The objective of this paper is to demonstrate how both Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) data, acquired using a fiber-optic cable installed and cemented behind a 7" production casing, could be used for single-phase production allocation in two conventional oil producers in the South of the Sultanate of Oman. DAS data can be processed, time-averaged, and filtered to specific frequency bands, to identify and monitor the acoustic frequencies that are excited by the flow through the perforation tunnels. It will be shown that under certain assumptions, the flow-induced acoustic amplitudes at the perforations can be calibrated and converted into actual flow rates, which allows for continuous production profiling across all intervals of interest. DTS data, acquired under transient conditions, can also be analyzed using a thermal simulation model, to allocate production to specific perforation intervals, provided an appropriate logging program is followed. DTS is not as good as DAS in capturing dynamic changes to the inflow profile, but does have a deeper depth of investigation and is less sensitive to the geometry of the perforation tunnels or possible flow obstructions in the wellbore. The two technologies are therefore complimentary and are best acquired simultaneously. This is the first case study in the Sultanate of Oman, where both DAS and DTS data sets were successfully acquired and interpreted for single-phase production profiling in a conventional oil producer with perforated casing. Moreover, it was also the first time in Oman that oriented perforation was achieved with full shot density, through a double perforation run with a slight offset in orientation angle between the two runs.

The A West heavy oil reservoir in the South of Sultanate of Oman is a very attractive target for thermal EOR considering its low primary oil recovery of 20%. The field development plan proposed Vertical Steam Drive as a development concept for Phase 1 that included drilling and operating a total of 80 3.3 Acre inverted 7 spots patterns. Vertical and areal steam conformance has been highlighted as one of the main challenges in one of the most complex and thick heavy oil reservoirs in the world. As a result, the plan has proposed executing and operating a smaller spacing 1.1 acre pattern in parallel with full field development of the 3.3 acre patterns. The main objective of the trial is to run a full lifecycle in situ steam flood in 2-3 years compared to 15 – 20 years at field scale spacing. This will accelerate learning on steam breakthrough management in combination with understanding how to improve vertical and areal sweep conformance. A fully integrated surveillance plan using advanced technologies including down hole DTS temperature fiber cable, covering the whole wellbore have been installed in all producers. In addition to that real-time wellhead temperature monitoring is a key surveillance element to sense the impact of steam break-through in the producers. Multi-tracers injection will also be executed to monitor the areal sweep efficiency and estimate the preferential movement of the steam within the subsurface by measuring the concentration of the tracer in the producers. Along with that, mechanical conformance applications have been installed in the steam injectors to add an additional control on vertical steam conformance and test the effectiveness of such application on addressing steam break-through issues. The trial will provide direct experience in managing steam injection and production after steam breakthrough that can later be implemented on a larger scale. The integrated data from the trial will aid in calibrating the simulation models to anticipate the time to steam breakthrough and build confidence in the power of the model for short/long term forecasting. In addition, it will also provide early indications of the effectiveness of some of the new technologies and surveillance in predicting and addressing steam conformance challenges and hence optimize the steam flood process.

One of the key challenges of the "A" West reservoir thermal development is the presence of an active bottom aquifer. If unmanaged, high aquifer pressures relative to the oil reservoir would have a detrimental effect on the ongoing thermal Enhanced Oil Recovery (EOR) process. Consequently, the "A" West development strategy includes an Aquifer Pump Off (APO) system. The key APO management objectives are:Lower the reservoir pressure and hence:a.Improve injectivity.b.Improve heat efficiency (more latent heat).c.Prevent quenching of the injected steam.Secure the feed water for the steam generation. In order to meet the above objectives, the following methods were used to evaluate the targeted pump off rate:Material Balance analysis.History matched full field model.History matched regional aquifer model, whereby several aquifer pump-off scenarios have been explored to further deplete the aquifer pressure in "A" West. A high APO capacity is initially required for an accelerated aquifer pressure depletion to match the currently low reservoir pressure caused by historical cold production of the upper half of the reservoir. This initial APO capacity is only required until the target aquifer pressure is achieved, after which, aquifer pump off rate will be gradually reduced to avoid oil cusping into the aquifer. To monitor oil cusping, water samples are collected from APO wells and facilities and analyzed for oil contamination. Moreover, three observation wells were drilled for real time reservoir/aquifer pressure gradient monitoring. These observation wells will also ensure an optimum pressure differential between the reservoir and the aquifer. The produced APO water is partly used as feed water for steam generation, with the remainder relocated to a shallow aquifer via a separate relocation system. To ensure oil free water, APO wells are located 100m below the OWC. In order to avoid well integrity issues and heat losses through the produced water, well trajectories have been designed to evade penetrating the steamed formation. An additional opportunity was realized by re-routing a portion of the excess water to a northern water-flooding project to maintain its reservoir pressure. This paper will focus on the integrated APO strategy, which meets the reservoir management objectives of the "A" West steam flooding project, and the PDO water management strategy.

Context and Objectives Petroleum Development Oman's "A" Field Thermal Asset, southern Sultanate of Oman, is characterized by a large scale Steam Drive/Cyclic Steam Soak (CSS) development project, underpinned by extensive data gathering. Cambrian faulted/fractured braided river sandstones are the predominant reservoir, with < 300m of heavy oil. Viscosity is high, reaching up to 400,000 cPAt around 1100m tvd, the reservoir is relatively deep for a thermal project.Well count is high, and steadily increasing. These factors create a challenging environment for maximising oil recovery. Key to success is efficient execution of data management and analysis, within a visualization intensive, collaborative work environment. In this paper we aim to demonstrate that working in this manner, within a cross-discipline asset environment enables the rapid identification and execution of cost-effective optimization opportunities and risk reduction. Approach In order to provide a sufficiently broad description of how the Asset is working towards the desired outcome, the paper addresses the following elements:- Data Capture, Transmission and Storage.Application of original algorithms and tools to convert the data into meaningful insights.Accessibility to insights (speed and mode of access).Meaningful impact to efficiency, production, and safety.Added value associated with the implementation. Results to Date Some of the areas further discussed include the following:- Implementation of Automatic Beam-Pump Optimisation has resulted in step-changes in terms of both oil production and reduced manpower requirements.Distributed Temperature Sensing (DTS) wells are providing real-time temperature profiles, essential for monitoring steam conformance.Automated well tests are fully operational in "A" East Field, and the results can be viewed and analysed via desktop applications in the Asset.6 Micro-Seismic wells have been successfully executed and now provide real time monitoring of reservoir integrity.A live subsurface model has been developed, which can be rapidly updated with new drilling results and subsurface insights. The above elements are continuously facilitating asset management, whilst also highlighting opportunities and reducing uncertainty as we follow the data journey from scoping and capture through to bottom line impact.