Downhole pressure monitoring in oil and gas reserves with Acoustic Data

Matthew Farmer 4 November 2020 (Last Updated November 5th, 2020 17:24)

UK-based technology company Acoustic Data deploys retrofittable, durable downhole pressure sensors to help the operator keep down costs and provide surface readouts of field health. We spoke to the company to find out more.

Downhole pressure monitoring in oil and gas reserves with Acoustic Data
The acoustic probe works via a slick line unit, allowing for retrofitting. Credit: Acoustic Data.

In an information age, field operators will know that more data can mean fewer costs. While pressure monitoring helps measure a field’s health, monitoring devices often have short life spans, and few options exist for brownfield sites. Since 2012, Acoustic Data has aimed to change this with its sound-based devices. We spoke to global sales director Stephen Murphy about where the technology fits into the world of oilfield solutions.

Matthew Farmer (MF): What is the importance of real-time pressure monitoring?

Stephen Murphy (SM): Engineers are very much blind of what they’re seeing in their assets. Having that real time data enables them to optimize those assets, especially as we move into times where cost is the number one concern in everyone’s working manual. Having that cost effective solution, being able to retrofit, and being able to understand more about the reservoir is really key, now more so than ever.

When you look at conventional methods, you’re looking at memory gauges, where clients are doing sporadic runs and not getting real time data. It’s obviously a very cheap method of getting data, but you’re always looking back at the data itself. Having a cost effective, retrofittable, real-time solution is a niche market to be in.

Other ways of getting data include permanent gauges, but those kind of systems are often installed at the very beginning of a well’s life. I was running those gauges back in the 90s, and a lot of those have failed since, though obviously not the ones I installed. They’re normally limited to a five- or ten-year life, so you have a lot of brownfield assets out there which don’t have any monitoring.

MF: Does the ability to retrofit these systems mean that, outside of real-time monitoring advantages, there can be cost advantages of having a longer-lasting system?

SM: Yes, it’s a rigless solution. All we need is a slick line unit, which keeps costs down. We can run it into an existing completion. When those batteries are fully depleted, we could retrieve the system, install new batteries and run again.

Some of our systems in the lower-temperature environments can see up to seven to eight years of system life. In higher temperature applications, we can still achieve well over three years’ system life.

MF: What limits are there on where these devices can be used?

SM: Temperature is one of the biggest limitations when it comes to wireless systems, across the industry, and that’s mainly down to the batteries. The highest temperature rating that we have is 150°C, so certain regions are out of reach. At those temperatures, you’re probably going to get a system life of roughly one year.

Other limitations are in the complexity of the well. We require freestanding tubing. We don’t work in a cemented environment, due to the acoustics and attenuation caused by cement. Other technologies can, but to be as cost-effective as possible, we stick to freestanding tubing.

We market ourselves as an onshore or platform solution. We haven’t really looked at subsea environments, the reason being if you’re going to do intervention on a subsea well, then you know there’s a lot of cost involved, so cost-effective solutions probably aren’t ideal there.

MF: What sort of innovations would you look to put into your product in future?

We have a technology which we utilize to give a client data, but some clients would like to utilize our communication protocol for control of assets. That’s another area we’re looking at, and teaming up with like-minded technology companies.

There are actually quite a few companies doing things like that. The big players have controls that they utilize in drillstem test environments, where they’re just controlling downhole shut in tools. It’s an area where we’ve had many inquiries.

Currently, we deploy our tools in a ‘simplex’ mode, which means we program them at the surface, before deployment, what data and what frequency we’d like it to work with. Moving forward, we’ll move to duplex, meaning we’ll be able to really communicate with those tools from surface without retrieving them, changing frequencies and fully optimising the assets for clients.

MF: How do these sensors integrate into existing systems?

SM: We can tie into any kind of distributed control system, gathering data from well heads on a rig. They normally monitor that from town, if it’s an unmanned platform.

We can tie our top side units into those systems, using Modbus communication protocols, so the operator on the beach can see how well wells perform. You can see downhole pressure and temperature, and if the engineer is carrying out activities on different wells within that field, then they can see the interconnectivity across the field as well as within that one reservoir.

MF: You’ve said that these systems can retrofit into existing wells, but how exactly does the installation process work?

SM: It’s a turnkey contract awarded to operators. It’s a two-man job, if you’re talking about 24-hour operations, and we work closely with the operator. Normally we would be involved with a slick line crew, and our crews work in tandem with them.

In the case of our recent deal, we’re providing small elements of real-time reservoir monitoring to one of the top four oilfield services operators, during their post-frack operations. The company actually has their own technology for this, so it’s good to be held in high regard. They’re very much concentrating on the short term drillstem tests. We look at the long term, which is our kind of niche market.

MF: On this recent deal: why did you go ahead with it?

SM: This contract kind of came about for about a year and a half ago, we just didn’t make the announcement due to Covid and rig shut down. So we’re looking to get operational, hopefully, at the tail end of this year. We’ll actually start running systems at the beginning of next year.

The clients utilize sporadic memory gauge runs. When they do well testing, they’ll run some memory gauges, they’ll sit there for 30 days, and then they’ll stop the well test, retrieve the memory gauges, download data; and they’ve probably really just done that because the guy they took over from did that. They’ve never had cost-effective, real-time data.

MF: What applications does the technology have outside of extraction? Can it assist with carbon capture and storage (CCS)?

SM: We’ve looked at a couple of (CCS) opportunities, actually one of those was in North America. That’s definitely a market that we’re exploring and seeing how we can utilize the technology. Typically, they sometimes measure multiple points and utilize fibre optics… But there’s obviously a huge cost involved when it comes to fibre optics. We have a lot of interest in those markets, and in salt caverns, and did some recent presentations for SMRI [the Solution Mining Research Institute] as well.