Field Harvest: The digital oilfield has proven its value in a multitude of ways. So why is it stalling?


Since its inception almost two decades ago, the digital oilfield (DOF) has advanced by leaps and bounds. The original concept was relatively straightforward: create a suite of gadgets and software that would allow oil companies to plan, drill, complete and produce a well using data that was generated in as close as possible to real time. The goal was to reduce operating costs, add reserves and increase overall efficiency.

And, by many measurements, proponents have achieved what they set out to do. Since the early 2000s, IHS CERA has been documenting DOF performance in order to quantify the impact. “We have been tracking metrics for a while, and we see production increases of two to eight per cent, operating expense reductions of five to
 25 per cent and capex reductions from one to 10 per cent, depending on the project,” says Judson Jacobs, research director of upstream technology for IHS CERA.

The multifarious Ekofisk field development project in the Norwegian North Sea consists of close to 30 manned and unmanned installations. Utilizing an Onshore Drilling Centre (ODC) in Stavanger, Norway, operator ConocoPhillips was able to bring real-time control to field production and reduce rig staff and drilling days. The ODC paid for itself in 10 months and achieved savings of around US$12 million within the year. (PHOTO: CONOCOPHILLIPS COMPANY)

With numbers like that, one might expect the DOF to be ubiquitous in the oil and gas sector, but one would be mistaken. “Many companies within the industry are not yet convinced that DOF is a driver of value,” says Jacobs. “There are many barriers.”


The technology focused on four main areas: visualization/collaboration centres, real-time drilling, intelligent wells and real-time operating centres (RTOCs). Visualization/collaboration centres allow the analysis and interpretation of large geological, geophysical and engineering databases. Using proprietary and vendor software, they combine and interpret databases in order to identify not only structural and stratigraphic traps, but also the presence of oil and gas.

Real-time drilling, also known as geo-steering, allows engineers to steer the drill bit to the best reservoir locations. During a geo-steering operation, measurement-while-drilling and logging-while-drilling sensors in the downhole tool gather directional, positional and lithological information. Software collates the data into a cohesive picture for the geoscientists to interpret. The drill bit can then be commanded to alter course to find the reservoir’s sweet spot.

Intelligent wells have sensors and controls that allow companies to optimize the life of the field. Operators can control the influx of unwanted water or gas in an oil well and water in a gas well. The technology also allows operators to develop multiple reservoirs and produce them simultaneously from the same well.

RTOCs monitor a wide range of upstream activities. Experts can remotely view and interpret streamed drilling data that allows them to help guide the drill bit to its reservoir target. Engineers can remotely preside over activities in isolated offshore platforms, optimizing production and guarding against equipment failures.

The first generations of DOF suffered teething problems. Costs were high—a visualization/collaboration centre could run from US$50,000 to $1 million per well, geo-steering fees were US$30,000 per day, and installing an intelligent well system started at US$350,000 for a simple, three-zone hydraulic valve set. Reliability was also an issue. Early downhole measuring and control devices in intelligent wells were prone to failure, resulting in costly reworking.

Undaunted, oil companies and service companies sought solutions. Operators focused their capex on specific DOF sub-elements, seeking ways to reduce drilling costs, cut crews or optimize production. Collaboration/visualization centres gave way to global connectivity applications that allowed geoscientists to participate from anywhere via laptop. Hardware was rebuilt to reliably perform at temperatures exceeding 250 degrees Celsius and pressures above 25,000 psi.

Companies throughout the world benefited in a number of ways:

- ConocoPhillips’ US$6-million Onshore
Drilling Centre
in Stavanger, Norway, reduced the number of rig staff and drilling days in the North Sea and brought real-time control to field production. According to
the company, it paid for itself in 10 months and achieved savings of around
US$12 million within the year.

- A customer with a North Sea
RTOC saved 500 helicopter trips, 4,500 worker days and US$53 million in one year.

- Staff in Chevron’s Machinery Support Center
in Houston were able to spot a problem with gas re-injection compressor in an oilfield off the coast of western Africa before it could potentially shut down operations and cost several million dollars in downtime and lost production.

The list goes on. And yet the DOF finds itself overlooked by many companies, geographical regions and play types. The causes are various and complex.


One of the reasons that companies have been reluctant to engage the DOF is because the technology does not follow a well-worn path of innovation. “Traditionally, a service company approaches an operator with a new technology or process and it is tested out on 20 wells before being widely adopted,” says John Elmer, executive vice-president of Endeavor Management, a Houston-based consultancy to the oil and gas industry.

