Five-year program of seismic monitoring begins in September;
six 5-km hydrophone cables to be embedded in seafloor
Dev George
Managing Editor -- International
- Foinaven's floating production platform and subsea seismic acquisition system.
- The Foinaven Field lies in the highly prospective West of Shetland area of the UK's North Atlantic.
The first use of 4D seismic technology in deepwater anywhere in the world is about to begin on the UK's Foinaven Field, west of the Shetland Islands. British Petroleum has elected to employ 4D to improve its management of the Foinaven reservoir during production.
In what it calls its FARM Project (Foinaven Active Reservoir Monitoring), BP will utilize time-lapse 3D seismic acquisition, shot at about one-year intervals, to monitor fluid movement within the reservoir over time. The
technology was used previously only in shallow water. This should provide considerabl esavings in development costs by reducing the number of wells necessary to access the oil.
Each Foinaven well represents a large investment in drilling, completion, and subsea infrastructure. But rather than collect data in the traditional way, using streamers towed behind a survey ship, BP and its Foinaven partner Shell have contracted Geco-Prakla to carry out the geophysical acquisition and processing services.
Buried cable
Geco is supplying six custom-designed, five-km hydrophone cables that will be buried in the seabed at a water depth of 480 meters over the southern sector of the field, where the first two production wells have been drilled. Alcatel is providing the trenching and installation of the cables. Once the cables have been deployed in straight lines 300 meters apart, the first survey will take place.
Continuous seismic monitoring on this scale at this stage of field development is unprecedented. The technology was successfully tried in the shallow waters (about 100 ft)
around BP's West Sole Field, in the southern North Sea, last year, but has not been attempted since.
Following cable deployment, the first survey will take place immediately to provide a base-line set of data prior to initial production. To carry out this survey, a seismic shi will shoot over the area of the cable array in a week-long operation. Signals picked up by the buried seabed hydrophones will be transferred to a dynamically positioned receiving vessel via a cable connector, then stored in a computer for digital processing.
So why the quantum leap into the deep water west of Shetland?
Conventional 3D seismic on Foinaven provides the ability to distinguish between oil-filled and water-bearing sands, but to monitor fluid movement over time, repeatability of the
operation is key. 4D seismic will assist subsurface teams to pinpoint and assess the volume of unswept oil with accuracy throughout the productive life of the field.
Model matching
The processed and interpreted information will be matched against the reservoir model, production data, and to previous surveys to identify any changes in the reservoir.
By doing this, it is hoped to ascertain fluid movement to assist reservoir management, knowledge which can then be extended to other BP exploration areas.
Mike Currie, Foinaven geophysicist, said, "We are confident that the equipment design can withstand the pressure of the water depth. We're investing in the application of a new seismic technology in an important frontier province and believe that this technology will provide major benefits in the future." Currie is a member of the geophysical team that includes Mike Daly of subsurface prediction; Dave Howe, seismic survey; Ronnie Parr, AFP geophysicist; Dave Madill, AFP commercial; and Shell's Chris Linskaill and Ron Masters.
Foinaven's reservoir rocks are younger than many in North Sea fields, explained Currie. The ability to discriminate between sands and shales and, more importantly, the fluid content within the sands, is improved with decreasing age and shallower depths.
"Conventional 3D seismic on Foinaven allows us to distinguish between oil-filled and water-bearing sands, but 4D is expected to be a method of monitoring fluid movement over time. Repeatability is the key. We'll be looking for subtle changes in the reservoir."
Currie also feels that 4D seismic will help to pinpoint and assess the volume of unswept pools, common in mature fields.
Movement in 4D
Until recently, models have been the best way operators could track the movement of fluid in reservoirs. However, their accuracy has always been questionable, since sample points may be far apart and interpretation of data is difficult, at best. Now, however, 4D seismic offers the possibility of highly accurate data to dramatically improve reservoir management and avoid problems.
Four-D allows geophysicists to follow the movement of reservoir fluids, to know how their distribution changes over time. By plotting the fluid contacts during production, for example, flow models can be confirmed or rejected in order to change recovery schedules.
In addition, mapping steamflood fronts during enhanced oil recover may indicate zones that were by-passed which might be future targets of remedial work. And well placement, stimulation treatment, and waste disposal can be facilitated by mapping hydraulic fractures to reveal local stress fields that govern permeability anisotropy.
Four-D seismic monitoring illuminates each of these problems.
Reservoir changes
Pore fluid undergoes changes in temperature, pressure, and composition as reservoirs are exploited, and enhanced recovery techniques such as steam injection also increase temperature. Fluid pressure is normally lowered by fluid production, and both gas injection and waterflooding alter the reservoir composition.
Such changes affect the reservoir layers' volume density and seismic velocity, which in turn, combine to affect the amplitude and travel times of reflected waves. Rather than travel time, amplitude changes are the basis of most 4D seismic monitoring, but they must be of sufficient size to represent a difference between the base survey and follow-up surveys.
Laboratory data allows an estimation of the probable change in seismic amplitude to be made. It derives from the effects of fluid on rock velocity rather than rock density. Most of the changes in velocity originate either from the introduction of gas into a liquid-filled rock of gas or an elevation of the temperature of a hydrocarbon-filled rock.
Both result in a decrease in seismic velocity, because the gas dramatically reduces velocity due to compression of the fluid and hydrocarbons' reduced rigidity under higher temperatures. Each of these are more evident in shallow, unconsolidated sands and at low pressures.
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