This work presents a case study of developing the transition zone for a giant oil reservoir with significant gas cap and water aquifer, in Abu Dhabi-UAE, addressing geological and dynamic aspects, field development approach and present status. The reservoir lies within a relatively low relief heterogeneous carbonate structural trap and characterized by lateral and vertical variations in reservoir rock and fluid properties. Given the relatively low permeability of the mentioned reservoir, the transition zone contains a significant STOIIP; which called for this challenging development. A number of parameters were addressed and optimized as part of the transition zone development plan. The dynamic modeling suggests that a full field ultimate recovery of 70% can be achieved by developing the transition zone. However, considering the complexity of the reservoir, thickness of the transition zone and current market conditions, the field development would be economically viable for a period of 50 years under miscible hydrocarbon WAG, provided the most effective development strategy in terms of the definition of transition zone, optimization of the number, location, orientation and horizontal reach of the proposed wells. Various development strategies for the transition zone were investigated during the study considering all possible uncertainties and economic drivers, all of which are discussed in details in this paper. 12 years of early production scheme (EPS, 1993 to 2005) and 12 years of phase-I development helped better understand the reservoir and characterize the transition zone. Total of +150 wells penetrated the reservoir with good data gathering (ROS, Core, SCAL, PVT, MDTs…etc.). PVT studies indicate a wide range of compositional variation areal and vertical, which further complicates the development plan considering the surrounding sensitive environment. The transition zone is defined by rock types and the corresponding critical saturation. The amount of recoverable oil in the transition zone is depending on the distribution of oil saturation as a function of depth and the relationship between initial and residual oil saturation in the transition zone. The reservoir is under EOR (Miscible HC GI at crest and WAG at flank) since commissioning of phase-I in 2005 and tracers were injected in 2012; adding challenges to the history matching and tracking of the flood front. Given the limitation on surface handling capacity of the current facilities, the transition zone development called for well placement in the upper part of the transition zone using 6 months WAG cycles. The first well of the transition zone development has been drilled; which has positively validated the definition of the transition zone, built confidence on the subsurface modeling approach and commended the planning strategy.

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The objective of this work was to quantify the in-situ stress contrast between the reservoir and the surrounding dense carbonate layers above and below for accurate hydraulic fracturing propagation modelling and precise fracture containment prediction. The goal was to design an optimum reservoir stimulation treatment in a Lower Cretaceous tight oil reservoir without fracturing the lower dense zone and communicating the high-permeability reservoir below. This case study came from Abu Dhabi onshore where a vertical pilot hole was drilled to perform in-situ stress testing to design a horizontal multi-stage hydraulic fractured well in a 35-ft thick reservoir. The in-situ stress tests were obtained using a wireline straddle packer microfrac tool able to measure formation breakdown and fracture closure pressures in multiple zones across the dense and reservoir layers. Standard dual-packer micro-injection tests were conducted to measure stresses in reservoir layers while single-packer sleeve-frac tests were done to breakdown high-stress dense layers. The pressure versus time was monitored in real-time to make prompt geoscience decisions during the acquisition of the data. The formation breakdown and fracture closure pressures were utilized to calibrated minimum and maximum lateral tectonic strains for accurate in-situ stress profile. Then, the calibrated stress profile was used to simulate fracture propagation and containment for the subsequent reservoir stimulation design. A total 17 microfrac stress tests were completed in 13 testing points across the vertical pilot, 12 with dual-packer injection and 5 with single-packer sleeve fracturing inflation. The fracture closure results showed stronger stress contrast towards the lower dense zone (900 psi) in comparison with the upper dense zone (600 psi). These measurements enabled the oilfield operating company to place the lateral well in a lower section of the tight reservoir without the risk of fracturing out-of-zone. The novelty of this in-situ stress testing consisted of single packer inflations (sleeve frac) in an 8½-in hole in order to achieve higher differential pressures (7,000 psi) to breakdown the dense zones. The single packer breakdown permitted fracture propagation and reliable closure measurements with dual-packer injection at a lower differential reopening pressure (4,500 psi). Microfracturing the tight formation prior to fluid sampling produced clean oil samples with 80% reduction of pump out time in comparison to conventional straddle packer sampling operations. This was a breakthrough operational outcome in sampling this reservoir.

