Technology: Transforming onshore exploration
Friday, March 25, 2011
Many onshore areas have not seen recent exploration using modern technologies, in particular a suite of technologies that can be integrated both to understand geological setting and to choose well locations with precision.
These technologies all exist: the key to unlock the whole will be a step change in our ability to obtain onshore 3D seismic.
This article first appeared in Geoexpro.
By David Bamford, OilEdge
The starting point of exploration thinking is an understanding of the impact of plate tectonics through geological history. Thus mining companies that have successfully explored for minerals onshore along the West African Transform Margin seek analogue deposits onshore in South America where the two regions were juxtaposed before the opening of the South Atlantic. On the other hand, the new frontier of offshore East Africa gas is rooted in the perception that a ?late Jurassic basin may have opened as Madagascar moved away from Africa.
Picture: Global bathymetry and topography.
If this map is overlain with one showing where some 200,000+ exploration wells have been drilled in the last 40-50 years, benefiting from modern technology, one notes that much of the offshore has been explored whereas the ‘white spaces’ are mainly onshore – the northeastern USA, East Siberia, much of mid-continent Africa, and so on.
Offshore, due to the relatively inexpensive nature of marine 3D seismic data, at least as far as multi-client surveys are concerned, it is possible both to reconnoitre and explore a huge area with ‘surgical’ precision. For example, most of the deep water Gulf of Mexico and deep water Angola is covered from ‘corner to corner’ with such 3D, many versions of it in the former case.
Generally speaking, this is not possible onshore due to the prohibitive cost of land (and transition zone) 3D seismic data, and explorers have to recourse to a more traditional ‘focussing’ approach, in which a range of technologies – including the boot on human feet – come into play. The steps in this ‘focussing’ approach can be characterised as: is there any evidence of the components of a viable petroleum system in the region under study; is there any evidence at all of actual hydrocarbons – seeps that can be sampled for example; can suitable, preferably large, structures be envisaged; then, and only then, can 2D, or preferably 3D, seismic delineate prospects?
Surprising as it might be to modern geoscientists, our predecessors in countries such as Iran, Iraq, Kuwait, Saudi Arabia, Russia, the onshore USA did actually get out in the field, in fact they spent most of their time there, they hit rocks with hammers, they plane-tabled, they drew cross sections, and yes, they knew a seep when they saw one and sampled it.
They didn’t spend their life looking at computer screens!
Extensive field work can still answer significant questions during the reconnaissance phase of exploration: can we identify potential source, reservoir and seal rocks; are there any active seeps; following sound principles of structural geology including section balancing, can trapping structures be envisaged at depth?
And technology of course has its pace.
Direct Hydrocarbon Detection
A key step in screening a brand new basin is of course whether a respectable source rock exists and if yes, whether it has matured and hydrocarbons have migrated away from it. Early in onshore exploration, such investigations inevitably focussed on visible seeps – macroseeps perhaps we should call them – that could be sampled and analysed.
In the last 20 years of the 20th Century, this form of direct hydrocarbon detection moved offshore, adopting both ‘high’ technology (satellite SAR)and ‘low’ (looking for seeps out of an airplane window in sun glint, wearing expensive sun glasses). This worked well because any remotely sensed ‘seeps’ or seep-related ‘anomalies’ or ‘phenomena’ could be sampled and fingerprinted with geochemistry. In the early 1990’s, BP ran a study in the Gulf of Mexico where they ground-truthed over 40 surface slicks detected by satellite and from the air, of which 90% turned out to be actively bubbling seeps.
Fertile minds then turned to how technology might then promote this sort of direct hydrocarbon detection onshore: here we need to add the additional concept of microseeps, the notion that in addition to macroseeps, there is a more pervasive background of seepage resulting from one or all of several different vertical migration mechanisms.
Picture: Macroseepage amd microseepage; picture courtesy of Gore Surveys
Picture: Vertical migration mechanisms; picture courtesy of Gore Surveys
The ‘sine qua non’ here is that some of this background seepage is derived from hydrocarbons escaping from reservoirs.
A couple of technologies can be highlighted. The first uses satellite-based remote sensing to search for ‘anomalies’ in soil geochemistry or vegetation that are the results of alteration caused by microseepage. The second uses a novel sampling device, laid out in extensive grid pattern on the ground (or on the water) and directly collecting hydrocarbons over a period (say three weeks or so): the offshore version of this device was reviewed in Geoexpro, November 2010.
Both types of data can then be analysed to show ‘anomalies’ that pop out from the background, the inference being that these are where the microseepage derives from previously reservoired hydrocarbons. Many examples have been shown where these ‘anomalies’ are located above known petroleum accumulations.
Once again, the key to these approaches becoming useful direct hydrocarbon detection methods is geochemical proof that what is being seen is, or is the result of, mature hydrocarbons escaping from a reservoir. Technology moves on of course but I do seem to remember that (in contrast to their offshore experience) BP was unable to so ground-truth any of the onshore ‘anomalies’ they saw around the world.
