The choice of which seismic reservoir monitoring technique to use depends on a number of factors. In fields with more than 10 years of production left, and with a significant number of wells to be drilled, or those where difficult reservoir conditions imply that it would be advantageous to carry out frequent surveys, typically at intervals of about one year or less, permanently installed ocean bottom seismic (OBS) cable systems is the cost-effective alternative to conventional streamer surveys.
Snorre – large IOR-potential
The first seismic section measured with light! The blank area in the middle is caused by the gap between the two cables as laid out on Snorre. Courtesy: StatoilHydroFrequent time-lapse observations with high survey repetition accuracy hold the potential to provide a wealth of information related to production and injection responses. The consequent improved reservoir understanding allows (1) early reaction to unexpected well or injection program failure, (2) search for bypassed zones, and better placement of future wells, (3) confident development of reservoir production plan, (4) validation of the dynamic model, and updating of the reservoir simulation model, and (5) monitoring of fluid migration, injection paths, and well performance.
The Snorre field (see Box) is a major North Sea oil field that is expected to benefit from frequent surveys with accurate survey repetition. Snorre is a thick, heavily faulted, eroded and heterogeneous fluvial reservoir with a complex production history and with a large IOR potential. The field’s future economy relies on an effective IOR strategy.
In 2006, Snorre initiated a focused seismic monitoring (FSM) project. The project investigated the benefit of frequent monitoring of the reservoir in areas with large remaining reserves where a high number of advanced and expensive wells are to be drilled, as well as the feasibility of optimising production/injection and increasing the understanding of the drainage pattern.
Collaboration with Optoplan
The Snorre field pilot made information on vessel and source positioning available in real time, while broadband transfer of the recorded seismic data via a fibre optic communications network to the dedicated operations centre in Trondheim permitted quality control and seismic imaging in “near time” – within a minute or so of acquisition. Courtesy: StatoilHydroStatoilHydro’s need for robust long-term solutions for repeated seismic data acquisition led in 2004 to a collaboration project between StatoilHydro R&D and Optoplan AS to develop a fibre-optic based ocean bottom seismic technology suitable for FSM. As we reported in GEO Expro No 3/2009, the Optowave fibre optic sensor technology was successfully field tested in the Trondheim fjord and at Tjeldbergodden, offshore Norway.
After the Tjeldbergodden field test, the Optowave seismic array was ready for final qualification in a StatoilHydro pilot at Snorre. The pilot objectives were to (1) assess the operational aspects of recording seismic data using permanent sensors trenched into the seabed, (2) demonstrate that recorded data gathers could be transferred to the onshore support centre (OSC) in real-time (within 30 sec) for data analysis, and (3) demonstrate that the final seismic processed section could be delivered to the interpreter within 48 hours of the last shot being recorded.
The Optowave array was trenched into the seabed at a depth of 1 m with an east-west orientation approximately 3 km north of the Snorre A platform. The array consisted of two seismic cables laid out ‘back to back’ giving a total array length in the order of 10 km. Each cable contained 100 fibre optic sensor stations with an inter-station spacing of 50 m. The two cables were connected to a lead-in cable and then up to the platform via a fibre tail available on the seabed. A data interrogation unit was installed on the platform and connected to a dedicated sub-network within the already existing StatoilHydro infrastructure.
Data acquisition and QC
The fibre optic sensor data were acquired twice. The repeatability is very good (right). Typically, the repeatability of conventional streamer data is poorer (left). Repeatability is conventionally expressed as NRMS (normalized root-mean-square) magnitude. NRMS values above 50% are considered too large to be of real value; 30-40% is considered good, and lower values are excellent. Courtesy: StatoilHydroThrough collaboration with Schlumberger the onshore support centre (OSC) and imaging cluster dedicated to seismic acquisition were installed at StatoilHydro’s R&D centre in Trondheim. The OSC allowed the concept of integrated operations (IO) for seismic operations to be evaluated.
A seismic vessel equipped with an airgun source was used to acquire a number of shot lines over the Optowave array so that seismic quality could be assessed. The source lines were acquired twice to study repeatability. The data were recorded by the topside interrogation unit.
During seismic operations quality control would normally be handled in the field by company representatives and reports sent to the company each day. For the FSM pilot, expert support and quality control functions were assembled in the OSC. Vessel and source positioning were made available in real time and seismic data transfer allowed for quality control 30 seconds after every shot.
Constantly updated QC products were made available to the FSM stakeholders who were situated at different geographical locations. Since the requirements for information were not identical for the different stakeholders, solutions to provide different levels of information were utilized. These ranged from full access of all QC material in the OSC to an abridged overview made available through a web interface that was accessible via a smart telephone solution.
A dedicated cluster formed the major part of a distributed data processing system that included processing capability on the platform during data acquisition.
Since the sensor package is deployed in an unknown orientation on the seabed, the first break energy was used to derive the orientation of the accelerometers. The data were then rotated into vertical, radial and transverse components. The data processing sequence included noise attenuation, data summation and pre-stack depth migration with a P-wave velocity model available from the earlier processing of streamer data.
With the processing parameters decided and the data from acquisition made available to the cluster on a shot-by-shot basis it was demonstrated that the seismic section could be produced within 6 hours of the end of acquisition, well ahead of the pilot objective of 48 hours!
Successful project and pilot
The FSM project successfully identified key criteria for the long term future of reservoir monitoring at Snorre. These included high data quality, through a high degree of repeatability, fast turn-around and short intervals between monitoring campaigns. The FSM pilot carried out during 2008 demonstrated the concepts of Integrated Operations for seismic acquisition and ‘on-demand’ monitoring.
Statoil Hydro’s goal is to apply 4D seismic to 100% of its fields that show positive 4D potential. In 2009, it set up a multidisciplinary, global implementation team that is currently evaluating the 4D potential for the company’s fields around the world with the mandate where necessary to recommend deployment of appropriate monitoring technologies. Permanent reservoir monitoring is currently subject to a comprehensive business case.
Acknowledgments
We thank StatoilHydro and the Snorre unit (ExxonMobil Exploration & Production Norway AS, ?Hess Norge AS, Idemitsu Petroleum Norge AS, Petoro AS, RWE Dea Norge AS, StatoilHydro Petroleum AS, and Total E&P Norge AS) for permission to publish the results.
References
Morton A, M Andersen and M Thompson 2009 Field Trial of Focused Seismic Monitoring on the Snorre Field: 71st EAGE Conference & Exhibition, Amsterdam
