Andrew McBarnet speculates whether evolving microseismic monitoring technology being harnessed for the US onshore shale gas revolution could end up offshore.
The rapid development of US onshore shale gas must count as the most stunning turnaround ever in the country's energy prospects. Looming scarcity of natural gas five years ago has changed into today's over-abundance which is actually threatening to curb the enthusiasm of oil companies from making further investments. Not surprisingly many countries are now scrambling to assess their shale gas potential.
But even a nation like Poland, which is eyeing a sudden windfall of natural gas to boost its economy and loosen its energy dependence on Russian supplies, is having to proceed with some caution, notwithstanding the acreage already taken in anticipation of a bonanza by major companies such as Chevron, Marathon, Exxon Mobil, Conoco Phillips and Eni.
This is because there is a widely held suspicion of the hydraulic fracturing process at the heart of the shale gas production method.
In essence hydraulic fracturing involves pumping large volumes of water, sand and chemicals (proppants) into horizontally drilled wells thousands of feet below the surface in order to crack the rock and free the flow of gas. Fears (largely unfounded on the experience so far) expressed about the environmental impact, for example mini-earthquakes, and the potential threat of contamination to public water supplies in aquifers and the like, have prompted a number of governments, including France quite recently, to ban any fracking operations and thus shale gas development until the whole method is better understood. At the EU level, there have been calls for a regulatory framework opening the door to a potentially long and most likely fractious debate.
In the circumstances you would imagine that it is perhaps too early to be thinking of taking the technology offshore. That's not how they see it at Houston-based MicroSeismic, a company founded in 2003 which a few years ago struggled to put together $7 million development money.
But all that has changed.
Last year the company won a number of technology innovation awards, raised more than $100 million from investors no sweat and just for good measure repelled acquisition overtures from a major oil services company – no guesses which. Backlog in the company's third quarter was up 86% at $41 million.
MicroSeismic's founder and executive chairman Peter Duncan, a Canadian geophysicist with a PhD from the University of Toronto, has already been honoured for his achievements by his professional peers in the Society of Exploration Geophysicists, Canadian Society of Geophysicists and the European Association of Geoscientists & Engineers, recognition of the original direction which the company is taking.
By his own account Duncan had a struggle to persuade the folks in Houston that fracking operations were susceptible to what he suggested, namely be mapped and monitored in real-time across an entire reservoir at a fraction of the cost of conventional methods. It was an idea he came to from making the connection with the passive seismic recording techniques used for the monitoring of earthquakes.
Downhole alternative
The key to the MicroSeismic approach is that it offers an alternative to using downhole monitoring tools for fracking jobs, instead deploying hundreds or thousands of seismic recorders on the surface or near surface.
The basic operation in the recovery of shale gas normally involves the drilling of a horizontal well as long as 3000m into the target low matrix permeability rock. This is followed by injection under high pressure of a mixture of proppant, such as sand, and water into the cracks of subsurface rock to widen the fissures so that gas can escape out of the formation and into the well bore, from where it can be extracted.
For the operator, it is vital to track the impact of the fracking in order to plan the next step in the gas extraction process. Until MicroSeismic came along the only option was to drill a monitoring well to record data from the well being stimulated. These wells are invasive and expensive, costing some $2-4 million each, and there are temperature restrictions on the tools that can be placed in a well. In addition the recording instruments can only map a relatively small area around the monitoring well. In other words, reservoir engineers do not have the full picture of where the fractures are occurring, and this hampers their ability to optimize completion and production strategies for the whole reservoir.
Duncan uses his favourite medical analogy to describe his company's monitoring solution. ‘We are like doctors putting a stethoscope on a patient's chest. In our case the reservoir is the patient, and we listen for the almost imperceptible low-energy MicroSeismic events that take place during drilling, stimulation, or production. We then diagnose what these events mean so that reservoir engineers can take immediate steps to maintain the health of the production process.'
In the US shale plays, MicroSeismic has implemented nearly 130 applications of its passive seismic removable FracStar system which deploys a hub and spoke pattern on the surface to monitor long laterals and pad drilling over a large area. There have been around 30 BuriedArray systems deployed to date for long term monitoring. Both methods in effect create a large parabolic dish microphone that can detect multiple MicroSeismic events over an entire field, so effective that companies are gradually appreciating that monitoring wells are an unnecessary expense.
To give an idea of scale, the largest BuriedArray system, which is a continuing multi-million contract for Whiting Petroleum in the Bakken and Three Forks play in the Sanish Field, North Dakota, has 295 monitoring stations covering 152 square miles, each station having four geophones buried at 300, 250, 200 and 150ft depths. A local field office receives real-time data which is transmitted to a processing centre in Denver.
Spot GraphThere is of course a processing trick involved in all this. MicroSeismic's Passive Seismic Emission Tomography (PSET) mapping and analysis technology links individual geophones together and serves as a focusing algorithm so that the location of MicroSeismic events can be identified across a field with a high degree of accuracy. In the process it overcomes the issue of signal attenuation by the overburden which makes conventional seismological earthquake location techniques ineffective. With PSET it is possible to use the dense array of geophones to ‘beam steer' or sum the output of the entire array to detect and locate the MicroSeismic activity deep below the earth's surface.
The benefit of the permanent monitoring systems are potentially substantial and extend beyond the mapping and monitoring of fracking operations. The sytems should help operators to see large reservoir areas from a single installation, capture data from weaker MicroSeismic events extending detectability, measure pressure and stress changes, detect physical property changes in the reservoir as fluids move and are replaced, optimize depletion plans, find bypassed zones and see changes in both the overburden and underlying formations.
