September Lunch and Learn Q&A

News

September Lunch and Learn Q&A

Posted on 10/Dec/2018
September Lunch and Learn Q&A

Lunch And Learn Panel Session


2018's Extended Lunch and Learn, which took place in September, featured a number of speakers from Operators, Service Companies and the Regulator. 

Here we share the full transcript from the event's Q&A where the panel comprised Margaret Copland (OGA), Matt Dunning (BP), Valentine Ojogwu (Shell), Robbie Fargo and Ryan McGill (ConocoPhillips), and was chaired by Darren Bewick (TAQA). 

Margaret, you mentioned about the 14% intervention rate. Is there anything that the OGA is doing to encourage people to do more interventions?

Margaret Copland, OGA: “So we have the data now. We’re going to be sharing it with industry in general and we will be speaking to the various Operators about what they’re doing to achieve MER UK, i.e. what they’re doing to optimise production where it is economic from their wells. So if you’re an Operator in the room, expect a visit.”

Margaret, have you got any more data on the success rate of the water shut-offs that you’ve seen for the last year, and any inferences or connections with the amount of surveillance, on the types of surveillance that led to successes?

Margaret Copland, OGA: “We only have detailed data from last year because how we collected data on interventions changed last year. So we don’t have data on what surveillance was done in previous years. I should say, it will come out in the report shortly, only 8% of wells had surveillance carried out on them last year, so very, very poor. So we don’t have the full picture going forward. All of the water shut-off activities carried out were technically a success. Whether that was economic is a different case, but from a technical point of view, they all worked.”

Another one for Margaret regarding the 14%. How do we compare as a basin, a mature basin predominantly, to other basins around the world? Because that’s who we’re competing against ultimately.

Margaret Copland, OGA: “So we don’t have the figures because most other regions around the world do not report or have to report to a Regulator and therefore it’s not shared. 14% is low. It’s lower than it used to be many years ago. So obviously the more interventions we can do, the better. We’re a mature province, therefore it’s even more important that we go in to each well, but I’m not telling you anything anyone in this room doesn’t know. We need to do more. We need to increase recovery factor from reservoirs. Recovery factor from reservoirs in the UKCS is not increasing. So 20-30 years ago when a lot of these reservoirs started off, there was a recovery factor estimated what it was going to be. It’s not increasing. With all this new technology, we know how to do things an awful lot better. Yet we’re still not managing to economically produce more from the reservoirs. That’s got to change.”

Valentine, this one’s for you. What other types of technologies had you considered for your example?

Valentine Ojogwu, Shell: “So there were two other specific ones that we considered. Matt mentioned one of them, it’s CannSeal. I don’t know if CannSeal’s here today? And then also considered BiSN as well which is another technology. I’m not sure if they’re here today. Both of those technologies are things that will help us inject some sort of substance or fluid into the annulus where we can definitely have some sealing from the lower perforations. As I’ve said, those technologies do not give 100% sealing, simply because of the inclination where we’re planning to set these tools.”

Question for Matt. You talked about the costs of getting on to your wells, your subsea wells, and your discussion just really talked about running PLTs. Is that all you’re doing, or where do you see yourself going to get maximum data and what tools conveyance are you thinking of?

Matt Dunning, BP: “We consider every well on a case-by-case basis. Simple answer is no, we’re not just considering PLTs. We are looking at things like saturation logs, other data acquisition as well; calipers we would typically get anyway. But it kind of depends on what we think is going on and certainly for some of the West of Shetland fields, saturation data isn’t easy to acquire because of the salinity of the water. It’s not easy to interpret and get a conclusive answer from it so it does kind of depend on the candidate. But we do typically approach it that if you’re in the well, do the maximum we can while we’re there, both in terms of data acquisition and also to be set up for things that we might not expect that we can easily carry contingency for. For those of you who’ve seen the Kinnoul presentation that we gave before, we went into that well and didn’t expect to find a closed valve downhole. That was a bit of a surprise for us and more and more we’re trying to make sure we cover every eventuality without pushing the costs through the roof.”

So fiber optics and noise logs?

Matt Dunning, BP: “Possibly. We have done some fiber optics this year, it depends what we’re looking for.  Greg here in the audience ran fibre optics on Mungo this year so we have been doing some of that too.”

Valentine Ojogwu, Shell: “Maybe just to add to that. We actually looked at fiber optics on noise logging and saturation logging. So going into this well, we’re actually looking to gather more data before we actually go and deploy the technology. But I guess with the BP approach, what we’re also doing is we’re going in with these logging tools and also going in with the tools to actually remedy the problem right there and then. I don’t think, there’s no appetite to take the logs just for taking the logs’ sake. To kind of solve it once you identify what the problem is.”

I’m just curious. It’s a well-known problem and so on and so forth, there are technologies out there. You know the adoption of new technology in this space is pitiful. What screening process do you apply in technology selection and have you considered working with chosen partners to actually drive the solution rather than wait for it to come via mediums such as this?

