceanic Anoxic Event (OAE1) was prevented by a regional tectonic uplift and platform exposure during the Late Valenginian.

Flowback of wells after hydraulic fracturing has always been under debate because the future performance of fractured hydraulic wells depends on the operational procedure applied during the flowback. Unconventional reservoirs have become increasingly important hydrocarbon resources to develop and produce for the oil and gas industry, and the best cost-efficient approach to develop and produce unconventional reservoirs is by drilling and completion of horizontal multi-stage hydraulic fractured wells. Hence the complexity of the phenomenology seen during the flowback of this type of wells has increased substantially. The complexity of the phenomenology is the result of the change on the range of fluid and fluid-rock properties. The permeability of unconventional reservoirs is typically in the range of nano to low micro darcies. This implies that the forces acting on the fluid flow through the medium are extremely magnified. This paper is aimed at describing the phenomenology during early fluid flow in unconventional wells, and its relevance during the design, planning, and execution of well flowback. The work considers actual data and information of flowback in unconventional wells from the available literature, as well as our own experiences. The authors use this available data and information to describe the physical phenomena that occurs in unconventional wells, especially in the early stages of production testing. The paper describes a theoretical approach that explains the fluid behaviour seen during multi-stage hydraulic fractured unconventional wells. Finally, the flowback is characterized based on the phenomenology, and its description provides an approach to an improved design of well flow management. The characterization of the phenomenology during flowback allows us to identify six stages of fluid flow in unconventional wells during the early flow process. Each stage has been identified considering the acting forces, fluid flow, and implications during the flowback. After such description, flowback design is explained based on the phenomenology characterization. Finally, the authors provide a comparison of the design and the actual behaviour for the early stages of flowback. This work introduces an approach based on the characterization of the phenomenology associated to multi-stage hydraulic fractured unconventional wells that have been successfully applied in flowback operations. A comparison between theoretical designs and actual cases confirms the value of the methodology.

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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.

Development of unconventional oil plays worldwide demonstrated that conventional characterization of such rocks in terms of a total porosity and total water saturation does not always provide enough information for completion and drilling decisions. The characterization and quantification of different fluids in different pore space together with a coupled geomechanical model is key for "sweet spots" detection for wells placement, stimulation and production. Based on our experience we present in this paper how an integration between geochemical analyses and advanced logging technologies can improve formation characterization in unconventional rocks; help to identify target intervals for wells stimulation and testing at an early exploration stage. The workflow was developed for the Shilaif formation evaluation in Abu Dhabi and allows fluids typing and their quantification in different pore systems from advanced logs data interpretation calibrated to full size and pressurized sidewall core special analyses. Detailed description of the workflow and results of its application showing reservoir and hydrocarbons quality variation within the Shilaif formation in wells from synclines and anticlines are presented in this paper.