INTERVIEW: Distributed Acoustic Sensing - Real-time monitoring throughout the full well lifecycle

INTERVIEW Distributed Acoustic Sensing: Real-time monitoring throughout the full well lifecycle Stuart Large, Product Line Director, Oil & Gas In this week’s interview we talk to Fotech’s Stuart Large - Product Line Director, Oil and Gas - about the safety and efficiency benefits Distributed Acoustic Sensing (DAS) technology can bring to shale gas producers throughout the full lifecycle of wells.

Monica Thomas (Shale Gas International): Fotech is a technology company that allows for advanced monitoring within the oil and gas sector and their flagship product is a Distributed Acoustic Sensor (DAS). Can you, perhaps tell us what this is and what are the applications of DAS technology within the oil and gas sector?

Stuart Large (Fotech): The simplest way to think of Distributed Acoustic Sensing is – it uses a fibreoptic cable which is deployed along the length of the well. DAS effectively turns the cable into tens of thousands of microphones placed along the length of the well. This allows us to listen to events that are occurring along the length of that well. The fibre responds to micro strain resulting from vibrations and noises along its length and the DAS system can interpret these vibrations.

And so, combined with Distributed Temperature Sensing, which is a well-established technology, we are able to use this fibre-optic technology to look at a number of different things occurring in the wellbore. This could be hydraulic fracture monitoring, production profiling, injection profiling, potentially also seismic data acquisition, well integrity, and sand production. Well integrity covers damage to cement – so we’re looking for leaks on the outside of the casing, as well as issues with the casing itself.

MT: Why were fibre-optics chosen for this type of task, rather than electronic solutions?

Is it because they are better suited to withstand the harsh conditions in the wellbore or where there also other considerations?

SL: One of the main benefits of having a fibre is that it is able to look at the entire length of the well simultaneously. And also we are taking thousands of samples every second, and so we are able to

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monitor for a period of time and see the changes in the wellbore at any point along its length.

To compare it with wireline logging, for example, the wireline logging tools are a set of sensors that will be at one place in the wellbore at a given point in time, and we know that the conditions in the wellbore fluctuate. Particularly when you look at production monitoring, for example, you may find that a particular perforation or fracture is producing hydrocarbons for a period of time – maybe half an hour – and then it can stop and produce nothing for maybe an hour, and then it can come back again.

In this case, when you are logging with wireline logging tools, you either are seeing that perforation producing, or you are there at the time when it is quiet – and it’s impossible to know which. Whereas with fibre we are monitoring all the time and we can see those variations.

If we’re looking for a leak in the casing, or cement, again – these things can fluctuate. They may be sporadic events. So we can watch for a number of minutes or hours, we can locate a potential leak and then if somebody wants to diagnose that in more detail with wireline logging tools, we can direct them as to which tools to use and where to place those tools in the well to diagnose the issue more closely.

MT: So, as opposed to the alternative, DAS offers ongoing monitoring capabilities?

SL: That’s right. The fact that we have the fibre on the whole length of the well means that we are able to monitor for as long as we choose.

It is also worth understanding that the fibre can be put into a well in a number of different ways.

It can be permanently installed, which means that it’s strapped to the casing and cemented in during well completion, or it can be deployed into the well at some point during the life of the well – sometimes for just a few hours – by deploying a carbon rod or a slick-line, or coil tubing. It also can be attached to the completion string if we’re talking about a frack job.

MT: Am I correct in thinking that DAS can be deployed throughout the lifecycle of the well?

SL: Yes, that’s one of the key points – it’s throughout the life of the well. So when I think about the jobs that we are doing in the U.S. right now, we’re installing the fibre initially for the purposes of hydraulic fracturing monitoring. When the fracking happens, we will be monitoring that job. We will then monitor warm-back and flow-back – as the well comes online. And then we can go back and look at the well at regular intervals of three months, six months, a year, and look at how the well performance is changing.

Using the data we have collected on well performance over time, we can define when and how we might re-frack the well in the future. Then, of course, we can monitor that re-frack. And also, through the life of that well we can use the fibre to run a VSP job, and collect seismic information. And lastly,

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we could be monitoring for well integrity issues to see if there are any issues with cement or with the casing that develop over time.

MT: You mentioned hydraulic fracturing. Can you give examples of how the results of DAS monitoring would alter the hydraulic fracturing process?

SL: First of all, we are able to track the wireline logging equipment that goes into the well. So as the perforating guns, or the devices to set the packers, are put into the well, we can check that they are on depth, we can check that the packer is set properly and that the guns fire. There have been instances when the wireline company thinks they’ve fired the gun, but actually we can see that they haven’t.

