Can seismic detect oil and gas?
Direct hydrocarbon identification has progressed; but it’s still possible to drill duster in northern Alaska; 4-D shows promise
June 20, 2007, marked the 30th anniversary of the first barrels of North Slope crude flowing down the 800-mile trans-Alaska oil pipeline from Prudhoe Bay to Valdez. Looking back, it is clear that the role of technology has been paramount in the progress operators and contractors have made in improving the efficiency and lessening the impact of their operations on the Arctic environment. In a series of seven articles, Petroleum News will report on some of the technologies developed by the dedicated and innovative men and women who work on the North Slope. These articles will be followed by “30 Strong,” a full color magazine celebrating three decades of North Slope oil production.
Drilling a wildcat exploration well has always been a risky proposition. And even drilling a well within a known oil field involves some level of uncertainty about what is under the ground. But advances in seismic surveying and data processing over the past few decades have refined the identification of what geophysicists call “direct hydrocarbon indicators” to a point where that drilling risk may at least be reduced, given an appropriate geologic situation.
In a seismic survey, sound waves from a sound source partially reflect off boundaries between different underground strata, to form echoes that are detected at the surface by receivers called geophones. Those echoes provide information about the subsurface geology, including the locations of potential oil and gas traps.
But it’s long been know that oil and gas occupying rock pores in an oilfield reservoir affect the physical properties of the rock in a way that could alter those sound echoes and thus provide direct evidence of subsurface oil and gas pools.
Detects gasIn particular, a quite modest amount of natural gas inside a rock will significantly reduce the velocity of sound passing through the rock. That velocity reduction can increase the acoustic contrast between the gas-bearing rock and the adjacent rock formations. And the increased contrast can in turn cause an abnormally high amplitude seismic reflection, giving rise to what geophysicists refer to as a “bright spot” in a seismic section.
The relatively low velocity of sound through the gas-bearing rock also causes strata underneath that rock to appear deeper underground that they actually are. That effect results in an apparent down warping of the lower strata in a seismic section, something that geophysicists call “push down.”
For example, a near-vertical column of pushed down seismic reflections often indicates the presence of a gas chimney, a vertical zone in which natural gas bubbles upwards through the strata from a source that is deep underground.
Because, however, there can be more than one possible explanation for a seismic phenomenon such as a bright spot, this type of indicator suggests but does not prove the existence of subsurface hydrocarbons.
And things become much more difficult when trying to use seismic data to detect oil. Oil has a much lower acoustic contrast with rock than does gas. And, to make things even more tricky, there’s quite a low acoustic contrast between oil and water, thus making these two liquids difficult to distinguish.
When analyzing exploration seismic data people have a much better chance of saying whether there’s gas or a liquid underground, rather than oil versus water, Michael Faust, offshore exploration manager for ConocoPhillips Alaska, explained.
Over the years, increased seismic resolution and an improved ability to extract unwanted noise from seismic data have improved geophysicists’ ability to locate possible hydrocarbon indicating anomalies in the seismic data. But in Alaska, the high acoustic contrast between reservoir rocks and the surrounding rock formations in the relatively old, deeply buried reservoirs of fields such as Prudhoe Bay and Kuparuk has severely limited the use of hydrocarbon detection techniques — that high contrast simply swamps the subtle acoustic contrasts caused by the presence of hydrocarbons, Tom Walsh, principal partner and manager of Petrotechnical Resources of Alaska, told Petroleum News.
Walsh thinks that the hydrocarbon detection techniques will prove more valuable in the younger and shallower Brookian horizons that have become an exploration focus in the past few years. The difference between the acoustic properties of shales and sands is not as big in the Brookian as it is in the older rocks, so any change in fluid properties will likely have an impact, Walsh said.
AVOHowever, a modern seismic technique known as amplitude variation with offset, or AVO, has seen some use in Alaska for delineating subsurface oil and gas reservoirs.
AVO is a bi-product of the way in which a seismic survey involves recording underground sound reflections using sound sources and geophone sound detectors in a series of increasing offsets from a single survey point. Seismic surveyors record the data from different offsets so that they can add the data together. This addition tends to remove random noise while enhancing coherent signals from underground sound reflections.
