Tar mats are encountered in many Middle East carbonate reservoirs including the Kingdom of Saudi Arabia. Tar is considered to be very heavy crude that does not flow or has very limited flow capacity at standard reservoir conditions. In some cases it is found above the aquifer and below a light oil layer. As tar is practically immobile at reservoir conditions it acts as a flow barrier between water and light oil, causing significant challenges for reservoir development. In such cases water injectors work most efficiently when placed horizontally just above the tar mat to maintain pressure support during production. One challenge when drilling for these water injectors is to optimize their position above the tar layer yet as close as possible to the tar to maximize sweep efficiency. A further complication for their placement is the uncertain lateral distribution of the tar in terms of true vertical depth (TVD). The top of the tar layer is often an undulating lateral surface with varying depths. Positioning the well a "safe" distance from the tar is not a good solution as it might leave behind a significant volume of producible oil, ultimately lowering oil recovery. A real-time tar detection method is needed while drilling to quickly respond and modify the wells trajectory if tar is encountered. The low mobility caused by tar can be detected with a formation pressure while drilling (FPWD) tester. A nuclear magnetic resonance (NMR) tool provides oil viscosity estimation and additional tar-related properties. In combination with a conventional logging string, tar can be positively detected while drilling. This case study from a carbonate field in KSA shows the successful placement of a 6.25-in. horizontal well using a logging-while-drilling (LWD) NMR-device and an LWD formation pressure tester to detect tar in combination with conventional resistivity, density and neutron (triple-combo) LWD logs.

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.

Generally, appraisal wells are drilled to reduce uncertainty. However, occasionally reserves uncertainties may increase in a heterogeneous carbonate reservoirs specially challenging stratigraphic limit of reservoir facies. Under such circumstance, sometime operators rethink of further investment in the field development when in-place volumes are marginal. The objective of the study is to present how we achieved well design modification and test strategy in a dynamic environment. Optimal well test design, execution and analysis can help mitigate major uncertainties, which were not considered during initial planning phase The subject appraisal well was drilled as a vertical hole in an up dip direction to the first appraisal well. However, Open Hole (OH) and mud log data indicated the reservoir to be tight and in some portion dominated by water flow during sampling even though clear hydrocarbon presence observed in core chips and cuttings analysis. After detailed studies of the available data, a decision was taken to horizontalize the well towards first appraisal well. While drilling, geological barriers were encountered as indicated by the presence of different fluids in the horizontal section. Variable fluid presence (water and oil) posed a challenge with respect to well completion and testing. This paper describes the process of completing the well in an evolving complicating situation and how successful well test design and execution helped to mitigate the uncertainties. OH Logs, Wire Line Formation Tester (WFT) and test data from the studied and existing wells in the area were used to design the well test and interference with first appraisal well in an evolving situation, which is not typically faced in well operations. Hence, the results obtained provide an additional information that helped to conclude variable fluid distribution and its dynamic connectivity to the first appraisal well. Well was completed followed by test as designed and Production Logging Testing (PLT) was conducted to define reservoir contribution. Post well test analysis and comparison with existing WFT and test data from existing well helped to conclude results and address the uncertainties. This paper summarizes the design process, challenges faced in an unexpected variable fluid distribution in the horizontal section and accordingly how well test analysis was performed to conclude the results that helped to take optimal investment decision for the development of this marginal reservoir.

Exploration is a high risk business. Hence, available data including those from offset fields have to be analyzed and reviewed critically prior to drilling a well. This becomes especially true in a marginal thin reservoir where innovative drilling and testing strategy would play a key role in deciding commercial discovery of the prospect. Flow rate is one of the basic criteria, inter alia, on which commercial viability of a prospect depends. Conventional testing strategy performed in the vertical well did not yield commercially viable flow rate. Hence, innovative approach was adopted to achieve the desired results. After drilling, multi-disciplinary data should be integrated to finalize the testing strategy, which is critical to announce the discovery to meet the criteria set by the company. Reservoir of interest is a thin clastic reservoir, which could not meet the criteria of flow rate during testing with conventional way even though volume in place assumed to be significant due to large area. After carefully reviewing all data, the flow rates were predicted with the modeling if well will be horizonalized. In order to fully evaluate the prospect, the static and dynamic model of the first vertical well was thoroughly reviewed and re-evaluated. The vertical well was tested comingled with two reservoirs having a two feet dense layer between the two. The well flowed mostly water with traces of oil. A detailed review of the test data revealed that a higher prospectivity layer exists in the overlying thin clastic reservoir above the dense and that the two reservoirs are in isolation. Based on this finding, a modeling was performed to decipher optimal horizontal well length to achieve the flow rate. It was a challenge to geo-steer the well trajectory of horizontal section in this very thin reservoir, which was successfully achieved by an active coordination of an integrated teamwork. An innovative approach was adopted by applying Wireline Formation Tester (WFT) data to confirm dynamic isolation from underlying reservoir, which is predicted to be major water contributor. Optimal horizontal well length was established by analytical model for achieving the best flow rate. The well was drilled successfully with horizontal length of 1400 ft. in thin clastic reservoir and completed with fit-for-purpose completion followed by production testing that achieved the flow rate criteria as predicted in the model. This paper summarizes the processes of: (1) data integration, (2) establishing reservoir segmentation based on static and dynamic data, (3) modeling to predict flow rate and optimal horizontal length, (4) selection of fit-for-purpose completion and (5) addressing challenges and lessons learnt during planning and execution phases.