Carbonate coiled tubing (CT) reservoir stimulation approaches vary, using acid systems and different diverters in order to try to achieve the best results. However, because it was not previously possible to know where the injected fluids actually go in the formation during a stimulation job, even with the enhancement of the coiled tubing placement and software model prediction, the results were often not effective as they could be. The inclusion of a fiber optic distributed temperature monitoring system (DTS) in the coiled tubing enables visualization of different zones injectivity by monitoring the exothermal effect of the acid reaction with the carbonate in highest permeability zones and hence acid and diverter placement can be optimized for improved stimulation efficiency. In one of Abu Dhabi Onshore fields a production log (PLT) was run in a water injector well that was completed in two different reservoirs, to provide a baseline injection profile. The acid stimulation job was then performed using fiber optic temperature monitoring through the coiled tubing, to optimize fluid placement. One feature of the data acquired by the fiber optic distributed temperature system was that the initial baseline temperature log was able to identify the high permeability injection interval from its "warm-back" response and this was correlated with the PLT interpretation. Consequently the treatment volume was optimized using the DTS results. Another DTS run was recorded after the acid stimulation with diverter using the injection velocity approach. This consists of bull-heading water down the coil tubing annulus and tracking the hot water generated at the heel of the well from the previous shut-in as it moves across the reservoir. The velocity interpretation of the injection profile confirmed that there was minimal injection into the high permeability interval at that point of time. The stimulation resulted in a well injectivity increase of 20% indicating successful placement and diversion of acid compared to conventional stimulation practices. The use of DTS will enable stimulating wells without the need for pre-job production log (PLT) and especially wells where a PLT is not possible either due to low flow-rates (below critical flow) or operational constrains (completion restriction). This paper details this "first-time" experience of a coiled tubing stimulation combined with DTS measurement and injection velocity profile in the UAE. It also concludes with a list of lessons learnt and recommendations for similar future approaches.
Matrix stimulation treatments are applied to improve well productivity and enhance the hydrocarbon recovery from the formation. However, in some wells optimum results cannot be achieved using conventional stimulation techniques since it is difficult to ensure efficient placement of the stimulation fluid across the entire stimulation interval. This is a prerequisite for a successful result. The situation becomes even more challenging in heterogeneous reservoirs with large permeability variations or possible presence of natural fractures in a complex geological environment. Other complications may occur when conventional stimulation treatments keeps creating undesired wormholes throughout the same spot within existing (horizontal) bore hole. These complications may result in making future diversion jobs even more challenging and sometimes enlarges the hole to the limit of affecting accessibility in future interventions. The paper describes a unique approach that has been successfully executed in one of the super giant onshore fields in Abu Dhabi through an extensive study over different types of heterogeneous reservoirs. The objective was to develop an economically justified stimulation strategy utilizing different treatment fluids and a unique placement approach which led to proper reservoir drainage. In this field the production comes from various carbonate reservoirs, where the different layers are subject to different methodologies to support the reservoir pressure. The approach consists of chemical diversion, dual injection for acid placement, and optimized jetting tool. The paper also describes the results of re-stimulation of a group of wells as part of field pilot. Actual data from several treated horizontal wells are presented. The methodology of candidate selection, treatment design and execution is described along with pre and post stimulation production logging. The paper highlights the impact of production improvements of the treated wells. Chemical diversion, as proved in the pilot wells, enhanced the acid stimulation. It was shown that previously untreated subunits, were now contributing to flow. The pilot wells have validated the engineered methodology adopted for the work-scope.
A super Giant field production sustainability is essential and has to be sustained for longer period of time, therefore different techniques have been introduced and tested to overcome the various reservoir issues. Gas Lift technique (GL) has been considered as one of the effective mitigation actions to reactive the dead wells, enhance recovery factor (RF) and accelerate the production from both technical and economical points of view. Prior the full field implementation, it was decided to select a GL Pilot for testing and data gathering, the planned GL Pilot consists of 10 wells which have been selected from various reservoir units and completions to analyze the differences in the performance. The selected Pilot wells were inactive prior to GL implementation (with no oil production) as per set strategy which calls for using of the GL system to reactive the dead wells only.The Pilot started production in November 2008 with almost a total oil production rate of 14 Mstb/d using GL system and the current average rates of the pilot (as of Jan. 2010) are as follow: average oil rate ~ 13,000 bbl/d, average water rate of ~ 19,000 bblw/d, average gross rate of 32,000 bbl/d and average W.C% ~ 60%. The pilot performance was achieved with total gas lift injection ~ 6 MMSCFD (which means 0.6 MMSCFD per well in average). The total oil recovered from the current GL pilot, during a period of one year (330 producing days) is 4.15 MM bbl, this can be roughly turned in to cash amount equal to $ 207.5 MM (assuming 50$/bbl).These resulted values from the GL wells have been surging up and down as a result of the optimization process in order to minimize the W.C% and increase the oil rate. Real Time Optimization (RTO) process is important and currently is ongoing (last stage) to be fully implemented to optimize especially the GL produced water (amount and treatment) in addition to the oil production. Gas quality, availability and conditions have been ensured with the current available field facilities.Pilot Modeling is vital to assess each well behavior, therefore every well has been modeled using Inflow/Outflow Software and pertaining data has been continuously validated and updated according to the production tests and actual findings. Different monitoring tools have been used such as RST, PLT and Gas Lift surveys to identify the actual well performance. The Pilot modeling results have been used as a guidance to predict the full field future GL performance.Generally, the Pilot results revealed the important questions and achieved the core objectives related the GL system for full field implementation.
The company introduced a new era of Well Integrity Management system as a continuous assessment and verification process to ensure the integrity of the wells is designed, monitored and maintained throughout the well life cycle.Failure of any well barriers is not allowed. If a barrier fail , an immediate action should be taken to restore the well integrity, which is one of the important business elements in oil and gas fields; and hence according to well integrity standards utilizing well control devices are mandatory to protect human life, and reduce the potential for environmental pollution in addition to minimize the loss of production.The surface control subsurface safety valve (SC-SSSV) is an integral part of the overall safety system of any well and it is the only method that provides sub-surface isolation in case of emergency due to uncontrolled surface or sub-surface event. Therefore it is mandatory to have functional SC-SSSV installed in the production tubing in all gas and oil wells, irrespective of their location, to stop the flow in case of a catastrophic failure.The SC-SSSV is adjusted to be held in the open position by hydraulic positive pressure from surface. This pressure is applied through a control line in the tubing-casing annulus running from the valve to the surface. In case of an emergency shutdown the hydraulic pressure will be released forcing the safety valve to close. However the control lines could leak, plug or break leading to losing the functionality of the safety valves. The only way to rectify SC-SSSV C/L problems is by a rig work-over to replace with new C/L. This paper describes the innovative methodology, which is the first application in the UAE & Middle East, to install Baker Hughes system "Inject-safe" controlled sub-surface safety valve which has a similar operating philosophy to the conventional SC-SSSV. The "Inject-safe" C/L deployment is on the inside of the tubing which drastically reduces the cost. This unique approach has been successfully executed in one of the super giant onshore fields in Abu Dhabi through an extensive techno-economical study.The paper goes through the methodology of candidates' selection, the system requirements and modification in wellhead and the trial results through specific testing criteria in one of the wells as part of a field pilot. The risk assessment is also discussed along with the execution process.The cost impact of installing the new system as proved in the pilot through a techno-economical evaluation well will be highlighted, in addition to well performance pre/post installation combined with the project conclusion and recommendation for future implementation.
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