When drilling in mature reservoirs, conventional formation evaluation is not enough. Characterizing these formations properly becomes essential in ensuring longer and sustainable oil producing boreholes. Understanding the geological complexities, permeability drivers and pressure potential is important since they control fluid flow. This work presents the first ever case study from the Abu Dhabi Carbonates where an innovative multi-measurement borehole imager was deployed, providing a comprehensive and integrated formation evaluation not used before in the industry. A campaign of five extended reach wells was planned in one field offshore of Abu Dhabi. A 15-ft long borehole imager was added to the drilling bottom-hole assembly (BHA) to acquire apparent resistivity and ultrasonic images simultaneously to characterize the often not-observed geological features that control reservoir properties. These complementing images helped in characterizing vug distributions, bioturbation, faults and dissolution seams in addition to the bed boundaries. Around 13,000ft of lateral was logged while drilling, using this data in real time in oil-based mud to target the most permeable and thinnest layers for the first time in the middle east. Core analysis had defined the 2ft thick most permeable layer of the reservoir where the lateral needed to be exposed for better production. Multi bed boundary detection for waterfront identification was integrated with mobility pretests points along with surface mud gas fluid sampling for Gas Oil Ratio (GOR) determination and the innovative dual imager. For the first time, acquiring a high resolution apparent resistivity image in real time in OBM, made the restriction of placing the lateral in a thin layer possible. Findings redefined the understanding of the geology and the drivers behind the fluid flow within this reservoir. With the new high definition ultrasonic image, vugs that tend to control the permeability in many facies were discovered. This led to the computation of a vug density curve derived from the images which characterized the key-intervals. Qualitative trends were validated with mobility estimated from independent LWD measurement, providing much-needed confidence in the new imaging technology. Completion was re-designed based on the new brought-in information. Sections were isolated based on the high-water saturation zones mapped with the multi bed boundary detection technology and higher gas oil ratio from surface fluid sampling. Completion was then optimized around high vug density/ mobility intervals. This first-ever case study provides a plethora of new information for model update whether it be the geology or the reservoir model that was hitherto unavailable for some reservoirs where development wells were drilled with OBM. For challenging wells planned in highly constrained environments from structure, petrophysics and reservoir maturity aspects, this new technology cleverly combined with others, opened the door to boost production from otherwise, a highly matured reservoir.
This paper reviewed the interpretation of repeat fall-off tests acquired in two vertical pattern injectors operating in a carbonate reservoir undergoing full field development. Water Alternating Gas first pattern (WAG-1) started in August 2002 with a period of continuous gas injection until 2006 when the first water cycle was initiated. In the second pattern (WAG-2) water injection was initiated in June 1998 until September 2007 when the first gas cycle started.A few pressure fall-off tests were acquired during the monophasic injection phase mostly to verify well injectivity. After Water Alternating Gas (WAG) cycles started, pressure fall-off tests were usually acquired at the end of each three-month injection cycle with 1:1 WAG ratio. Analytical fall-off test interpretation relied on the use of the two-zone radial composite model. The apparent permeability thickness product was corrected with the Perrine formulation of multiphase mobility. Triphasic oil permeability was calculated using the modified Stone I model. Multiple fall-off test interpretations indicated that the two pattern vertical injectors behaved differently even though both being fractured. The difference in behavior was linked to different perforated intervals and reservoir properties. Gas and water injection rates were showing differences between both pattern injectors as a consequence. No major operational issue was reported during the three-year operation of both WAG patterns. During the WAG cycles, gas banks were found to be of a small inner radius and almost undetectable at the end of the subsequent water cycle. Changes in the pressure derivative slope at the end of the subsequent water injection cycle indicated most likely the creation of an effective mixing zone of injected gas and water in the reservoir.Numerical finite-volume simulation was required to account for potential injected fluid segregation and, the multi-layered and heterogeneous nature of the reservoir. Repeat saturation logs acquired in observation wells provided critical information on the saturation distribution away from the injection wells. Enhanced vertical sweep conformance through phase mobility control in the presence of strong reservoir heterogeneity was the major expected benefit from an immiscible WAG displacement mechanism. All available observations were reviewed and integrated using a history-matched reservoir simulation sector model with boundary conditions obtained from a full-field model.
