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This paper applies a new constrained multiwell deconvolution algorithm to two field cases: a gas reservoir with two producers and an oil reservoir with three producers and one injector. This paper describes the use of a downhole temperature-sensor array during a commingled drillstem test (DST) to determine the density of produced fluids accurately. The complete paper describes the shortcomings of traditional well testing methods and the methodology and results of applying wireline-conveyed IPTT in a light-oil reservoir offshore Norway. In my inaugural column as editor of the Well Testing Technology Focus feature, I want to shine a light on the notable trend among operators of seizing on the tremendous untapped potential that exploration and appraisal wells represent for far-field reservoir characterization and connectivity. To predict liquid-loading tendencies and to identify opportunities for production enhancement, the performance of 150 gas wells was analyzed in two gas fields in India.
Gambhir, H.S. (Reliance Industries Limited) | Shrivastav, Anil (Bechtel O&G) | Lovell, John R. (Schlumberger) | Mackay, Stuart (Schlumberger) | Chouzenoux, Christian (Schlumberger) | Juchereau, Bernard Guy (Schlumberger) | Arachman, Fitrah (Schlumberger) | Chaudhary, Ashish (Schlumberger)
Measurements from permanent sandface sensors have been made in a dual-stage subsea well in the Bay of Bengal. Miniaturized temperature sensors were clamped to the exterior of sandscreens and transmitted their data across an inductive coupler back to the seabed by means of a downhole communication hub. The system has been permanently installed and was designed to provide interpretation data over the life of the reservoir. The completions hardware required to accomplish this was novel, but the implementation would not have been a success without attention to the overall instrumentation and controls architecture. Interface management was a key to the ontime deployment of the system.
The sensor data were transmitted in packed blocks that combined diagnostic information with raw temperature values. The communication hub merged those blocks with temperature and pressure values from above the production packer. Inductive coupling provided a wireless transmission of power and data between the upper and the lower completion. The combination was transferred to a subsea interface card in the tree which made the data available using a ModbusTM protocol. The Modbus data were transferred by subsea vendor protocols to a rack-mounted computer on the production platform. For the subsea vendor, there were essentially no differences between for sandface data versus for those wells with measurements only above the production packer. In particular, no additional or non-standard penetrations were required through the tree.
The sandface temperature data were transmitted in real-time during clean-up to the company headquarters in Mumbai, where they were staged onto an OracleTM database. A thermal simulator has been configured to upload data from that database and provide an iterative inversion wherein reservoir properties are varied until simulated temperature data matches the measured data. Standard fluid modeling programs can then give a flow profile from those intepreted reservoir properties. The same thermal simulator will be used for production data, in which case the well data passes from the production platform to the same remote database using a redundant architecture.