Duncan and his colleagues have already begun thinking about monitoring lots of other operations such as oil sands in Canada, CO2 storage, mining and geothermal operations. But a major prize may lie in offshore applications as a production optimisation tool, particularly if hydraulic fracking ever becomes a reality offshore. Up to now there have only been limited feasibility tests for fracking offshore and nothing approaching commercial operation, but this may well change sooner than we expect.
An internal MicroSeismic document authored by Mike Mueller, MicroSeismic's VP analysis, and Jerry Beaudoin, an industry consultant on offshore seismic technology takes as its starting point the potential requirement in the Gulf of Mexico for hydraulic fracking as one of the production boosting technologies for the tight reservoirs in the Paleogene Play. When plotted against reservoir depth two Paleogene (Wilcox) trends are apparent. Alaminos Canyon discoveries exhibit shallower reservoir depths. The Walker Ridge and Keathley Canyon discoveries are all at depths greater than 24,000ft and are where most of the recent activity has been focused.
A comparison of reservoir properties suggests that not all Paleogene (Wilcox) reservoirs are tight. However the tight (average permeability of 15md) reservoirs of the Walker Ridge and Keathley Canyon protraction areas are estimated to hold about 86% of the estimated 25 billion barrels original oil in place (OOIP), estimated by the Research Partnership to Secure Energy for America (RPSEA) report IOR for Deepwater Gulf of Mexico published in 2010. So far some 17 discoveries have been made in the Paleogene Play of which only Baha and Tiger are considered non-commercial.
The RPEA report listed hydraulic fracking as a contender in the list of potential technologies which could optimise production in the Paleogene, suggesting a 4% recovery factor increase which translates into at least an additional billion barrels of reserves. It is of course clear that these same calculations could apply to pre-salt offshore Brazil and presumably some other equivalents around the world. None of which is to underestimate the challenges of fracking offshore in terms of the scale and logistics as well as the high pressures involved in what would be a massive stimulation operation.
Moving offshore
There would be two approaches to installing a continuous, seismic monitoring system for deepwater development, each building on proven MicroSeismic systems in use onshore.
The offshore analogue to FracStar would use an array of autonomous nodes placed on the ocean bottom. Since current battery and communications technology cannot support such a system on a permanent basis, the nodes would have to be deployed and retrieved by ROVs, which of course would preclude real-time recording.
The BuriedArray system analogue offshore would consist of ocean-bottom seismic cables laid out radially or in a fishbone pattern from a wellhead or other subsea installation. Power and communications would come from the wellhead. The cabled array could extend across the entire field or any area that needed monitoring and the installation would be permanent.
Monitoring of fracking offshore may still be some way off, but MicroSeismic has already been working with BP on some very preliminary concepts for MicroSeismic reservoir monitoring using the Life of Field Seismic (LoFS) permanent reservoir monitoring system established since 2003 on the Valhall field, offshore Norway. Microseismic believes that buried cable recording equipment has the potential to be adapted to the specific recording of MicroSeismic data for continuous reservoir monitoring and management purposes. This might mean that the real-time MicroSeismic data could supplement on-demand 4D seismic monitoring surveys over buried ocean bottom cable networks. Current copper wire technology, as used in the Valhall and Clair field LoFS, can supply power and send data. The recently deployed Ekofisk (Norway) and Jubarte (Brazil) permanent monitoring systems employ fibre optic technology, but this is not seen as a major compatibility issue.
Although in the very early stages, using MicroSeismic data as a reservoir management tool fits in perfectly with the digital oilfield vision which has been touted but never quite realised for at least a decade. Combining the acoustic data with other production monitoring data from downhole pressure and flow meters and field-wide acoustic emission information will help to bring the ultimate digital oilfield that bit closer.
However, MicroSeismic reservoir monitoring's most important role could be more to do with well safety and risk management, especially in the aftermath of the Macondo disaster. As we know this was a massive shock to the system, temporarily at least derailing public confidence in the safety standards and environmental responsibility of the oil industry and obliging regulatory authorities worldwide to publicly review their offshore operation requirements.
One indication of what the future may hold in the US at least, and who knows where else, is contained in HR 3534 ‘Consolidated Land, Energy, and Aquatic Resources Act of 2010', passed by the House of Representatives last July. In the Bill, section 727 (Offshore Sensing and Monitoring Systems) appears to require a real-time monitoring system in water depths greater than 500ft capable of operating for at least 25 years, providing alerts in the event of anomalous circumstances, providing docking bases to accommodate spatial sensors for remote inspection and monitoring, and secure internet access. This would seem to be straight out of the MicroSeismic playbook describing precisely what its technology could help to achieve as part of a permanent real-time seismic reservoir monitoring system installed at offshore production facilities.
For an embattled offshore industry, the value of continuous, real-time seismic monitoring systems installed for offshore facilities would go beyond the listable benefits as it would provide evidence of implementing additional safety measures into their operations. Upsets at or near the borehole, pipeline and related equipment could potentially be detected and mitigated before they became catastrophic.
Passive seismic monitoring would enable offshore operators to improve the reliability of their operations and help to meet the challenge of a more stringent regulatory environment.
Duncan is realistic about what the future may have in store. ‘We have come a long way since the company started less than 10 years ago and are excited that the oil industry has been convinced to join us on the journey to developing passive monitoring applications.
‘However, moving from onshore to offshore is a big step so it would be unwise to raise expectations. We are also mindful that permanent seismic reservoir monitoring systems have been very slow to win industry acceptance.' OE
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