The work discusses the unique challenge of developing deep and thin oil reservoirs spread across onshore and offshore area of Abu Dhabi. The field is being developed with a cluster development approach utilizing available Natural/artificial Islands in offshore areas. The reservoirs under considerations are thin heterogeneous carbonate reservoirs with moderate permeability (avg ~<10-15 mD) and containing volatile to critical oil. The reservoirs were discovered quite early; limited data is gathered in old wells and have associated uncertainties. Some wells were deepened for sake of collecting additional data; very few completed lately under early production scheme (EPS) to evaluate the well potential, performance sustainability, reservoir drive etc. Their production behaviors also carry an overprint of reservoir diagenesis. The available data, their associated uncertainty and EPS performance are combined to build a holistic reservoir understanding and field development plan, under implementation with phased drilling. An early water-alternate-gas injection (WAG) is planned to support declining reservoir pressure in volatile oil reservoirs in absence of aquifer support. These reservoirs comprise of thin parasequences (<10 ft) separated by dense intervals associated with stylolites; reservoir thickness falling below seismic separation limit. The structural setting is complex due to undulating anticlines and extensive faulting. Diagenesis has heavily influenced reservoir properties, making significant reservoir saturation profile variation both laterally and vertically. This has been confirmed with production performance of EPS wells, behaving differently due to their areal location. The current development plan considers producers with 4000’ horizontal lateral in high oil saturation along with multiple sub-zone coverage to achieve an effective depletion strategy. The limited data availability, structural uncertainty and reservoir heterogeneity in combination with limitation of cluster drilling rig capacity has made well placement a challenging task. Placement of horizontal laterals in good reservoir properties, away from gas cap or O/W transition zones is achieved by utilizing unified understanding of structure, carbonate lithology, diagenesic imprints, logs, analogue saturation-height function, openhole tests and production data. The learning from each new well is incorporated to optimize further development plan. The reservoir quality of completion interval is critical in terms of saturation considering water production, well lifting and long term sustainability. The learning from successful implementation of WAG in another reservoir of the field is incorporated. Understanding from production behavior during EPS has provided a broad guideline for reservoir development; this paper discusses the challenges of implementation and their mitigation approach.

Reservoir X is a thin and tight carbonate reservoir with thin caprock that isolates it from an adjacent giant reservoir. An accurate geomechanical model with high precision is required for designing the optimum hydraulic fracture and preventing communication with adjacent reservoirs. The reservoir exhibits considerable variability in rock properties that will affect fracture height growth, complexity, and width and rock interaction with treatment fluids. The heterogeneity observed from the tight sections is further complicated by the variation of Biot's poroelastic coefficient, α, which is required for accurate assessment of the effective stresses. Laboratory testing was required to characterize the extensive vertical heterogeneity for key inputs in developing a geomechanics model. Approximately 120 ft of continuous core from an onshore field was provided for this study. The core material represented a potential tight carbonate reservoir interval and bounding sections. Heterogeneity mapping was performed from continuous core measurements from CT-imaging and scratch testing. CT-imaging provides an indication of the bulk density variation and compositional changes. Scratch testing provides a continuous measure of the unconfined compressive strength (UCS). Combining the two provides a means for accurate definition of rock thickness for dense, moderately dense, and lower density material coupled with corresponding compressive strength. Rock units were then subdivided based on these continuous properties for further geomechanics tests. Using log analysis combined with continuous UCS measurements from scratch testing, eight rock type classes were defined covering the target reservoir interval and bounding sections. This information was used for optimizing the sample selection process to characterize each identified rock unit. Routine core analysis measurements reveal significant vertical heterogeneity with porosity ranging from 0.1% to 18.1%. Similar variability was determined from elastic properties for each of the eight rock types. Quasi-static values for Young's modulus and Poisson's ratio determined at in-situ stress conditions ranged from 2.6 to 9.6 × 106 psi, and from 0.16 to 0.34, respectively. The Biot's poroelastic coefficient has a first-order impact on the calculated effective stress profile, which directly affects fracture stimulation model results. Testing from this study combined with previous measurements (Noufal et al. 2020, SPE-202866-MS) provides a unique correlation with porosity and bulk compressibility. In addition, rock-fluid compatibility was evaluated with proppant embedment/fracture conductivity tests. Results are dependent on a given rock type, exhibiting a wide range of fracture conductivity as a function of closure stress from 10 to 1000 md-ft. Embedment for all cases was low to moderate.