However, geophysicists have discovered that by examining how the amplitudes of the signals from a single subsurface reflection point vary with those increasing recording offsets, it is possible to obtain insights into the subsurface geology. In fact, surveyors now tend to use larger geophone offsets than they used to, to enable this type of AVO analysis.
And, as with other aspects of modern seismic analysis, interpreters can view computer graphics of the AVO data, to gain subtle insights into the underground geology.
“The difference between what you see on the close receivers and the far receivers … changes with the type of fluid you have in the ground and the type of rock present,” Faust said.
Walsh said that AVO analysis essentially enables an assessment of the porosity of underground rocks. For example, analysts might perform an AVO analysis on an unproven section of a known field pay zone, to test for adequate porosity and thus reduce the risk level associated with reservoir development.
4-D seismicAnother technique with the potential to detect underground hydrocarbons, at least in the context of an operational oil field, is known as 4-D seismic. This technique involves shooting several 3-D seismic surveys over the same area over a time period of perhaps several years (a 3-D survey is a type of survey that results in a three-dimensional image of the subsurface geology). Changes in seismic signals from one survey to the next can provide insights into the movement of fluids such as oil and gas within the field reservoir.
As a technique, 4-D seismic is still relatively young, although results so far show promise.
“It’s going to be huge as far as economics goes, because then you’re looking for unswept oil, changes in gas caps, watching waterflood movements,” Jon Anderson, chief geophysicist, exploration and land for ConocoPhillips, told Petroleum News.
Because changes over time in the seismic signals can result from a variety of causes, such as the chemical alteration of the rocks or subsurface pressure changes, the linking of the seismic data to field reservoir data forms a critical component of 4-D analysis, Anderson said. But given that linkage, it is possible to use 4-D seismic to test predictions that reservoir engineers make about reservoir fluid movements in response to field production.
“That’s the beauty of 4-D,” Anderson said. “You know that the fluids are there and you know they’re moving and you integrate that with all the reservoir information.”
Detecting fluid movements using 4-D surveying has proved particularly successful in offshore oil fields, where surface conditions remain relatively constant from one survey to the next. But onshore 4-D surveying is still in its infancy and has yet to be fully proven to work, Jon Konkler, senior development geophysicist for BP Exploration (Alaska) told Petroleum News.
“The North Slope is one of those places where we’ve started investigating, does it work?” Konkler said. “… We’ve got a couple of places where we’ve overlain successive surveys and we’re in the process of evaluating — can we see the fluid movements and, if we can, how do we use that?”
4-D surveys have been done in both the Prudhoe Bay and Kuparuk fields, Anderson said.
Konkler sees the use of 4-D surveys as a “game changer” in the use of seismic data, with the possibility of assessing fluid saturation volumes rather than just structure volumes in a field reservoir.
“This really is a different way of looking at things,” Konkler said.
Gas hydratesAlthough people are far from determining whether the vast deposits of gas hydrates that underlie parts of the North Slope can ever form a viable source of natural gas, the use of seismic techniques to directly detect the hydrates is proving to be one of the particularly useful outcomes of a multi-year gas industry, government and university gas hydrate research program on the slope. Gas hydrate consists of a white crystalline substance that concentrates natural gas by trapping methane molecules inside a lattice of water molecules at certain pressures and temperatures.
The seismic detection of gas hydrates works in a similar manner to that of natural gas, in that the hydrates tend to cause amplitude anomalies in the seismic signals. However, gas hydrate has a relatively high sound velocity, as opposed to the low velocity of gas. So, the presence of hydrates tends to pull up the seismic reflections, rather than push them down.
A gas hydrate stratigraphic test well at Milne Point on the North Slope in February 2007, drilled by BP as part of the gas hydrate research program, verified the effectiveness of seismic gas hydrate detection techniques.
And Walsh sees the potential for increasing use of this type of seismic direct detection technique in Alaska for detecting shallow gas deposits.
“We’re looking shallower and shallower and how to directly detect these hydrates and coalbed methane deposits,” Walsh said.