This paper present the successful deployment of the ultra-deep EM tool in a mature carbonate reservoirs to reduce the uncertainty associated with fluid movement for horizontal/ MRC well-placement optimization and enable precise geosteering to maintain distance from fluid boundaries and mapping of nearby reservoirs for future reservoir development. In addition, the EM tool can facilitate to optimise lower completion design liner (blank pipe length, PPL, ICD and swellable packer depth). The high heterogeneity of reservoir qualities increase uncertainty in fluid distribution and make drilling long horizontal, oil producer wells in offshore mature giant carbonate fields very challenging. The usual plan is to drill a pilot hole crossing the reservoir sections, evaluate log saturation, and then re-optimize horizontal sections accordingly. To study the possibility of eliminating pilot holes, an ultra-deep electromagnetic (EM) tool was deployed. The first objective was to detect reservoir boundaries and predict resistivity of the target before penetrating it (Geostopping). The second objective was to optimize the horizontal drain (Geosteering), and map resistivity of adjacent reservoirs for well completion and future well optimisation (Geomapping). Pre-well inversion modeling was conducted to optimize the spacing and firing frequency selection in order to facilitate early real-time geosteering and geostopping decisions. The plan was to run the ultra-deep resistivity tool in conjunction with shallow propagation resistivity and density-neutron porosity while drilling the 8½ in landing section. The objective was to be able to detect the lithology boundary early and predict the resistivity of the reservoir before penetrating, facilitating geostopping decisions. This would allow optimization of the horizontal section to geosteer the well in an oil-saturated layer 4-6 feet from top boundary while geomapping the surrounding reservoirs’ resistivity. The EM tool delivered accurate mapping of thin reservoir layers while drilling the 8½ in section, as well as enhanced mapping of low resistivity zones up to 85 feet true vertical thickness in a challenging low-resistivity environment. Comparison to recorded open-hole logs for validation showed good results, enabling identification of the optimal geostopping point in the 8½ in. section. The EM tool is able to save up to five rig days in the future by eliminating pilot holes. The 6 inch horizontal section was successfully geosteered and placed 4-6 feet from top boundary. The EM tool was able to map reservoir resistivity 30 feet TVD below the wellbore and the completion design was designed accordingly. Additionally, the EM inversion for the nearby reservoirs helped to modify the plans for nearby future wells.
This paper reviewed the management of injection water quality in a super-giant carbonate oil field operated by ADCO onshore Abu Dhabi since 1973. This field was subjected to peripheral water flooding in order to maintain reservoir pressure and provide a mechanism to sweep the oil. Injected water was sourced from 23 water supply wells completed into deep hyper-saline aquifers with total suspended solids (TSS) of 1.5 mg per liter (mg/l). Each water supply was connected to a cluster of 4–5 water injectors. Clusters were interconnected. Produced water having average TSS of 100 mg/l and oil in water (OIW) content of 260 parts per million (ppm) was being reinjected into the most permeable reservoir through five well peripheral pilots injector. No significant operational problem was reported apart from occasional injectivity degradation which was restored with a maximum of one acid stimulation per well since 2002. New facilities under construction were designed for a maximum OIW of 100 ppm with plans being made to reduce it to 50 ppm as the volume of produced water was expected to rise with the field wide implementation of gas lift. After more than 30 years of production from two major high-quality reservoirs, ADCO recently started the development of a third oil-bearing Reservoir X classified as low permeability. Accepted assumptions based on the extensive water injection experience proved questionable considering the low median pore size diameter of the reservoir under development. The common water supply for the peripheral water injectors assigned to the three different oil-bearing reservoir zones posed an additional challenge as the water injectors drilled in the low permeability reservoir needed to be shielded from temporary degradation of water quality typically experienced during start-up operations after maintenance or water supply well workover. The issue of temporary high solid loading gained importance as the practice of discharging water loaded with solids to a pit was discontinued after 1998 for environmental reasons. Several studies related to water quality were recently performed including the onsite cycling of aquifer water through reservoir core plugs of Reservoir X in order to predict the potential degradation in matrix injectivity over time and evaluate the resulting operational cost and timing of future acid stimulations. Material selection for the surface pipeline network carrying the aquifer water was also reviewed with non-metallic internals being recommended. In the event of a temporary degradation of water quality following system start-up or a workover in a water supply well, disposal of such water into the source aquifer was determined to be the best solution to avoid injecting water loaded with solids in the low permeability reservoir, also fulfilling all regulatory requirements.
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