Valentine Ojogwu, Shell: “So I’ll briefly mention on the technical side. What we tend to do is we go to different vendors and what happens is there’s quite a lot of cost involved with setting up what these tests can be. Of course, as Operators what we’d like to do is to set up these tests for free. In an ideal world, that never ever is the case. So what we’ve started trying to do is to, kind of, come up with a partnership to where we agree to testing the technology and then agreeing to some candidate wells. And now, in a sense it also helps the vendors because they get the case study, they get the ability to test their technology but also for us, it actually reduces the cost. I think another option that we’ve started looking at recently is going out to the OGA to actually get some funding. But I’ve focused more on the technology side, that’s basically what we do. We do the testing, we come up with basically these testing strategies with companies and then see what other options are available.”

Darren Bewick, TAQA: “One of the things to follow on from that and one of the things that certainly I’ve made notes on is that we’ve heard from BP, Shell, ConocoPhillips. I can confirm TAQA have, I could put slides up there that say exactly the same story. Especially when we’re speaking about subsea as well, the costs involved with subsea. You know we’re working in other areas of the industry. We’re looking at combining efforts and sharing technologies and sharing work scopes in terms of potential intervention job opportunities and I think it’s something that, this has got legs to follow suit. And I think Margaret’s report coming out, and the chasing the Operators, will probably add some meat to the bones.”

I had a quick question for Anna and Scott (Tendeka and RESMAN respectively). Correct me if I’m wrong but it’s mainly ran on completions your technology, is that correct? Are there any retrofit options that you’ve been looking at or have been thinking of doing?

Scott Glendinning, RESMAN: “Yes, we have looked at some retrofit, but initially it was going to be for some land wells initially to get some track record on it. We have looked at some cases particularly for Shell, for retrofitting some of the reservoirs. It never actually came off due to being quite a high gas well. It’s something we have looked at, but we’ve got so much stuff on the horizon that it’s sitting there. If someone wants to take it on. We started the process but we had to stop it due to the amount of other things that we’re working on.”

Anna Petitt, Tendeka: “The example I presented was a retrofit installation in China. We have also had retrofit installations in Canada and Oman. We’re looking at one for BP at the moment, in the UK, which would be retrofit as well.”

So this is a question for anyone who does the logging and field surveillance type of stuff. So one of our examples there was looking at a wide field map, lots of wells on there for a kind of approach from the south and we’re getting to the early stages of identifying the couple of wells where we’re losing production but we’ve been caught in the past with things like callipers. We’ve not done a regular surveillance and then wish we had done. So from like a water monitoring perspective, what would people recommend for a timescale, what kind of things should we be looking at to do upfront and how you demonstrate a value case for something you may get value from in 6-7 years’ time compared to jobs that you’ll get a return on this year / next year? Does anyone have an insight into that longer term view and things we could be doing and pushing now for a benefit later?

Matt Dunning, BP: “For me, it’s largely a function of how much it costs to get our data.  From my own experience at Wytch Farm on the older wells, the vertical wells, we had saturation logs more or less every 3 years for quite a long period of time. In terms of understanding what layers were flooded and how that water flood was progressing was amazing data. Let’s just stick them on the glass of the window and overlay them. You could see where the water was coming through and manage that. Obviously you get to subsea wells and it’s just, it’s the cost that stops you from taking that type of approach.  On land wells its easy, platform wells are somewhere between. It’s trying to get the balance right, I’m not sure we’ve got the balance right just now but that’s the challenge we have, I think.”

Darren Bewick, TAQA: “Yeah, I concur. I think my experience is the first thing that comes off the budget is the surveillance so if we can build a better case and again, using Margaret’s report might push us down the road that bit more in terms of having to do these things and getting our recovery factors up.”

Margaret Copland, OGA: “I think the other thing, if it’s for new wells, you know, really speak to the people planning these new wells and whoever is running the completion. It’s not happening often enough, yet we can see from the figures that that will pay back for itself in the future. Yes we know that capital today is always difficult to justify but that’s the way to solve this problem for the future. It won’t for all the wells we’ve already drilled, but let’s stop making the problem worse.”

Just to say something on that. You’re absolutely right, the first thing to be cut is surveillance budgets. We had a guest speaker a number of years ago at the ICoTA annual conference, from BP in fact, and he also made the same comment that the first thing to be cut was your surveillance budget. It reinstated that, realising that it’s perhaps not the most prudent approach to the future and he advised on that day that some 30% more reserves were added to the books as a function of a surveillance programme. So if you want more, you’ve got to go find it I guess is the answer, and only with the increased levels of intervention are we likely to see that, but the short term-ism in the industry is something we’ll always combat. You know, the longer term view is just not something we’re used to applying beyond the initial approval for field development and we need to do that on a well-by-well basis as well.

Matt Dunning, BP: “I think it’s also incumbent on all of this that when we do get the data to make a bit more noise about what we found out about it. And I know, again from personal experience, I’ve had a reservoir engineer demanding a log, eventually got the log, delivered it to him and it sat on the shelf for 2 years before we interpreted it. When he asked me for a log again, I didn’t get it for him. I think we need to shout from the rooftops what we’re finding from that information so that we can get more of it.”

I think what we need to bear in mind is it’s not just the acquisitions, it’s actually, it’s the solution. You know, we’ve got to deliver on that. A lot of Operators maybe don’t have that luxury having a subsurface team can take that data and make sure the industry is well equipped and have the confidence to act on it. Hats off to you, but the smaller Operators that we’re seeing coming forward into a mature basin. We need to be able to help them from an industry perspective.