Not so long ago, marine seismic was strictly a regional fabric and prospect development tool. Over the past two years that wide but limited envelope of operation has expanded so seismic evaluation is now being used for field production monitoring. Reservoir engineers are learning the theory and functionality behind acoustic-based tools for viewing beyond the bore of producing wells into the reservoir fabric. Below is a brief review of recent developments that have led us to this new seismic frontier.
A seismic data acquisition revolution began several years ago with the commercialization of 3D towed-streamer systems; they are an order of magnitude improvement over earlier 2D seismic. Denser spacing of longer towed arrays now permits whole basins to be viewed on 3D workstations and quickly evaluated for prospectivity. Infill surveys keep tightening the grid of control while detailed, high-resolution grids are gathered over field discoveries.
Over time, the early high-resolution surveys were re-shot. This opened the potential of comparing surveys to track field production and locate bypassed reserves. The value of detailed 4D studies began to prove their worth - they located "new" reserves.
The next logical step in reservoir illumination was to fix an acquisition system to the seabed. The advantage of a fixed system is the collection of a shear wave information to help understand the lateral variation within reservoirs.
Moveable seabed systems were considered next and are still in development. These can either be pulled through the water, moved along the seabed into repeatable grids, or deployed as single point systems that are lowered to the same seabed location over time to collect a 3D data grid for 4D comparison.
At the same time that towed marine systems were moving to the seabed, borehole geophone systems were expanding to take on a new role - production monitoring.
Recent developments allow the permanent placement of geophones in producing wells to monitor fluid movement with microseismic.
The availability of larger data sets challenged the processing capability of the industry. Fortunately, advances in computer hardware and software were occurring at the same time so that processing capability rose as the need for data processing capacity expanded. Many seismic contractors built new processing centers or upgraded existing centers to handle the expanding workload.
High-speed data links on land and by satellite now allowed data processing of a single dataset to happen in many centers at once.
Standard post-stack processing was augmented by pre-stack processing to search for reserves near and under salt bodies.
Computer power is being used in other new ways. Kirchoff migration technology uses interpolation to create a regular matrix of spatially distributed locations for 3D survey bins. Most surveys have irregularly spatially distributed common midpoints (CMP or bin centers). Regularizing the location matrix speeds standard processing, even though it introduces some error into the data.
Now with improved computer power, full waveform processing has just become available. This processing technique eliminates Kirchoff errors because it does not need to interpolate to a new CMP. The technique can adjust to the irregular CMP spacing as the processing sequence moves through the dataset. This yields better data migration. The result is a more accurate image of the subsurface and more accurate signal attributes.
The greatest productivity tool for the geophysicist by far is the development of the interpretation workstation and the software that drives it. Using these tools, a trained professional can review and interpret an order of magnitude more data than was possible using 2D paper records (sections). This is mainly due to the automation of grid value picks whether horizons or faults. Freed from record keeping, the interpreter can use the time searching for prospects.
Second to the workstation is the ability to use natural and derived attributes from the 3D survey. Natural attributes include signal amplitude, phase, and frequency, as well as two-way-time. Many derived attributes use proportions of signal elements or comparisons between one or more different signal elements. By viewing these derived 3D volumes, sedimentary features are revealed and the geologic history of an area is open to evaluation. Measures of apparent porosity and permeability are also possible to guide well placement when tied to existing well data.
The technology for displaying seismic data for interpretation has changed completely. After making the leap from marking paper sections to working 2D data on a computer screen, interpreters now use both larger monitors and room-sized projections systems to examined 3D datasets. From flat projections of 2D data, to rotatable 3D volumes, to fully immersive "walk-through" 3D projections, digital video technology has opened up the seismic dataset like no other technology.
Now multiple attribute volume display technology is available for the desktop PC workstation.
The seismic revolution of the past few years has completely changed the way data is presented and examined. Productivity of individual professionals has jumped, leading to more oil reserves in more difficult environments than ever before. The industry is still developing its technical capabilities and has more to come.