If we’re talking about a traditional cement and perf frack job, then when fracture balls are dropped into the well, we are able to check that they seat on the right packer. We have seen on occasion when balls are, perhaps, the wrong size, or they fail, and in fact they are blown through the packer at the end of the intended frack stage and leave the wellbore open in the previous frack-stage and so the client would end up effectively re-fracturing the last stage, rather than fracking the new, intended, stage.

The client would ordinarily have very little indication of this. They might see a kick with pressuregauges at the surface, but other than that they don’t know where the frack fluid is going. Whereas we are able to see, and alert them to the fact that they are fracking the wrong stage. Assuming that the frack ball does seat in the right stage and the perforation gun has been fired and we start fracking, we then are able to look at a number of things.

First of all, we are quite interested in what happens with the cement during the fracking process because inevitably with the high pressures and flow rates involved damage can be done to cement in the area around the formation, and we are able to see this because the cement fissures opening up occur at a different frequency, and it’s a different acoustic signature, to breaking rock formations.

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And the issue with cement failure is that it can cause small cracks to open up that allows communication down into the previous frack stage and, again, the fluids may end up going into the previous frack, rather than the current one that you’re targeting. And that’s quite common.

Alternatively the cracks can open up a little bit up hole and can damage the cement in the area where the next – or future – frack is intended to be, and we need to know if that’s the case.

Now assuming that there hasn’t been too much damage to the cement, and we’re able to get the fractures away into the formation, we are then able to look at the relative contributions of the fluid and the proppant that go into each cluster. Typically, a fracture stage with have four or five clusters that are being fracked simultaneously. Ideally, One of the main benefits of you would normally want fairly equal quantities having a fibre is that it is able of fluid and proppant to go into each cluster, but to look at the entire length of in reality there tends to be some variation, and the well simultaneously we’re able to see that.

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A typical example that we’ve seen is where a lot of damage is being done to cement, we can see that sometimes it’s difficult to get the actual frack to initiate and propagate into formation. Where we’ve had success in identifying these issues is to bring that to the attention of the clients. We are able to produce data and reports within half an hour of completing a frack stage, and this can influence the design of the next frack stage. And so the client has the opportunity to improve the fracture method for the next stage, and try to do less damage to cement and get the fracture out into the formation. We’ve had a lot of success with that. We’re able to reduce the time for fracking stages and, potentially, to reduce the wastage of fluids and proppant.

MT: So, I understand that there is a safety aspect to the technology and an efficiency aspect to the technology as well?

SL: That’s correct. And another thing that may happen in real time whilst you’re fracking a stage, is that if you see some fissures opening in the cement, and – perhaps – communication to the previous frack stage; fluids flowing through the cement down into the previous fractures, the clients may choose to change their proppant type and be able to pack-off those channels and divert the fluids back into the correct fractures.

If you were talking about a situation involving a re-frack or using diverters, then we’re able to confirm that those diverters are working correctly.

MT: Fibre optic monitoring of oil and gas wells is not unique to Fotech. I read about something called Distributed Temperature Sensors (DTS) that are in widespread use. Can you explain how Fotech’s solution differs from other solutions in the market?

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SL: Distributed Acoustic Sensing (DAS) is a new technology, where DTS has been around for a decade or more. But they are really very different measurements. DTS is to do with very precise measurements of temperature along the fibre, and Distributed Acoustic Sensing is like having microphones along the well. Actually these two technologies complement each other very well and we should run them both together.

For example, if we are production profiling, companies have been trying to use the temperature profile as defined by DTS to produce an injection profile. But if we bring in inputs from Distributed Acoustic Sensing, then that helps you to resolve some of the variables and get a far more accurate production, or injection profile.

MT: Is Distributed Acoustic Sensing a technology unique to the oil and gas industry or does it have other implementations?

SL: DAS is a technology that’s been deployed in other industries for a number of years. It’s been used in linear assets – for example in security fences and pipelines, where you want to detect potential intruders, people or vehicles, or machinery such as diggers, where people would try to break in or do harm to your assets.

It’s the fact that the fibres are one long sensor, which can be deployed for tens of kilometres along these assets, that is important. So it was a natural progression to bring this technology into the oil well.

MT: You mentioned re-fracking, and re-fracking has been in the news recently. Not long ago we reported that Halliburton is spending $500 million on re-fracturing projects. So I was wondering whether the increased interest among the E&P companies in re-fracturing is good news for Fotech?

SL: Re-fracturing is still a fairly new and emerging field and there’s still a lot to be learned there. The challenge with it is that if you’re trying to re-frack a well, how do you target your new fractures into a new formation, rather than, perhaps, re-fracking old formation, which is now somewhat depleted.