Full Tensor Gravity Gradiometry
One of the more important breakthroughs of the last few years has been the coming of age of airborne gravity via Full Tensor Gravity Gradiometry (FTG). Put simply, two extremely sensitive gravimeters, one above the other, record all 9 tensor components of the earth’s gravitational field. In comparison with conventional gravimetry, the twin gravimeters allow much of the ‘in-flight’ noise to be removed and this ‘full tensor’ approach allows the source of anomalies to be located relatively precisely in the 3D sub-surface.
Picture: An early version of a full tensor gravimeter; picture courtesy of ArkEx Ltd
Picture: Ready to survey! An FTG airborne platform; picture courtesy of ArkEx Ltd
Thus reasonably precise, reconnaissance phase, 3D images of the sub-surface can be generated and FTG becomes an especially powerful tool when integrated with other geophysical technologies, for example with modest amounts of 2D seismic or perhaps magnetics (especially when ‘depth to basement’ – the depth to the base of the sedimentary pile – is a key deliverable). Obviously this can be used anywhere as a relatively inexpensive early stage exploration tool but it should prove particularly useful in remote or hostile onshore areas; the jungles of Gabon and the Congo would be an example.
Onshore Seismic
However, seismic technology is the main, some would say the only, means of interrogating the sub-surface in sufficient detail to allow insightful geological prediction and the precise location of wells.
So I am going to state quite baldly that onshore exploration technology is miles behind offshore.
Why is this??
The availability of regional or ‘exploration’ 3D has been the main driver of exploration success in Deep Water. Huge swathes of multi-client 3D, covering for example whole 5000 sq kms blocks offshore Angola, are available at prices as low as $3000/sq km, are turned around exceedingly rapidly, and are interpreted at great speed.
The technology drivers have been: highly efficient and effective acquisition systems based on vessels capable of towing many, many streamers and multiple guns; simultaneous processing – to some extent on-board – but mainly via satellite transmission; powerful interpretation workstations, capable of dealing with these vast surveys and delivering both time and attribute-based interpretations.
As an ‘old codger’ I would simply point out that this is an incredible transformation from the days of ‘postage stamp’ surveys in the North Sea that took two years to go from design to delivery of a ‘final’ product…and then interpretation on paper invariably meant that only 1 line in 10 or maybe 5 was fully interpreted!
What is more, very complex geological problems, for example at great depth or beneath salt or basalt, can now be tackled, for example by multi-azimuth, wide-azimuth, wide-angle recording.
Thus, modern 3D lies at the heart of modern offshore exploration, integrating stratigraphy, sedimentology, facies prediction, rock physics, hydrocarbon phase prediction on the regional and prospect scales, and then providing a ‘surgical’ tool for choosing exploration well locations.
It is a fact that such integration is much rarer onshore; 3D seismic plays a much lesser role.
Here’s an example I heard about the other day, namely exploration in the Llanos foreland of Colombia where ‘everybody now explores with 3D seismic’, leading to success rates as high as 75% - pretty remarkable in an onshore environment. The terrain is this area is moderately undulating ‘cow country’ so relatively straightforward for acquiring 3D…..and yet the cost per sq km is roughly an order of magnitude, ten times, that of offshore multi-client 3D…so we are talking $25-30,000 per sq kms.
Step back into the Llanos fold belt itself, and the cost is more like $100,000 per sq km.
Why so? Why these differences? How can we pay so much!
My contention is that onshore seismic has simply not yet seen the acquisition technology breakthrough that transformed offshore 3D over 15 years ago.
As my old friend Ian Jack has pointed out many times, supported by Bob Heath of iSeis, both at Finding Petroleum events, the absolute key is the slow pace and man-power intensive nature of using cables, and that the first breakthrough we seek is the advent of light-weight, long-life, wireless systems.
Picture: Cables and ‘man-hauling’; picture courtesy of Wireless Seismic Inc.
What this means is that, in turn, onshore exploration itself remains untransformed, with the exception of the odd example such as that I have quoted from Colombia, Tullow Oil’s activities in Uganda, one or two others.
I am fully aware that it would be unreasonable to expect onshore 3D seismic prices to drop to the level of offshore multi-client data, largely because onshore seismic crews have to contend with a variety of terrains and topographies and that significant numbers of people will inevitably be involved in deploying onshore seismic equipment.
A better message than a simplistic 'cheaper please!' is that the cost of onshore 3D needs to be at the point where shooting it extensively - so it can be used for regional and prospect work - fits neatly into the 'gradually focussing your onshore exploration' approach.
The implications
Many onshore areas have not seen recent exploration using modern technologies, in particular a suite of technologies that can be integrated both to understand geological setting and to choose well locations with precision.
These technologies all exist: the key to unlock the whole will be a step change in our ability to obtain onshore 3D seismic.
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