The End of The Last Run ?
Over the last couple of weeks there have been several significant events that will change the course of the pandemic and the future of the US. What better time therefore to consider something less significant globally, but (nearly) as significant personally.
The future of borehole seismic. Does it have one?
I think so, however, what it will look like, and in which domains will it flourish, I think will change. It goes without saying that this is a personal opinion, but I hope it will perhaps provoke some discussion and thought on what, if anything, can be done to breathe new life into a technology which, with a few notable exceptions, has stagnated somewhat in recent years as a wholesale exploration tool.
Historically, traditional VSP work has taken place at the end of the logging program, ‘The Last Run’. Consequently, it was the service most likely to be cut, due to pressure on rig time, or budget constraints. Many, many times over the years, and, much to the annoyance of many a service company operations manager, did I have to explain why, despite many months of planning, the VSP had been cancelled at the last minute.
Borehole seismic technology includes all varieties of VSP, using downhole receivers and an active surface source, as well as downhole microseismic monitoring, using downhole receivers and passive downhole sources created by hydraulic fracturing.
Borehole seismic is not as popular as it once was, but the demise of borehole seismic has been overstated and requires a closer look.
In the mid 2000’s service companies shifted attention en masse, both in technology development and sales focus, from VSPs to microseismic monitoring. The reason was obvious; VSPs are acquired in a matter of hours, perhaps a day or two at most, and the associated revenue is proportionate. Microseismic projects however can last weeks if not months, utilizing essentially the same equipment and personnel, the revenues are proportional and significantly higher. The operations managers who had previously scorned borehole seismic suddenly had a new poster child.
In a recent First Break editorial, Peter Rowbotham discusses ‘Whatever happened to VSP’ and presents a fascinating chart showing the number of occurrences of a selected key word search in EarthDoc. Clearly the occurrence of ‘VSP’ flattens at around 2005, coincident with the commercialization of microseismic monitoring. I wonder what the curve for ‘HFM’ or ‘Microseismic’ would look like. I suspect that if they were added to the ‘VSP’ curve then the trend would be upward.
Number of occurrences of selected keyword search in EarthDoc. (Rowbotham, 2020)
There are two main factors which will drive what the future of borehole seismic business might look like.
Firstly, the demand side of the business. Where can it be used to drive production, optimize development efficiency and minimize drilling risks. Clearly the oil (and gas) patch will continue to be an area where the technology is valued both for traditional applications, including unconventionals, and those focused on carbon capture and sequestration and EOR. However, the global energy mix is in the midst of fundamental change, the growth in investment in Geothermal energy in particular in the coming years will provide opportunity aplenty for the use of borehole seismic techniques.
Secondly, how the industry (service companies, operators and academia) react to what type of technologywould be needed to satisfy the demand side will ultimately shape the future of the business.
So, let’s look first at the geographical areas where demand will grow and the increasing variety of domains where it might be relevant.
There is no doubt that for straight up exploration plays, such as the Guyana-Suriname basin, there is a need for seismic well control which only the VSP can provide and such frontier areas will continue to provide opportunities in the future. Deep water exploration wells in the Gulf of Mexico (GoM), and in the Pre Salt offshore Brazil will also continue to require well seismic calibration. The cost benefit in these high stakes wells is clear, and the ongoing challenge is mainly one of continued improvement in operational efficiency aligned with a continued focus on safety.
For offshore development areas there is increasing recognition, that the improved resolution that borehole seismic can provide, has a direct impact on well placement, landing depth and ultimately on field performance. Joy et al (2018) describe the business value of 3D VSPs for improved imaging at Thunderhorse in the GoM.
The VSP (top) detected sand deeper than the Pink 6.5LL
reflection in the (lower) surface seismic data. The VSP was very useful
for calling hole section TD. (Joy et al, 2018)
The future of VSPs onshore is more challenging, there is far greater well control and the value proposition is harder, but not impossible. Operators invest significant amounts of money every year in newly acquired or reprocessed surface seismic. Simultaneous or independent acquisition of VSP data (including offset data) can be used in the processing of this surface seismic to improve bandwidth, confirm seismic well ties and phase control and reduce the impact of multiples in the data. It can also be used to determine local anisotropy and to calibrate AVO effects.
In the unconventional shale plays it is my belief that downhole microseismic monitoring is here to stay. As monitoring technology evolves, the ability to describe the near and far field, fluid and proppant distributions, from a combination of high and low frequency measurements, is invaluable. Long term permanent monitoring of whole pads will make a considerable contribution to the understanding of parent-child interactions.
Carbon sequestration, and surrounding regulation, is an area where the demand for robust, high resolution, far field imaging techniques will grow. As major energy producers strive for ‘net zero’, carbon capture and storage is a critical component of that goal. For example, in a recent online JPT article, Brian Owens, the senior vice president of Oxy’s US Rockies business unit, describes the “Midwest CO2 Superhighway” that will take CO2 from a mix of industrial plants in the interior US and move it hundreds of miles south to aging oil fields in the Permian Basin where EOR infrastructure already exists. (Jacobs, 2020).
Whether as standalone imaging methods or in conjunction with surface deployed monitoring solutions, downhole sources and receiver systems can directly monitor CO2 migration and make a positive contribution to these ambitious goals.
Perhaps the most exciting areas where there is likely to be a growing demand for borehole seismic services is in Geothermal energy. Conventional geothermal energy is generated from a deep well producing hot water turning to steam which powers a turbine and generator, the cold water it then reinjected. The location of these wells with respect to landing depth, local faulting and the presence of natural fractures are all familiar objectives which can be addressed in part by high resolution borehole seismic. This becomes more important for more recent geothermal applications such as the James-Joyce design from Eavor Technologies Inc. from Calgary. I really wanted to mention this is as it is named after a local pub that used to be a particular favorite and serves wonderful Guinness. The design looks a little like the unconventional pad layouts we are used to but consists of 8-12 closed loop wells.