“DOF has taken a different approach. You can’t expect a sensor or a communications network to produce results; organization change has been the bigger determinant of success. People have to work together in order to capitalize on the new knowledge that is streaming in at a much faster time scale.”

Secondly, many companies are not suited to the DOF. “Every company has its own strategy for making money,” says Elmer. “Some independents make profit by buying a producing asset from a supermajor and then tweaking it, using their own processes to lower the cost of operations. For them, DOF may not be a good investment.”

A third, and most important, reason is that many companies cannot make a financial case for the DOF. While $2 million is a small percentage of an offshore well’s budget, even $50,000 can be a make-or-break proposition for an onshore unconventional well. In addition, many plays are located in unpopulated regions, where even inexpensive add-ons at a well pump require infrastructure.

“Onshore unconventional faces the last-mile problem—you need electricity and a communications network to install DOF in remote locations,” says Elmer. “Unconventional wells face rapid declines, so the cost of installing infrastructure has to be weighed against the payout period, which may only be six months to a year.”

Advances in sensors and communication technologies have also opened up the industry to the Internet of Things. This has resulted in a tsunami of data flooding into oil companies, swamping their ability to derive value. “Our clients tell us they use about one per cent of the incoming data,” says Elmer. “There is a big push to make meaningful sense out of the rest of the information by using machine learning and analytics.”

Unfortunately, outdated corporate IT systems can’t handle the load. “The foundation for opportunities in machine learning and analytics lies with better data management, data governance and data quality processes,” says Jim Crompton, managing director at Reflections Data Consulting. “These are the missing or low-visibility elements in today’s DOF programs and are often the reason for low returns and failed DOF projects.”

Complications can arise when companies attempt to transplant a DOF success story. Global oil companies, several of which have made significant advances in DOF in their showcase fields, have had difficulties extending the technology to other regions. “There are barriers, such as geography and languages and independent ways of doing things, that prevent knowledge from passing between assets,” says Jacobs. “It can be a real challenge.”

Finally, simply making an announcement in the C-suite doesn’t necessarily mean that DOF will be a company success. “DOF is not a top-down initiative,” says Jacobs. “There are too many interfaces between saying what to do, and those people who are doing it. It comes from peers who try it and succeed, and pass on their knowledge.”


The key to making the DOF work, say stakeholders, is
to find what parts work best, and where and for whom. National oil companies (NOCs) might not, at first glance, seem to be prime candidates for the DOF. They are granted monopolies and have little market motivation to adopt technologies that give them a competitive advantage, but they still have an incentive to adopt the DOF.

“NOCs cannot sell underperforming assets, so they have to maximize recovery through long-term strategies,” says Elmer. “To do that, they need to have their subsurface model connected to their operational model, pipeline model and refinery model; in that case, investment in the DOF makes sense.”

Supermajors, or integrated companies, can benefit from DOF by cherry-picking specific technologies and best practices that can be deployed to workflows within their operations. “What is the best technology for upstream?” says Elmer. “What is the best for production? They learn from experience and establish a business case that leads to a satisfactory payoff.”

There is now more interest from regional companies focused on unconventional plays in North America. “Some see their plays as assets that require 30 years of infrastructure in place,” says Jacobs. “They have great focus on what can be done to be as efficient and productive as possible. They have business-driven pain points. They can look at a spectrum of new technology and processes and see what delivers value. They are quick to communicate what is working throughout the company.”

Companies are improving data management. “When the concept of the DOF first arose, there was an impression that since there was so much data coming in, data quality wouldn’t be an issue,” says Jason Medd, senior product manager at Informatica, a data software provider. “That proved to be a false assumption.”

For over a decade, Informatica has been working with oil and gas companies to install data governance and data quality processes that fuel sophisticated data management and analytics. Working with open industry standards established by the non-profit Professional Petroleum Data Management Association, Informatica recently launched a new data quality accelerator, based on Informatica’s Data Quality solution, that can align and resolve industry information across a number of different business, operational and analytical systems. The new system allows a company to consolidate data, improve quality and enhance the ability of business units to gain value across the entire well life cycle.

