BP – using connectivity to drive productivity
Feature Articles, Sep  01  2009 (Digital Energy Journal)

- BP has installed real time monitoring systems on 80 per cent of its high rate wells – along with 2 million data tags and 2,000km of fibre – but there’s plenty further it can go, said David Latin, vice president of E&P Technology, speaking at the recent FindingPetroleum / OilVoice conference

David Latin, vice president of E&P technology with BP, says he believes that connectivity is the grease that drives productivity at BP, speaking at the recent Finding Petroleum /OilVoice Forum (London, April 22nd).

David Latin, vice president of E&P technology with BP

Digital technology has “helped us do things more efficiently, more effectively and at lower cost,” he says.

So far, BP has fitted 80 per cent of its high rate wells, and 40 per cent of its wells in total, with technology for real time monitoring, he said.

It has already installed over 2m data tags and has 2,000km of fibre connecting its facilities.

The company has around 30 in house staff and 70 consultants working directly on its “Field of the Future” (TM) project; it also has a staff member in each of its business units helping to roll it out, looking at change management aspects and application of the technology locally.

In a sense, everybody in the entire company has been involved in the project at some point, he said.

“We think we've delivered something like 80,000 barrels a day of extra production as a consequence of using this technology to date and saved more than 100m dollars of capital expenditure,” he said.

This is a much cheaper way to increase production than to drill more holes, he said. “This is very low cost.”

The financial value works out at between $3 and $6 a barrel, which is is similar, or better, to doing well workovers, he said.

BP’s digital oilfield strategy started with its largest and most complex oilfields – where it has a lot of money tied up.

For example, an early target was its Gulf of Mexico Thunderhorse platform which produces 350,000 barrels of oil per day from 7 wells. “We need to manage them carefully and ensure we get maximum value,” he said.

“Digital oilfield allows you to manage your fields more effectively and more efficiently,” he said. “It’s about reducing capital costs and reducing operating costs and making people more efficient in what they do day to day.

The main benefits are being able to take real time measurements of oil, water and gas production, quickly optimise the complex production systems, and feed the data straight into reservoir models.

Future

But there is still a lot further to go.

“If you think of a future where information flows freely and easily to individuals wherever they are, and it’s been filtered so they're only getting what they need, and as much as possible it’s automated, so it doesn't need to go to an individual unless they need to make a human decision, and it’s applied across the whole value chain, I would say we're miles away from being done,” he said. “We're all in the infancy really.”

Another challenge is working out how to use it viably in low rate onshore wells. “It requires different types of thinking and different solutions.”

“In North America a lot of the issues are to do with people driving large distances to gather data or do maintenance.”

There is plenty more progress to be made in how the data is used to improved reservoir management, he said; there is also new nano technology being developed which might be able to “revolutionise what we can do with reservoir engineering,” he said.

BP is making efforts to protect its technology investments. “The market is quite immature and we think we're quite far ahead of where the market is and that adds value to us,” he said. “I think this will ultimately separate winners and losers in the future.”

Three layers

BP sees the digital oilfield in 3 layers – data infrastructure and architecture at the bottom, then a middle layer where that data is turned into information, then a top layer when you try to work out if you can do with the data to optimise what you are doing.

“That's how we think of digital oilfield - and it really applies to everything from the oil in the ground through to our terminals - and we apply it to our refining as well. IT really touches every part o f he business,” he said.

Fibre cable

In the Gulf of Mexico, BP has laid a 1300km cable which connects all of its platforms. The cables provide 2,500 times the bandwidth of a satellite connection.

The cable has proved particularly useful in hurricanes, he says. “We have 20:20 vision of what goes on in the platforms,” he said. “We're down manned, but we can still see everything, we know everything. We know if anything has happened and we can start to plan a recovery. We're the only company that has that capability in the Gulf.”

The system is very helpful for people actually working on the platforms. “You can use software and it downloads instantly,” he said.

Remote drilling

In Indonesia, drilling engineers in Jakarta watch real time drilling data from the field operation 2,000 miles away in West Papua.

“Having this real time connected-ness between the field team and experts in the office really does improve how people work together,” he said.

“This particular team think they have saved something like something like 7 days of non productive drilling time on the 2nd well.”

“They had a well control issue - they solved it something like a week faster than they would have done without this kind of connectivity. It also saves a lot on travel costs as well.”

Instrumentation

There is nothing new about installing temperature and pressure equipment in wells, but what is new is using this information to calculate flowrates and production from the well.

Oil companies always calculate what each field is producing for management and regulatory purposes, but they haven’t historically measured the production from individual wells.

“Historically it has been done by testing wells at intervals - they can be quite big intervals - between those intervals you won't know what a well is producing. There's typically an allocation error of between 15 and 20 per cent in a normal oilfield,” he said.

However from the continuous temperature and pressure measurements, it is possible to measure the flowrate to an accuracy of +/- 5 per cent, including flowrates of oil, gas and water.

“If you’re managing a reservoir, you need to know where your oil gas and water are coming from and going to,” he said. “If you have a 20 per cent error - that will result in poor reservoir management and low recovery.”

It is also possible to measure the production from different intervals within a single well.

“In Azerbaijan, we run fibre down our wells - it collects distributed temperature data, and that can be converted into information about flowrates, real time,” he said.

“It shows where the flow is coming from in those layer intervals. It can show you where you want to add water,” he said.

Combined with 4D seismic, it gives you a clear view about which zones are producing.

Production optimisation

A good example of how the technology has been used to optimise is in the Schehallion field, West of Shetland, where a new system was implemented to reduce slugging by changing gas injection and throttling the production line.

The production system is very complicated, with gas injection, production through long horizontal wells, producing oil, gas and water, gathered at an FPSO.

“It’s a very complex system and can become very unstable,” he said. “One of the things you'd like to do is stabilise that system and increase overall production rates from it.”

One of the biggest problems is slugs – where liquid or gas builds up in the well and comes out suddenly – instead of a continuous flow of liquid and gas mixed together, which is much easier to handle.

By manipulating the choke valve at the top of the riser according to the computer model, BP was able to keep the flow of oil and gas coming smoothly through the well and avoid slugs. “This mechanical calculation actually worked,” he said.

Data analytics

A growing area is data analytics services.

“These are already being used in oil refineries, to try to predict when components will fail,” he said. “But it is in its infancy in terms of reservoir.”

“That's an area that will really take off in the next few years.”

“There's a tsunami of data coming now, how does one manage one's way through that smartly?”

One of the things we're doing that we find very valuable is using data about historical performance to bound future performance and to make business decisions,” he said.

“So for example, we can look at our pipeline and how measurements of wall thickness over time and how corrosion takes place - and use that to make empirical physics calculations as opposed to theoretical physics calculations.”

“Another type is to use drilling parameters and try to analyse in real time what your drilling parameters are and try to predict when the bit might fail, and then choose when you trip out of the hole rather than let it happen to you.”

Data analytics could be useful to analyse data from neighboring wells and try to work out how they might be connected underground.

People

The biggest challenges with this kind of technology is usually connected to people. “Its 80 per cent about people, 15 per cent about processes and 5 per cent about technology,” he said.

“When you have a brownfield - eg forties field that's been running for a long time people have been working on it for a certain time in a certain way - the behavioural change aspects to that are far greater than for when you have a new field in a new environment with a new workforce and they start working like that from day 1,” he said.

This means that it can be easier to install digital oilfield technology on new fields rather than older ones.

Watch David Latin's presentation

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