An overarching conclusion from the future demands for borehole seismic described above is that the complexity and technical challenges of such projects will continue to increase. With that in mind, what technology advancements in the coming years need to be made to satisfy these demands.
Let’s cut to the chase, TFIF. “The Future Is Fiber”. Not the whole future, but a large part of it. Distributed acoustic sensing (DAS) measuring uniaxial strain changes in fiber optic cable over a broad range of frequencies, is in the process of revolutionizing borehole seismic; including VSPs and microseismic monitoring. In addition, the fiber optic interrogators used to record DAS are able to simultaneously conduct distributed temperature sensing (DTS).
DAS for borehole seismic has one major advantages over geophone arrays. The whole length of the fiber is the sensor, making it comparable to a geophone array of hundreds if not thousands of receivers. Furthermore, the full length of the fiber can record seismic source data (passive or active) simultaneously. The impact of this is that a VSP can potentially be recorded in the complete well in a matter of minutes using a minimal number of seismic shots compared to traditional VSP surveys. The output channel spacing can be selected in conjunction with the gauge length, the length of cable over which the change in strain is measured.
This significantly reduced rig time and HSE exposure is always important but never more so than for the deepwater frontier wells described above. Of course, whilst this sounds appealing, it is only viable if the fiber is available in the well. Most exploration wells do not have fiber, the alternative is a hybrid wireline logging cable with additional fiber specifically for DAS/DTS. This is appealing because the VSP can potentially be acquired as part of another planned logging run so no more separate seismic runs.
The future challenge for this type of cable is the coupling to the wellbore and the resulting signal to noise of the recorded data. Should the cable be slack in the well or should it be tensioned? Should there be other mechanisms to improve coupling? No doubt service providers are currently working through these challenges and improvements are coming.
Whilst DAS may be the future, it currently has some limitations. DAS measures strain along the fiber optic cable it is therefore comparable to a single component geophone. As the angle of incidence of the incoming energy increases from zero (along the cable), so the response decreases, reaching a minimum (not zero) when the incidence angle is perpendicular to the cable. For zero offset VSPs in vertical wells this is not an issue but can become a concern for walkaway VSPs where incident angles can become large. This is also an issue for locating microseismic events which require three components to provide the azimuthal component of the event location. Currently, with a single component measurement, the same event must be recorded on either two fibers or at different places of the same fiber (heel and lateral).
Can this be overcome? Probably. There have already been attempts to model a fiber helically wrapped on a cable at a pre-determined angle to simulate a three-component response (Wuestefeld et al, 2019). Perhaps the answer is three fibers; one inline and two helically wrapped at 90 degrees to one another. They can sort it out in processing!
Another challenge with DAS today is the sensitivity of the cable and the interrogator. Not all cables and interrogators are the same. I am not going to get into that, but for microseismic applications today, geophone sensitivity is currently still greater than DAS, partly due to being (hopefully) clamped firmly to the casing. This means that the smaller microseismic events (of which there are many more), and the larger but more distant events are not recorded with DAS. Again, I have no doubt that this will improve over time.
There is more to consider than just downhole receiver technology. On the seismic source side development will need to continue.
Marine vibrators have long been talked about and have much to offer; less environmental impact than airguns (lower sound pressure and exposure levels), low frequency potential and flexible source geometry potential. One of their main challenges has been the practical issue of a towed moving source emitting a long-swept signal that required longer records than airguns for each shot and more processing efforts after acquisition.Development has been slow in the last five years due to the lack of research investment. I am sure however that there will be renewed interest in this, and who knows, we may soon be able to deploy a number of such sources on marine remote operated vehicles !
Downhole source development has somewhat stalled in recent years however it is encouraging to see acknowledgment that for the extreme temperature demands of geothermal wells there is some ongoing work (Paulsson, 2019).
For all the advancements in acquisition technology there will only be a meaningful future for borehole seismic if the processing can deliver the timely and robust answer products required by the operating companies. Cloud computing coupled with machine learning offers the potential for real time results for even the most data heavy DAS surveys. If real time DAS 3D-VSP image results could be available in a client’s office do you think the future of borehole seismic is bright? I do. Similarly, for microseismic data, whilst we have made progress in improving consistency between real time results and post-acquisition processing results, changes still occur. When the day comes, and it will, that single well DAS microseismic can deliver constrained hypocenters and moment tensors in real time within a clients calibrated 3D mechanical earth model, do you think that the future of borehole seismic is brighter still? I do.
The future is bright, the future is fiber.
References
Trent Jacobs, JPT Digital Editor. “CO2 EOR Could Be Industry’s Key to a Sustainable Future or Its Biggest Missed Opportunity”. Volume 72, Issue 11, 1 November 2020
Corey Joy, Anya Reitz, and Ken Hartman, (2018), "Business impacts of a record-breaking 3D VSP at the Thunder Horse South Field, Gulf of Mexico," SEG Technical Program Expanded Abstracts: 5402-5406.
Peter Rowbotham, “Whatever happened to VSP” First Break, Volume 38, November 2020, p103.
Bjorn Paulsson, (2019), " A Fiber Optic Single Well Seismic System for Geothermal Reservoir Imaging & Monitoring”, 44th Workshop on Geothermal Reservoir Engineering Stanford University, Stanford, California, February 11-13, 2019
Andreas Wuestefeld and Matt Wilks, (2019), "How to twist and turn a fiber: Performance modeling for optimal DAS acquisitions," The Leading Edge 38: 226–231.