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BRITAIN'S OFFSHORE OIL & GAS

*Discovering the Underground Structure


Introduction

Large-scale geological structures that might hold oil or gas reservoirs are invariably located beneath non-productive rocks, and in addition this is often below the sea. Geophysical methods can penetrate them to produce a picture of the pattern of the hidden rocks. Relatively inexpensive gravity and geomagnetic surveys can identify potentially oil-bearing sedimentary basins, but costly seismic surveys are essential to discover oil and gas bearing structures.

Sedimentary rocks are generally of low density and poorly magnetic, and are often underlain by strongly magnetic, dense basement rocks. By measuring 'anomalies' or variations from the regional average, a three-dimensional picture can be calculated. Modern gravity surveys show a generalised picture of the sedimentary basins. Recently, high resolution aero-magnetic surveys flown by specially equipped aircraft at 70 - 100m altitude show fault traces and near surface volcanic rocks.

Shooting seismic surveys

More detailed information about the rock layers within such an area can be obtained by deep echo-sounding, or seismic reflection surveys. In offshore areas these surveys are undertaken by a ship (F52) towing both a submerged air or water gun array, to produce short bursts of sound energy, and a set of streamers of several kilometres length. Each streamer contains a dense array of hydrophone groups that collect and pass to recorders echoes of sound from reflecting layers. The depths of the reflecting layers are calculated from the time taken for the sound to reach the hydrophones via the reflector; this is known as the two-way travel time (F50a & b). The pulse of sound from the guns radiates out as a hemispherical wave front, a portion of which will be reflected back towards the hydrophones from rock interfaces (F50a). The path of the minute portion of the reflected wave-front intercepted by a hydrophone group is called a ray path. Hydrophone groups spaced along the streamer pick out ray paths that can be related to specific points on the reflector surface (F50c). Graphs of the intensity of the recorded sound plotted against the two-way time are displayed as wiggle traces (F50b).

Seismic recording at sea always uses the common depth point (CDP) method (F50c & d). A sequence of regularly spaced seismic shots is made as the survey vessel accurately navigates its course. Shots are usually timed to occur at distances equal to the separation of the hydrophone groups. In this way up to 120 recordings of the echoes from any one of 240 reflecting points can be collected. Each represents sound, which has followed a slightly different ray path, but has all been reflected from the same common depth point.

F50: Seismic surveying

Processing

Processing recordings involves many stages of signal processing and computer summing. Firstly, wiggle traces from a single CDP are collected into groups. Displayed side by side in sequence they form a CDP gather (F51a & b). Reflections from any one reflector form a hyperbolic curve on the gather because the sound takes longer to travel to the more distant hydrophones. This effect is called normal move out (NMO). Correction is needed to bring the pulses to a horizontal alignment, as if they all came from vertically below the sound source (F51c). The separate wiggle traces are added together, or stacked (F51d). Stacking causes true reflection pulses to enhance one another, and hopefully, random noise will cancel out. This process is repeated for all the CDPs on the survey line. The stacked and corrected wiggle traces are displayed side by side to give a seismic section (F51e). Most seismic sections used by the oil and gas industry are time-sections that have undergone a long sequence of data-processing steps designed to improve the quality of the reflections and bring out subtle geological features. For particular purposes, after the principal reflectors have been identified or 'picked', a time-section may be converted to a depth-section (F54). For this and also for NMO corrections before stacking, the velocities of sound in the rock layers traversed by the section need to be known. Computer analysis of traces during NMO corrections yields velocity values, but more accurate data comes from special velocity surveys carried in wells in conjunction with sonic logging.

F51: Stages in processing a CDP gather, and a seismic section assembled from stacked gathers

Data processing lessens the impact of various undesirable effects that obscure the reflected signals; it also compensates for some intrinsic deficiencies of the CDP method. Undesirable effects (F53b) include multiples, where the sound is reflected repeatedly within a rock formation and, because this takes time, registers as a deeper reflector; reflections between the water surface and the seabed are a similar phenomenon known as ringing. Diffractions are hyperbolic reflections from the broken end of a reflector; they mimic arched formations. Random noise, mainly unwanted reflections from within rock layers, horizontally propagated and refracted sound, bubble pulsations from the airguns and other effects also need to be reduced. Stacking reduces multiples and random noise, but the main computer processing steps are deconvolution, muting and filtering, and migration. Deconvolution ('decon') aims to counteract the blurring of reflected sound by 'recompressing' the sound to the clean 'spike' emitted from the source. The result is clearer reflections and the suppression of multiples. Muting cuts out parts of traces embodying major defects such as non-reflected signals; filtering removes undesirable noise to enhance the best reflections. Finally, migration corrects distortions caused by plotting inclined reflectors as if they were horizontal and vertically below the midpoint between shot and receiver; it also collapses diffractions (F53a). In this process, the seismic energy is relocated to its true subsurface location, ready for interpretation.

Interpretation

F52: Seismic surveying in progress

Seismic sections provide 2-dimensional views of underground structure. By using special shooting techniques such as spaced airgun arrays or towing the streamer slantwise, or by shooting very closely spaced lines, it is possible to produce 3-dimensional (3D) seismic images (F59). These images comprise vertical sections and horizontal sections ('time-slices').