Companies are improving communications between wells and headquarters. BP is one of the early adopters and innovators in the DOF. According to the U.K.-based company, over the last decade, it has installed fibre optic networks and sensors in their North Sea, Gulf of Mexico and other assets in order to amass and interpret immense amounts of data in over three dozen advanced collaborative environments around the world. The benefits have been widespread: the company estimates that it has added 3,000 bbls/d to the Schiehallion field in the North Sea and 10,000 bbls/d at the Thunder Horse field in the Gulf of Mexico and has increased recovery at the Prudhoe Bay field in Alaska from 40 to 60 per cent.

In mid-2015, BP announced an agreement to license GE’s Intelligent Platforms Software. The software will connect all of BP’s oil wells to the Internet in order to optimize production globally. According to statistics, it costs an average of US$3 million per week when an offshore well goes down. BP, which has 6,000 producing wells around the world, plans to capture, store, contextualize and visualize data in real time in order to drive efficiency and performance. BP hopes that the DOF will increase its global production by 100,000 bbls/d by 2017 and support the addition of one billion barrels of reserves.

GE collaborates with oil companies to co-create DOF value on several fronts. “Unified Operations is a concept that helps increase uptime and efficiency for oilfield assets,” says Ashley Haynes-Gaspar, general manager
for Software & Services at GE Measurement & Control.

“We are working with a large oil company on a Unified Operations project involving gas turbines. Gas turbines are very similar in terms of their physics, but they tend to behave quite differently depending on how they are operated. In Q4 2014 we successfully installed a proof of concept at an LNG facility and are now working on the next phase. We expect to connect more than 150 gas turbines across five geographically dispersed business units in this next phase, and we will ultimately connect 5,000 pieces of critical equipment by the end of the program."

The concept can be expanded to suit a variety of needs. “I envision a Unified Operations world in which an operator sees a strange signature at the start-up of a piece of equipment and can investigate where it has occurred before in order to establish what is happening now, and how it was solved,” says Haynes-Gaspar.


Several trends that will shape the future of the DOF are already emerging. “We are seeing the DOF shift away from being technology-centric to more organizational-centric,” says Jacobs. “A decade ago, the technology drove the DOF, and now the work process drives the technology.”

IHS has been working with a client in Australia who was taking unconventional gas—coalbed methane— and turning it into LNG. “They recognized the need to have a very good value chain integration,” says Jacobs. “It wasn’t enough to optimize a well or a processing facility, because many of the wells might not start up again if they were shut in because a plant went down. They had to look at the entire process, right from the wells to the market. They incorporated the right tools to enhance predictability, and collaborative technologies so that they could act on information in order to make the best decisions.”

Regulators will also look to use data provided by the DOF to advance safety and environmental concerns. “We can expect legislation in the future that will call for the monitoring of fatigue in the well and the BOP [blowout preventer],” says Elmer.

The predominance of data-driven analytics will be complemented by first-principle analytics. “Data-driven analytics collect the data and look for correlations; if A and B rise, then module C is likely to fail,” says Jacobs. “That approach doesn’t care why module C fails, it just looks for the correlation. First-principle analytics looks at the physics behind events, why shale physically responds to one certain type of stimulation over another due to fluid properties.”

“Code halo” is a term used to describe the information that surrounds people, organizations and devices.
“It is generated by clicks, swipes, views, interactions and transactions that generates a ‘virtual self’ made of code,” says Haynes-Gaspar. “We have them as consumers—halos that follow us.”

GE foresees a time in the near future where code halos could also exist in the Industrial Internet. “You could have a virtual best operator that helps you understand how to achieve better uptime for your assets, regardless of where they are,” says Haynes-Gaspar. “It would be like a digital twin.”

Currently, the low commodity price environment is having a negative impact on the DOF. “Prior to the last six months, the focus was on production and recovery,” says Jacobs. “That focus has now shifted to cost management and efficiency improvements. Now, you need to show improved results in the next six months; there is little tolerance for a science project that might bear value in five years.”

That creates a silver lining for DOF, however. “The technology has been available for the last 10 years,” says Jacobs. “If you embrace it now, you will differentiate yourself from the competition and come out much stronger when the recovery occurs.”

“The low oil price environment has forced companies to sharpen their pencils,” says Elmer. “Any technology that has proven it can save money becomes part of the work process. The main limiting factor for the DOF is whether the investment in monitoring, communications and infrastructure can still be justified by ROI [return on investment].”

This article is part of a four-part series with sponsorship from GE exploring the Internet of Things and its impact on the oil and gas industry. While GE professionals were inter- viewed for this story, the company had no involvement in its creation or production.

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