Recently observed production behavior in a maturing carbonate oil reservoir indicated that many production strings were getting plugged with solid scales, requiring tubing clean-out jobs. This is the main reservoir of a supergiant onshore carbonate oil field operated by ADCO since 1973. Some cases proved to be no more than calcium carbonate scaling following water breakthrough and the tubing blockage was successfully treated with acid washing. A number of plugged strings revealed that a non-mineral hard scale was the cause of the blockage. Upon analysis, such scales proved to have an organic composition rich in asphaltenes. While solvent washing was successful in removing the blockage, rapid reoccurrence was observed in many cases. The subsurface asset team embarked on a detailed reservoir monitoring and fluid compatibility study to establish causative factors. One of the aims of the study was to check a possible link between the asphaltenes deposition with a naturally occurring tarmat and a rich-gas injection pilot, both located in the severely affected part of the reservoir. This work revealed that although the severity of the problem is higher in the tarmat area, asphaltenes mobilization from the tarmat layer was not considered a realistic mechanism. Although PVT studies revealed that rich gas dissolution in the crude at reservoir conditions triggered asphaltenes instability and precipitation but occurrence of asphaltenes deposition in the field seemed unrelated to the rich-gas injection as the injected gas was moving in a different reservoir subzone. Most of the plugged strings were unlikely to have had gas breakthrough at the time of problem detection and no clear spatial relationship could be evidenced. A preferred explanation may be that asphaltenes precipitation is related to differences in crude oil composition within the studied reservoir. The reservoir might have seen successive oil influxes from two source rocks with wide distribution of mixing ratios. Asphaltenes originating from one of the source rocks might cause greater fluid instability even at the observed low concentrations. Production rate sensitivities indicated that asphaltenes blockage was retarded at higher production rates. Many asphaltenes dispersant/inhibitor chemicals were evaluated for effective tubing clean-out and preventing asphaltenes deposition. Some chemicals proved to be more effective in mitigation and prevention of asphaltenes deposition.

The selection of a chemical solution to asphaltene challenges is an integral part of the flow assurance strategy, and has direct impact on both CAPEX and OPEX. The chemical selection process includes a detailed analysis of deposits, measurements of crude oil properties and various stock tank liquid tests, which are essential input into the development of the most appropriate inhibition and/or remediation strategy. The success of the chemical treatment strategy is a collaborative effort between operations and technology experts.In an onshore field in Abu Dhabi, routine clean-up jobs to date consist of diesel solvent as a carrier mixed with a dispersant chemical in approximately 80:20 proportions. However, the field observations indicate that such an approach provides often limited effect and sometimes can be detrimental for the well due to fluid incompatibilities. Laboratory tests on deposits collected from this field, combined with Shell's extensive experience in the area of asphaltenes prevention/remediation led firstly to identification of an alternative aromatic-rich solvent. In addition, better performing dispersant chemicals than previously used were identified that could increase the overall efficiency of the cleaning jobs (soaks, washes).In order to reduce the frequency of clean-up operations for wells with severe asphaltene problems, continuous application of chemicals (inhibitors) has been considered. Asphaltene inhibitors may not completely prevent asphaltene precipitation but may significantly "delay" the process of deposition. Lab inhibitor testing was performed on crude oil samples collected from the Abu Dhabi field and the performance of the chemicals with respect to their concentration was evaluated. The best inhibitor from the lab testing will be applied in a field trial where the dosage is optimized following a proper surveillance plan to monitor the chemical effectiveness.

A giant oil field consisting of carbonate reservoirs in onshore Abu Dhabi has been provided with long term Field Development Plan, including several Dual Oil Producer (DOP) completions in formations Shuaiba and Kharaib, more specifically in zones A & B to maximize oil recovery. Upper Zone and Lower Zone B have been producing on natural flow using dual completions. This has been possible due to high reservoir pressures available since the beginning of the production. Conditions have changed, especially for the Lower Zone B, and reservoir pressure has been declining for the past years. As a result, several wells ceased to flow mainly due to lower pressure and/or higher water cut conditions. Therefore, Gas Lift has been selected as the preferred artificial lift method in lower zone B. The problem has been identified in current dual wells where Upper Zone is still producing but changing dual into Gas Lift single oil producer in lower zone B will translate into halt in oil production in upper zone, therefore reducing the oil recovery for Upper Zone. This is a consequence of the current practice of plugging and abandoning the Upper Zone. An innovative application for dual oil producer completion with Gas Lift mandrels in long string has been evaluated to keep both zones producing and extend the ultimate oil recovery of the current wells. Candidate selection, including analysis and workflow, will be presented in detail. Moreover, the design process, well modelling and installation will be addressed further in this paper.