And so as companies put things like chemical diverters into the wellbore to try and push the new frack fluids and proppant into this new formation, unless they use fibre – and in particular DAS technology with DTS – they are really working blind. Whereas with the DAS and the DTS you can now see, in real time, immediately, where your fluids are going and where fractures are being propagated, or where there may be damage occurring to cement.

MT: Is the DAS unique to Fotech, or are there other suppliers of the technology?

SL: DAS in itself is not unique to Fotech, but of course we do have our differentiators. For example, one of the things that is unique to our sensors, which is particularly relevant to fracture monitoring,

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is that in situation where there is damage done to the cement, or the cement has been washed out, the fibre can become loose and start to vibrate with the fluid turbulence. In this situation there is a risk the fibre can get damaged. One of the unique features of our product is that we’re able to detect when that happens. We see a particular signature, which indicates to us that there is a risk to the fibre, that it has become loose in the wellbore, and that it could break in the following minutes or hours. And so we’re able to advise the client and propose they stop fracking or reduce pumping pressure, so as to preserve the fibre.

MT: My next question is of a slightly different nature. Obviously Fotech has been very active in the U.S., but I wanted to ask about what you think will happen to shale globally? Do you have an opinion on where shale is likely to take off in the next couple of years?

SL: Obviously we are a British company ourselves and we would really like to see the UK become the heart of shale for Europe. We think that there is an opportunity for that to be achieved. Poland started first but is struggling at the moment. With the UK we really would need to see the results of the 14th onshore licencing round, because most of the potential clients we have are waiting for those decisions before they can proceed with submitting their planning applications to drill and, hopefully, test wells.

There seems to be good support from the Government, but applications are being blocked by local authorities as we have seen with Cuadrilla being blocked by Local Council, for example. And so we need to try to increase the speed with which companies can receive approval and make progress with drilling and testing wells in the UK just so we can evaluate and find if we really do have a viable resource.

I think that if the UK could make some good progress, it wouldn’t be just for the benefit of domestic gas production, but also there could be some expertise that we could export elsewhere in Europe and into the eastern hemisphere. Perhaps in the way that we have been so successful with our North Sea expertise. Because if we’re successful, we will have to work differently to the U.S. and those particular methods that we develop should be exportable to other nations.

MT: Is that because of the best practices and environmental regulations being stricter in the UK? SL: Yes, it’s partly because of that. I think it’s also down to the nature of our environment here, in that we have smaller roads, and typically smaller rigs, smaller well-sites. What we deploy will have to have a smaller footprint, and we’re going to have to try and do more with less. That’s where

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something like DAS and DTS has a role to play, because we need to make sure that we learn more from each well that we drill. We might simply have less resources at the well-site in terms of proppant and fluids and pumping capacity, so we need to make sure that it is well targeted.

MT: I wanted to ask you about the drive for innovation within unconventionals. On the one hand there is the need for more environmentally-safe solutions in shale exploration. On the other is the drive for efficiencies. But then again, new technology costs money to develop and money to implement. So I wanted to ask you – what is happening to innovation in shale? Is it flourishing or is it being stymied by low price environment?

SL: Two things there: one is from our own internal perspective – yes, it’s a tough market, but Fotech is a growing company and we’re able to support our oil and gas technology partly by the fact that we are in other industries as well. And so some of the innovations that we’ve developed for oil and gas also have applications in our rail and our security businesses.

The positive thing for us is that we are still able to recruit people and continue to innovate.

As for our clients, one of the things that the falling oil prices brought into perspective for them is the fact that they are often working quite inefficiently. They’ve been able to get away with it when the oil price was high, because everybody was making profit, but now with $50 or $60 oil, you have to become a lot more efficient, and the way to gain that efficiency is to use technology – such as DAS and DTS – in order to become more accurate with your fracture placement and to better understand how to space out the clusters and fractures in your well, how to space apart the wells, and therefore how to maximise your production while using the minimum of frack fluids and proppants, With $50 or $60 oil, you have therefore reducing your well-costs. to become a lot more efficient,

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We’ve been able to demonstrate to clients efficiency is to use technology how they can make substantial savings. So what they tend to do is to bear the costs of running fibre and some of these services on some of their early wells, so that they can learn lessons which will be taken forward to their future wells and significantly improve efficiency – even in this market.

MT: So one could say that the current situation is a bit of a blessing in disguise because it is pushing companies towards innovation and then, at the end of it, they will come out more resilient, and more efficient than previously. Would you agree?

SL: That is right, because it will only be the most efficient companies – those that can get the most production for the cheapest cost – who are able to survive in this lower price market. Those that are uncompetitive will not be able to survive.

Published: 17th August, 2015

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