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A pilot was drilled offshore Abu Dhabi aiming to determine the in-situ stress magnitudes. A time-dependent reactive shale formation separates Middle and Lower Cretaceous Limestone formations, leading to difficult open-hole logging conditions. Determining the stress regime and stress contrast across these formations is critical for assessing wellbore stability in extended-reach wells, setting casing shoe depths, and designing hydraulic fracturing in the tight reservoirs. Therefore, a comprehensive logging including multiple in-situ stress measurements and full-core was acquired. Seven microfrac stress measurements were obtained in one pipe-conveyed straddle-packer run conducted in a 15°-degree deviated 8½-in. open-hole wellbore. Each microfrac test was designed with multiple pressurization cycles to accurately obtain the closure stress away from the near-wellbore zone. Core and logging data from offset wells were used to calibrate the pre-job microfrac assessment. Real-time data monitoring was implemented for quality-control and tool operation decisions while logging. Three different pressure-decline analysis methods were used to identify the fracture closure: (i) SQRT square-root of time, (ii) G-function, and (iii) Log-Log plot on each microfrac station. The pilot well required an inhibited oil-based mud system to stabilize the 360-ft. water-sensitive shale formation. All microfrac stress measurements successfully reached the formation breakdown pressure, providing clear propagation and fracture closure identification. The three pressure decline methods produced results around ± 15 psi from each other with G-function predominately higher and Log-Log predominately lower than the SQRT. These microfrac tests measured minimum horizontal stress gradients between 0.67 to 0.77 psi/ft confirming the normal faulting stress regime in the studied reservoirs and a near strike-slip stress regime in the intervening shale formations. The formation breakdown, fracture reopening and closure pressure provide an accurate present-day tectonic model with ~0.1 and ~0.9 mStrain in the minimum (N80°W) and maximum (N10°E) horizontal stress directions in the absence of breakouts and induced fractures on image logs. The Lower Cretaceous tight reservoirs, identified as generally thin (<10-30ft) and low-quality (<10mD, locally <1mD) microporous carbonates, were located between low stress contrast (0.69 psi/ft) clay-rich limestones intervals in the overburden and high stress contrast (0.74 psi/ft) denser dolomites and clean tight limestones in the underburden. The risk of tool plugging and unsuccessful latching due to large particle solids in the mud was mitigated by multiple mud filters and repeated circulations while running-in hole with the straddle packer module. The microfrac tests in the Lower Cretaceous tight reservoirs provide the stress contrast measurements to properly evaluate hydraulic fracture containment on these tight reservoirs for future field development plans.

The objective of this paper is focused on presenting and highlighting the results of the first successful reservoir fluid characterization and sampling attempt in offshore Abu Dhabi and the added values to the assets operating in the highly heterogeneous Jurassic carbonate reservoirs with unknown formation water salinity values. The original formation water has a unique high salinity that got mixed overtime with the fresher injection water, so that the open hole log interpretation using Archie water saturation model becomes highly uncertain. Exaggerated oil saturations could be computed within the water zones around the oil-water contact. In addition to measuring the fluid mobility, the formation testers are being run to confirm the fluid type present in the reservoir by using pressure gradient plot or by fluid identification and sampling stations. The increasing cost and rig time optimization demands inspired the team to utilize the emerging formation sampling and testing while drilling at the first time in offshore Abu Dhabi to replace the conventional wireline/ drill pipe conveyed formation testers. This application proved to be an added value to gather the required reservoir data in a mature challenging field reducing the operational time, cost and associated risks. A water injection well is drilled across a highly heterogeneous, Jurassic carbonate reservoir offshore Abu Dhabi. A deviated pilot hole was drilled for formation evaluation and reservoir fluid assessment, and the plan was to continue with a horizontal drain into one of the sub-reservoirs (swept area) if confirmed water bearing. The logging while drilling formation sampling and pressure testing tool was run combined with the conventional open hole logs to minimize the formation exposure time, real time down-hole fluid analysis started very shortly after drilling to the bottom of the target reservoir, based on the rush open hole log interpretation. Different sensors, with different physics (namely; fluid viscosity, density, sound speed, optical refractive index, temperature, fluid mobility and compressibility) were used to characterize the fluid during the pump-out stations. Due to the minimized mud filtrate invasion effects, this operational sequence allowed the gathering of conclusive formation fluid samples with less pumping time and volume. This paper shows the operational planning, design and execution outlines, discusses the benefits of acquiring clean formation samples right after drilling compared to those acquired with the conventional conveyance techniques, and indicates the drawbacks and the limitations of this technology together with any window of improvement.

Objective/ Scope Supercharged pressures exist when drilling fluid losses (spurt, dynamic and static) invade the near well-bore region and creates a ‘supercharged’ pressure zone that is higher than the reservoir pressure but lower than the wellbore hydrostatic pressure. Due to the overbalanced hydrostatic pressure the fluid invades but cannot be disbursed because of the low mobility of the rock. This creates a near well-bore region with pore pressures between hydrostatic (wellbore) and reservoir pressure. This typically occurs in low mobility formations where the dispersion of the invaded drilling fluids is not efficient. Determining true reservoir pore pressure in these conditions is difficult for formation pressure testing tools (FPT's) which measure elevated pressures above true reservoir pressure in these conditions. Analyzing the change in measured pressures from repeated tests using FPT's may help estimate the true formation pressure. Method, Procedure, and Process One characteristic indication of supercharging is successive pressure build-up tests (after small drawdown volumes) that stabilize at lower pressures with each subsequent test as more supercharging fluid is removed from the near well-bore region. The successive decrease in build-up pressure as a function of volume can provide information on the dynamic pressure environment in the near wellbore zone and the reservoir pressures further from the wellbore. Plotting the pressure drop as a function of fluid volume removed from the formation and fitting an exponential decay curve to the data provides an estimate of the reservoir pressure. The curve is optimized using a regression algorithm to find a best match. Because one of the unknown variables is the desired formation pressure, a range of formation pressures are evaluated and a χ-squared error function is minimized, thus approximating the true reservoir pressure. Results, Observations, Conclusions Numerical simulation models with known formation pressures were set-up with a static supercharged near well-bore environment and various pressure tests were conducted. Analysis was performed on a number of tests to optimize the regression algorithm. The optimized regression provided an indication of the reservoir pressure within 2% of the simulated value. Real data examples were also analyzed with good results. Novel/ Additive Information This analysis technique provides a novel empirical method for estimating reservoir pressures in supercharged environments by investigating the change in build-up pressures in successive tests. The analysis can be accomplished with pressure measurement data from standard FPT's. Furthermore, the individual pressure tests do not need to stabilize because the change in pressure is used nor do the pressure tests need to measure the true reservoir pressure because it is determined by a regression analysis.

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.