This case study well is in a mature onshore field, which has been under production for a long time (started in 1970) resulting in depletion of some of the reservoir units presenting challenges for optimizing drilling performance and managing risks associated with stuck-pipe incidents. Additional challenges are minimized surface footprint, 100% reservoir contact in thin targets and acquisition of accurate petrophysical data for formation evaluation. A detailed pre-well study was conducted utilizing historical field and nearby wells’ data in the planning phase with close collaboration in a multi-disciplinary team including well and Bottom Hole Assembly (BHA) design and pre-well modeling for geosteering and LWD tool string configuration taking into account the elimination of radioactive chemical sources. The pre-well study has concluded that the azimuthal deep propagation resistivity image is going to provide proactive geosteering solution to identify the approach to both top and bottom boundaries. The BHA has also included rotary steerable system (RSS) along with optimized Logging While Drilling technologies (LWD) which has included, high-resolution micro resistivity imaging, Laterolog resistivity, nuclear magnetic resonance (NMR), sonic caliper and near-bit gamma ray. Continuous real-time monitoring provided drilling performance monitoring and analysis as well as facilitating geosteering services. The 8,356 feet horizontal section was effectively geosteered with 100% reservoir contact tapping into two thin reservoir sub-layers. Real-time azimuthal deep propagation resistivity image/curves were used to geosteer the well trajectory precisely within target zones and provided 4-5 feet TVD detection to bed boundaries. Also, high-resolution microresistivity images, dip picks and near-bit azimuthal gamma ray helped in maintaining the well-bore attitude parallel to the stratigraphy within each sub-layer. This data facilitated a smooth transition from one sub-layer to the next with minimum borehole tortuosity aided by the push the-bit RSS and at-bit-inclination measurements. In addition, NMR provided real-time porosity and permeability measurements assisting in well placement and enhancing reservoir understanding as well as optimizing future well planning workflows. This paper presents a step change from the traditional field development drilling techniques in terms of horizontal length. Similar well designs are currently being implemented in an effort to benchmark drilling, well placement and petrophysical data gathering requirements for future development drilling in order to maximize asset value.

Early in 1998, three horizontal oil producers were drilled with short radius horizontal section of 1000 ft to 1600 ft. Those wells were shut in 2007 due to the evolution of watercut as a result of inverse water coning experienced in Zone-Y. Gas lift was selected as the preferable artificial lift technique for subject reservoir, accordingly, the three horizontal producers were planned to be worked-over during 2011 in order to install gas lift mandrel. The expected production rate with GL was estimated to be around 400 bopd with a high watercut of +70% after the gas lift application.An extensive review of actual wells' performance in addition to the application of simulation model were performed in order to study the optimum scenario to reactivate and put the wells back on stream naturally taking the advantage of the workover job. Evaluation of multiple scenarios recommended to extend the horizontal section of subject wells to unswept area and also to consider water shut-off technique in the original hole to enable producing them naturally prior to Gas lift startup.An innovative one step approach, with direct rig intervention, utilized LWD (Logging While Drilling) resistivity data to identify intervals swept by advancing waterfront instead of the conventional approach carried out in two steps; the first being the rigless coiled tubing intervention to identify water entry intervals (PLT-Production Logging Tool) and the consequent utilization of rig intervention to carry out the actual water shut-off plus horizontal section extension operation.Using LWD data further improved the shut-off operation efficiency by deepening the depth of investigation while extending the horizontal section in the pay-zone, which was not possible with the rigless PLT operation. Another setback with rigless PLT operation is the requirement of minimum threshold flow condition which was not possible to achieve in the inactive producers.During the Workover, the Openhole log (LWD) recorded while drilling for all the three wells showed that the area around the original hole is depleted to Sw of ~70% and the extended hole is totally located in oil bearing Zone-YL, thus confirming the model findings and the analytical analysis. Accordingly, it was decided to isolate the original hole with 4 ½" pipe and swell packers and complete each well as single producer. The production test results for the three wells, post the workover, showed that each well is currently producing dry oil of around 1500 bopd with nil watercut.Results of accomplishment team recommendation revealed the following:  The three wells were able to flow naturally and became active with nil watercut.  A cost saving of around 15.0 MM$ was achieved as a result of the cancellation of drilling three infill horizontal wells that were originally planned in the same locations to sweep the unswept areas including new surface flowlines, equipments and cathodic protection.  Additional capacity of 4500 bopd has been added to Zone-YL sustainable production capacity.