3 Exploring for oil and gas
3.1 Detection, exploration and evaluation (continued)
3.1.3 Seismic data and interpretation
Seismic surveying is by far the most widely used and important method of gaining an impression of the subsurface. Seismic surveys can be acquired at sea as well as on land. The marine method is the most common in petroleum exploration and is shown schematically in Figure 6, although the same principles apply to any seismic reflection survey.
Figure 6: Marine seismic acquisition – pulses of sound energy penetrate the subsurface and are reflected back towards the hydrophones from rock interfaces.
Compressed air guns towed behind a boat discharge a high-pressure pulse of air just beneath the water surface. The place of detonation is called the shot point and each shot point is given a unique number so that it can be located on the processed seismic survey. The sound waves (effectively the same as seismic P-waves produced by earthquakes) pass through the water column and into the underlying rock layers. Some waves travel down until they reach a layer with distinctively different seismic properties, from which they may be reflected in roughly the same way that light reflects off a mirror. For this reason such layers are called seismic reflectors.
The reflected waves rebound and travel back to the surface receivers (or hydrophones), reaching them at a different time from any waves that have travelled there directly. Their exact time of travel will depend on the speed that sound travels through the rock: its seismic velocity. Other waves may pass through the first layer and travel deeper to a second or third prominent reflector. If these are eventually reflected back to the hydrophones they will arrive later than waves reflected from upper horizons.
The hydrophones therefore detect ‘bundles’ of seismic waves arriving at different times because they have travelled by different routes through the rock sequence. Computer processing allows the amalgamation of recordings from all the shot points, filtering out unwanted signals of various sorts. The final result is a two-dimensional (2-D) seismic section. By using closely spaced survey lines or hydrophones arranged in a grid it is possible to produce 3-D seismic datasets. These are usually interpreted on a PC workstation and colours are normally used to enhance the image and aid interpretation. The data can be viewed in any orientation in order to create a 3-D visualisation of selected horizons (Figure 7).
Figure 7: A 3-D view of the Palaeocene reservoir in the Nelson Field, North Sea. The image is derived from a ‘cube’ of closely spaced 3-D seismic data, onto which the paths of the production wells are superimposed. Bright colours in this perspective view relate to depths to a particular reflecting boundary. Reds and greens are structurally highest, where petroleum may be trapped.
Seismic data of all forms (2-D or 3-D) are displayed with the horizontal axis indicating geographic orientation and distance, whereas the vertical axis is calibrated in time. The time, measured in seconds, records how long it took the seismic wave to travel from shot to reflector and then back to the hydrophone, so it is described as two-way travel time (TWT). Further processing and the incorporation of seismic velocity data allows TWT to be converted into depth. Depth-converted seismic data is the mainstay of exploration since it provides a meaningful basis for all subsequent interpretation.
What would happen to seismic waves if there was a strongly reflective layer, such as an igneous sill or salt body, in the shallow subsurface?
It would tend to reflect most of the seismic waves back towards the surface and reduce the quality of seismic imaging beneath it.
Interpreting seismic sections is something of a ‘black art’, requiring both experience and a certain amount of interpretative flair. At the outset, interpretation involves tracing continuous reflectors on 2-D sections in order to build up a plausible structural representation of the subsurface. In the context of an initial exploration programme to find possible traps this is often sufficient.
Look at the 2-D seismic section in Figure 8. Even though it was produced to explore for coal seams it contains lots of information that might help the petroleum explorationist. What kinds of trap shown in Figure 4 might be present in that section?
Figure 8: An example of a seismic section. The (vertical) arrival time axis in milliseconds (ms) is roughly equivalent to increasing depth. Towards the top of the section a pair of dark lines indicate major coal seams. They are displaced by a fault near the centre of the traverse (marked by the dashed red line). Many other features show up, including greater complexity in the deeper part of the section, and towards the left of the section deep, more steeply dipping reflectors are truncated by the simpler ones at shallower depths: this is an unconformity (solid blue line).
The unconformity might have associated combination traps (E on Figure 4). There is a large anticline at lower left (see C on Figure 4), and reservoir rocks might be in contact with seals along the fault (C on Figure 4) that extends vertically downwards in the centre of the seismic section.
Good quality 3-D seismic data provides sufficiently fine resolution for exhaustive processing and analysis to help in managing and developing known oilfields (Box 2).
Box 2: Applications of 3-D seismic data
Modern 3-D seismic data can be used for many purposes other than simply defining trap geometry. Sometimes it is possible to identify the presence of petroleum directly, particularly dispersed gas which tends to dissipate seismic waves and produce an ill-defined ‘shadow zone’ above a leaking trap. The changes in acoustic properties across a gas–water or gas–oil contact may also be detected as a horizontal reflector that conforms to the geometry of the trap.
More commonly, however, seismic data are used to map rock characteristics at a variety of scales. Starting with the recognition of distinctive reflector geometries and seismic sequences, and then by applying a range of seismic techniques, depositional environments can be mapped over a very wide area. As drilling progresses and data on rock properties (such as seismic velocity and density) become available, increasingly sophisticated reservoir descriptions can be developed. These commonly include an assessment of lithology, the amount of petroleum that is present, fluid type and porosity.
Interpretation of 3-D seismic data is an enormously varied and rapidly developing area of petroleum exploration that is beyond the scope of this unit.
Seismic technology has been transformed since the 1980s. Today, 3-D seismic, rather than single 2-D sections, are routinely used for exploration purposes in offshore environments because the data can now be acquired quickly and cheaply. New processing techniques and improved computerised visualisation tools add clarity to the data, helping to provide an unparalleled impression of the subsurface. The emphasis in exploration is to reduce the risk of drilling a dry hole and wasting a great deal of investment. This can only be achieved by integrating all the appropriate types of data, and with thoughtful analysis.
