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A vital key to Cook Inlet exploration Seismic surveys are essential to deciding where to drill but can be tricky to conduct in challenging geology and environment Alan Bailey Petroleum News
With a heightened interest in recent years in searching for new oil and gas resources in Alaska’s Cook Inlet basin, the use of data gathered from seismic surveys has become a critical factor in deciding where to drill exploration wells. A seismic survey involves creating sound waves bouncing from a sound source such as a small surface explosive device. The echoes of these sound waves from geologic structures deep underground are detected and recorded at the surface. Geoscientists can then use the recorded data to construct images of the subsurface, to identify potential oil and gas traps.
But the acquisition and processing of seismic data in the Cook Inlet region can be difficult, if rewarding, thanks to a combination of surface challenges and complex subsurface geology. And, in a chapter of a memoir on the oil and gas fields of the Cook Inlet basin published recently by the American Association of Petroleum Geologists, Diane Shellenbaum, a geoscientist with Alaska’s Division of Oil and Gas, reviewed the various techniques used for the acquisition and processing of seismic from the basin.
Old seismic data gathered many decades ago during early exploration of the basin is generally of very poor quality, but a dataset covering much of the marine area of the basin was gathered in the 1980s and is available for licensing, Shellenbaum wrote. Much existing seismic data is held by oil companies, geophysical contractors and Cook Inlet Region Inc., the regional Native corporation, with some of the data available for sale, she wrote.
Sound energy The physics of seismic data acquisition relates to the properties of sound as it passes through rock strata. Essentially, a seismic sound source creates a pulse of sound that contains a mix of sound frequencies. The speed with which the sound travels through subsurface rocks varies, depending on what is referred to as the acoustic impedance of the rocks. And where two different rocks with contrasting impedances share a sharply defined boundary, some of the sound energy passing through the boundary is reflected, creating an echo that can potentially be recorded at the surface.
The shorter the wavelength of the sound, and hence the higher the sound frequency or pitch, the finer the detail that the seismic echoes can discern in the subsurface geology. But there are physical and practical limits to the sound frequencies that can be used, so that there are also limits on how finely a seismic survey can resolve the details of the geology.
Lower frequencies dominate Shellenbaum explained that the geology of the Cook Inlet basin tends to cause lower frequency sound to dominate seismic recordings, requiring survey designs that maximize sound energy penetration and that allow for the recording of a wide frequency range.
The relative attenuation or dampening of the higher frequency signal components appears to result from a number of factors. In particular, the rock strata in the basin typically include many relatively thin beds of rocks of contrasting impedance, including coal seams, volcanic beds and conglomeratic horizons. The highly reflective boundaries between these strata tend to both absorb sound energy and cause multiple echoes to bounce back and forth, dampening the sound signals and causing the loss of the higher frequencies, Shellenbaum wrote.
Complex structures Added to these difficulties are the complex structures into which the strata have often been contorted and faulted, with this complexity requiring appropriate seismic processing. And geologic stresses that have been imposed on the rocks tend to cause the sound velocity to vary with the horizontal direction in which the sound is travelling, a factor that requires special care when conducting surveys involving multi-directional data, Shellenbaum said.
When using seismic data to evaluate subsurface geology, geoscientists attempt to tie sound reflections observed from the data to boundaries between rock strata identified from whatever wells have been drilled in the region of the survey. The geoscientists can then trace the relevant rock boundaries through the subsurface using the seismic data, to locate potential drilling targets.
But tracking the subsurface geology in this way for the Cook Inlet basin can be problematic, both because of the challenges of seismic data acquisition and because of the age of much of the existing well data, Shellenbaum wrote.
Difficult to trace In addition, the nature of the geology of the basin can make the tracing of specific rock strata through the subsurface difficult. The producing oil and gas fields of the basin are located in what is referred to as the Tertiary sequence, the younger and shallower of the two major rock sequences of the basin. The Tertiary rocks were formed from sediments laid down on land from a system of ancient rivers, resulting in a system of discontinuous river sands, discontinuous coal seams and other rock types.
And the lack of acoustic impedance contrast between the river-deposited silty sands and mudstones in the basin fill leads to low sound reflection from these units and consequent difficulties in tracing individual rock interfaces, Shellenbaum wrote. On the other hand, there are some distinctive rock units, such as the West Foreland formation, that tend to be easier to track around the basin, she wrote.
Onshore and offshore The acquisition of seismic data takes place in two distinctly different environments: on land and offshore in the inlet itself. Between these two environments lies a transition zone, characterized by the ebb and flow of the massive Cook Inlet tides, with extensive areas of mud flats, and commonly impacted by grounded ice in the winter.
Although surveys could be conducted in the better-drained upland areas year round, on-land surveys are generally conducted between late October and March, when the freezing of surface water helps protect fish and wildlife while also simplifying wetlands operations, Shellenbaum wrote. A variety of technologies have been used as seismic sound sources, including buried explosives, surface explosives and surface vibrators. Land access can be challenging, with the potential need for helicopter transportation for crews, and for the use of cable-free recording systems. And a general lack of easy road access, the seasonality of data acquisition and a small seismic contractor market all tend to lead to acquisition costs that can be higher than in the Lower 48, Shellenbaum wrote. A land survey may also need to contend with complex land use and permitting issues, she wrote.
Challenges of the inlet The marine acquisition season tends to be limited by winter sea ice and the need to avoid fishing and protected species at certain times of the year. The strong tidal currents can make the management of long surface streamers of seismic receivers in the confined waters of the inlet difficult, with data acquisition typically limited to periods of slack tides. Modern systems of data acquisition using recording nodes placed on the seabed have also been used and should enable improved data acquisition efficiency, Shellenbaum wrote.
The transition zone between the land and marine environments involves a transition between sound sources typically used onshore and the air guns that are typically used in a marine survey. There is also transition in the types of seismic receivers used. And data from a transition zone survey typically needs to be merged with data from a land or marine survey, Shellenbaum wrote.
Successfully used Given the various challenges in obtaining data from the Cook Inlet basin, surveys require careful planning both from logistical and technical perspectives. But seismic data have been successfully collected and used for exploration of the basin, Shellenbaum wrote. Data quality has progressively improved over the years. However, much of the existing data is from 2-D surveys that result in two-dimension cross-sections of the geology. Harnessing the full hydrocarbon potential of the basin will require modern, high-quality 3-D data, to identify the basin’s more subtle hydrocarbon traps, Shellenbaum said.
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