Figure 4.51: 4D traveltime changes at Top Ekofisk from 1999–2003, 2003–2006 and 2006–2008. The images show a propagating water front from injector well K3 towards producers X16, X28 and M17 which were put on production in the period 2003–2005. Positive time shifts are a result of reservoir compaction and decreased seismic velocity in the sediments above top reservoir.


is used in a predictive sense to help place new producers in areas of considerable water-flooding risk. However, the subtle amplitude changes are noisy, and challenging to interpret reliably from streamer 4D seismic data.


4.6.2 Monitoring with a Permanent System


By 2008, 4D seismic streamer surveys had become an established technique to help identify remaining oil zones for new production wells. Te risk of encountering water-swept zones had been reduced and the net result was accelerated production and fewer redrills. Despite the complexity of installing 200 km of permanent


ocean-bottom seismic cables around existing infrastructure and numerous pipeline crossings, the conclusion from a Value of Information (VOI) study was still that this would be the best solution for future seismic monitoring at Ekofisk.


The Ekofisk Field


Te Ekofisk field, located in block 2/4 in the Norwegian sector of the North Sea, is formed from fractured chalk of the Ekofisk and Tor formations of Early Paleocene and Late Cretaceous ages, most of which had high initial porosity in the range of 30–50%, but low permeability of 1–5 mD. Te reservoir is an elliptical anticline, 11.2 km long and 5.4 km wide at 2,900–


3,300m depth. At the crest of the field is the seismic obscured area (SOA) where gas charged zones in the overburden complicate imaging with conventional seismic data (see Figures 4.51 and 4.52). Ekofisk was discovered in 1969, and has been producing since 1971. Te field


was originally developed by pressure depletion with an expected recovery factor of 17%. However, a large-scale water injection programme which started in 1987 has proved successful and has contributed to a substantial increase in oil recovery. Te initial pressure depletion, plus water weakening of the chalk due to the injected water, has caused substantial reservoir compaction, causing the seabed to subside by up to 9m. ConocoPhillips expects to recover more than 50% of the oil originally in place, with roughly 627 MMboe (98 MMm3


oe)


recoverable resources remaining at the end of 2016.


184


Figure 4.53: Top Ekofisk formation structure map showing the extent of the seismic obscured area (SOA).


Key parameters in the VOI analysis were cost estimates of permanent systems versus streamer surveys, track record of 4D seismic for well planning at Ekofisk, expected improvements in repeatability from fixed receivers and the forecasted well programme and production profiles within the licence period. A permanent array of ocean-bottom receivers would enable efficient data acquisition with a source vessel once or twice a year. Included as an upside in the economical evaluation was an expected improvement in imaging of the crestal part of the field with converted (PS) waves.


4.6.3 Choosing a Fibre Optic System


In 2008, ConocoPhillips invited six suppliers to bid on the provision of the Ekofisk LoFS to be installed in 2010. Tree of the providers offered conventional systems incorporating either traditional geophones or MEMS (micro-electro-mechanical-


Figure 4.52: Seismic line showing the seismic obscured area.


ConocoPhillips ConocoPhillips


ConocoPhillips


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