3.1.4 Exploration drilling
When seismic data highlight a suitable prospect, the next step is to drill into the reservoir in order to establish whether or not petroleum is trapped, and, if it is, to establish how large the accumulation might be. There are several types of drilling rig, ranging from relatively small ones as deployed on land (Figure 9a) that can be dismantled and transported by truck or helicopter, to large offshore units (Figures 9b–d) that are capable of working in a range of water depths and sea conditions. An offshore jack-up rig is a barge with lattice steel legs that can be raised and lowered (Figure 9b). It is towed into position by tugs and its legs are lowered to the seabed before the barge is raised 10–30 m out of the water to create a stable drilling platform. They usually operate in water depths up to 200 m.
Drilling in greater water depths requires a floating unit and the semi-submersible rig is the most common and versatile type (Figure 9c). The working platform is supported on vertical columns that are attached to submerged pontoons. Once in position, the rig is anchored to the seabed and the pontoons are flooded with water to submerge them beneath wave level. The lower the pontoons are beneath the water, the less likely they are to be affected by wave action. This makes them stable in rough seas. Some semi-submersible rigs have computer-controlled positioning propellers, rather than anchors, to keep them in position and they can be used in water depths down to 1000 m or more.
Figure 9: Mobile drilling units can operate on land (a) or in a variety of water depths. Jack-up rigs at rear and front right in (b) are used in water up to 200 m deep, whilst semi-submersible rigs foreground in (b) and (c) and drill ships (d) can operate in much deeper water.
Drill ships resemble conventional ships and they can move easily around the world (Figure 9d). They too have dynamic positioning that allows them to stay on location with remarkable accuracy in all but the most severe storms. Since they are not ballasted they can be unstable in high seas but their advantage is that they can drill in water depths in excess of 2000 m.
What type of rig would be used to drill in the Amazonian rainforest and what preparation would be required before drilling commenced?
Components of a land rig could be taken into the rainforest by river boats or helicopters and assembled on site. Before that process began it would be essential to survey the drilling site, determine the best access route, clear the site sensitively and safeguard local water supplies from any risk of contamination. In ecologically sensitive areas the cost of site preparation and restoration may exceed the drilling costs.
Drilling for oil and gas is a sophisticated and very expensive process. Wells often penetrate over 3000 m into sedimentary rock; the deepest exceed 6500 m. At such depths the fluid pressures in the rock formations are so high that a dense drilling mud is continuously pumped into the borehole to counter-balance the pressure. This significantly reduces the possibility of an uncontrolled surge of petroleum to the surface, a situation that is graphically described as a ‘blowout’. The enduring image of rig workers celebrating beneath a gushing fountain of crude oil in the pioneer days of exploration distorts reality, since blowouts and the release of associated toxic gases such as hydrogen sulphide (H2S) are very dangerous. Every modern well is fitted with hydraulic rams that instantly isolate the borehole if excess pressures cause the well to flow. The other useful functions of drilling mud are to lubricate and cool the drill bit, to circulate rock fragments (cuttings) back to the surface and, in some cases, to power a turbine that rotates the drill bit.
3.1.5 Well evaluation
To some extent, well evaluation is similar to evaluation of coalfields. Traditionally an exploration well is evaluated at discrete stages by withdrawing the drill bit, lowering instruments (colloquially known as ‘tools’) down the hole on a steel cable and then hauling them slowly back to surface. This process is known in the petroleum industry as wireline logging. As the tools are withdrawn they record the properties of the rocks that surround the well and the fluids in them. Nowadays this approach is supplemented by measurements that are made while drilling is in progress, which has the advantages of providing near instantaneous data and incurs none of the expense of halting the drilling process.
The rock properties that are of interest include those used for identifying lithologies and small-scale structural or sedimentological features. Other tools help estimate porosity, permeability, pressure and fluid content. None provide a completely definitive description of the borehole wall, but in combination the data acquired by wireline logging provide sufficient information to determine whether further evaluation is justified.
The most useful geological data are derived from pieces of rock recovered from specific depth intervals. They range in size from small fragments of rock (drill cuttings) produced as the drill bit cuts into rock, to thumb-size and larger (5–15 cm diameter) cores of solid rock that are retrieved with special tools. These provide the basis for a detailed description of the reservoir, although cores may also be taken in mudstones to gain biostratigraphic and/or geochemical information.
Some exploration wells, particularly those that encounter significant volumes of petroleum, justify an extensive evaluation programme that is designed to recover fluid samples from selected intervals down the well. The fluids (oil, gas and water) are captured in situ at reservoir temperature and pressure, and then brought to the surface in a small sealed chamber for analysis. Less commonly, the fluids may be sampled by allowing them to flow to the surface. Such well testing may continue for several days. During that time it is possible to draw some preliminary conclusions about the nature of the reservoir, flow rates and the commercial potential of the petroleum accumulation.
Exploration is an expensive activity that can quickly lead to ‘gambler's ruin’ – betting more money than you win – unless there is a proper understanding of risk and potential reward. At the outset it is vital to decide where not to explore. List some of the fundamental geological, technical and commercial factors that you might use to reject certain parts of the world from exploration.
Source rocks only develop in sedimentary basins within continental crust, so areas formed by oceanic crust or crystalline rocks should be avoided. Remote regions (e.g. Antarctica) and inaccessible sedimentary basins (e.g. those beneath thick piles of lava or mountainous terrain) will inevitably be very expensive to explore. Some countries may be rejected for political or humanitarian reasons. It is salutary to remember that more than half of the world's countries produce no oil.