F53a: The reason for migration

Seismic stratigraphy is the study of the depositional interrelationships of sedimentary rock as deduced from an interpretation of seismic data; it can be used in finding subtle sedimentary traps involving changes in porosity. 'Bright-spots', short lengths of a reflection that are conspicuously stronger than adjacent portions may indicate gas: the velocity of sound is sharply reduced in gas-bearing rock, producing a strongly reflective contrast. A gas-water or gas-oil interface may stand out as a noticeably flat reflection amongst arched reflections (F56).

F53b: Undesirable effects on seismic traces

The end-products of seismic surveys are interpreted sections showing geological structure down to fine sedimentary details. Maps are used to describe the topology of known rock units and 'isopach' maps are showing the thickness of these units. For the maps, reflections are 'picked' and their depths at points along parallel and intersecting survey lines plotted and contoured.

Seismic sections that have been picked by hand are digitised and the digital files entered into a gridding and contouring program. Contour maps (F58) can be plotted or 3D colour and shade enhanced images (F61) can be generated to illustrate the subsurface structure. Some rock layers produce wiggles with a distinctive character that can be followed right across a section; others may be identified by comparison with synthetic 'seismograms' made from logging and velocity surveys in existing wells in which the rock sequence is known.

F54: A seismic depth section

The seismic maps are used to identify structures that would either repay more detailed seismic surveying or would warrant wildcat drilling. The interpreter studies the maps to identify areas that are shallower and form a dome shape (an anticline) or a shallow area surrounded by faults (a horst block) - within such structures it is possible that migrating oil or gas may have been trapped.

F55: Studying seismic maps

Initially 3D seismic surveys (F60) were used over the relatively small areas of the oil and gasfields where a more detailed subsurface picture was needed to help improve the position of production wells, and so enable the fields to be drained with maximum efficiency. In the early 1990's, when exploration in the North Sea shifted to smaller and more subtle traps, 3D seismic surveys became more widely used for exploration work. The vast amount of data generated by even a small 3D survey meant that computer workstations were an essential tool for interpreting the data quickly. With a computer an interpreter can map a specific reflector by moving the cursor along it on the screen or, when a reflector is strong and continuous, the computer can 'auto-pick' that horizon through the whole 3D data set. Digital files of reflector picks can be transferred directly from the interpreter's workstation to mapping software. Visualisation software (F63) is an additional tool that allows the interpreter to view the whole 3D data set as a cube and rotate or cut it at any angle, allowing a picture of the subsurface geometry to be quickly seen.

Latest developments

F56: 'Flat spot' (X) and 'Bright spot' (Y) F57: Distinctive rock layer (X) and subtle trap (Y)

Recent increases in computing capacity have enabled the migration process to be applied before stack, i.e. on the vast amounts of data collected in the acquisition phase. This pre-stack depth migration (PSDM) application is critical in areas with complex geological subsurface structures, such as around/below salt domes and other high-velocity layers. This has led to the first reliable seismic images of sediments located below such complicated overburden structures.

F58: Contour map of a reflector    F59: 3D 'Cutaway' Seismic volume with well paths

Because of the greatly improved seismic resolution of 3D seismic imaging, there has been an effort to reduce the cost of 3D data acquisition and shorten the time it takes to acquire and process the large volumes of data acquired. In the past it could take up to 24 months to process the recordings from a 3D survey. Acquisition time has been cut by specially designed survey vessels deploying up to ten multiple streamers at a time (F62), or by using multiple vessels. These techniques allow a swath of seismic data to be acquired in the same time it previously took to record a single 2-dimensional line. Specially designed paravanes steer the cables away from each other. Their design reduces the drag of the streamer array, which ordinarily would be sufficient to stop even quite a powerful vessel. Modern streamers have multiple global positioning system (GPS) sensors that constantly record the position of the streamers relative to the vessel and the earth.

F60: 3D Seismic survey section of the Brent field    Ocean bottom 3D seismic survey, colour coded with sand thickness derived from seismic attributes. Red indicates thick reservoir sand, blue indicates no sand

New techniques of data compression are being tried to allow the transmission of the raw seismic records from the acquisition vessel to the shore for immediate processing, in an effort to get the data to the interpreters faster.

Improved resolution and reduced acquisition/processing times have opened up the possibility of shooting seismic at different time intervals over the same area of a producing field, in order to detect changes. These changes with time will clarify how a field is behaving by revealing exactly where the fluids are or are not moving, or by revealing changes in pressure in different parts of the field, thereby indicating how production might be improved. This is the so-called 4D or time-lapse seismic, where time is essentially the "fourth dimension". Results in recent years have been quite astonishing.

F62: The 'Geco Eagle' towing ten seismic streamers    F63: 3D Visualisation systems help fast track decision making in the development and production of oil reservoirs

If seismic is to be acquired at regular intervals over the same field, then it can be economic to permanently install an array of hydrophones on cables buried just beneath the seafloor. BP has done this in the Foinaven field (F49), for example, with the aim of shooting over the array with a seismic vessel once a year.

Another recent development is that visualisation has been taken to a new level with the advent of Virtual Reality rooms (F63 & 64), allowing 3D subsurface images to be displayed on large screens and to be viewed from almost any angle. Different development options, such as the impact of various drilling targets, can be simulated. Much of the benefit of this approach stems from the fact that communication and understanding are greatly enhanced when multi-discipline teams meet whilst "immersed" in such an environment.

F64: 3D Visualisation systems enable geologists, geophysicists and reservoir engineers to design optimum well trajectories



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