The term ‘digital oilfield’ is much banded about in the oil and gas industry, but often not entirely understood. In essence, there is no such thing as a ‘digital oilfield’ in its current form because it is an amalgamation of several technologies – both new and old – which together contribute to the overall concept. And the concept itself is very much a work in progress because while fully digital oilfields will eventually become commonplace, they are still in the evolutionary phase.
So what does the term mean? Business advisor Deloittes, which consults with oil companies on digitising their activities, defines the digital oilfield as: “Nothing more than the evolution and convergence of a number of oil and gas drilling, exploration and digital control techniques coupled with standardised communication technologies.” It says the concept “potentially extends from the use of 4-D seismic imaging through to data-to-desktop initiatives that take production data through to marketers and traders. This means, it can, potentially impact the entire oil and gas value chain with all the technical, process and human impacts that go with it.”
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And the incentive to digitise comes from cost benefits. Cambridge Energy Research Associates has estimated that going digital can shave up to 7% off operating costs and that using digital processes to increase and enhance oil recovery could add as much as 125 billion barrels to global reserves by 2013.
In essence, creating a digital oilfield means an increased use of IT to help exploration and production. Today ‘digital oilfield’ has become an umbrella term that describes activities throughout the production chain and has tended to replace earlier terms such as: ‘smart fields’, ‘e-fields’ or ‘intelligent fields’.
How it works
So how does a digital oilfield work? One of the main features is the use of fibre-optic temperature and pressure sensors around the field (primarily underground), which are connected to monitoring stations on the surface. Data is then transmitted to the company’s offices and fed into computerised optimisation models enabling engineers to see exactly, in real-time as well as in the form of a 3-D image, how oil is moving through the field. These underground sensors also act as an early-warning system alerting engineers to potential problems before they occur.
Digital technology is now available at every stage of oilfield processes from intelligent wells, including automated working systems, fibre-optic monitoring below ground, automatic data acquisition, reservoir modeling in real time, IT reservoir and well supervision systems that detect leaks and carry out automatic instant diagnosis of possible problems, and increased asset and risk assessment functions.
Examples of the digital oilfield are already in existence. Sometimes described as virtual oilfields they operate as a fully digitised facility, which requires very little or no human interaction at the well-head. This brings several benefits, as Cisco Systems, which offers virtual oilfield technology, points out: scaling of key resources and skills with specialised expertise able to be deployed anywhere in the world, combating the loss of expertise due to an ageing professional workforce; projects can be staffed based on competency, instead of physical location, improving performance and outcome; people can connect regardless of time, space, or organisational boundaries; asset usage increases due to increased field productivity; and smaller IOCs can establish an effective global presence.
Schlumberger, which now digitally enables every new service it offers, says the digital oilfield can substantially improve productivity. It has developed 4-D seismic solutions, which have moved processing to the seismic vessel to run concurrently with data acquisition. This has shortened delivery times and allowed direct input of 4-D results to field planning decisions.
Having these results so quickly has, Schlumberger claims, already saved millions of dollars through more timely decision-making. It says one of the main features of the digital oilfield is the increased use of drilling centres. It operates nine teleports around the world, including one in Aberdeen, which can monitor up to 28 concurrent drilling operations in the North Sea; a similar site exists in the Gulf of Mexico.
Schlumberger says its vision for the digital oilfield includes “a global managed network covering the entire oilfield operation, from the first mile to the last mile, connecting field operations with petro-technical professionals in the mobile office environment”.
It also has an alliance with the UK’s BT to provide collaboration through converged communications and IT services, supporting interactive drilling and production operations. This first mile wireless service provides the critical first link in the digital communication chain for operations not served through wired connectivity.
Benefits
Schlumberger says the processes associated with the move towards the digital oilfield improve operations and financial returns. More efficient and better quality prospect generation can lead to a 7% increase in production costs and a 25% reduction in capital/operating costs while the use of dynamic drilling can double the target hit ratio and reduce drilling costs by 15%. Data driven reservoir monitoring, surveillance, diagnostics and optimisation help increase recovery factors to +65% and having a dynamic link between reservoir and economics increases capital allocation by 10% and improves field cash flow by 25%. In addition, harnessing global data, knowledge, and expertise can lead to a 10% increase in production and 10% reduction in capital/operating costs.
It is these obvious benefits that are peaking energy companies’ interest and several have already launched in-house programmes to digitise their operations. Shell, for example, launched back in 2004 its ‘Smart Fields’ programme, which integrates real-time measurement, monitoring and control technologies for oil and gas field operations and development planning. The concept relies on developing and deploying new technologies from a variety of sources. It means that fields can be unmanned, enabling engineers anywhere to operate them remotely. By monitoring a continuous flow of information, engineers can act swiftly to optimise production and operations, which took several weeks in the past, but now only takes hours.
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What next?
While the digital oilfield future looks assured, the path to its full introduction and widespread application is not at all straightforward despite recent technological advancements. As with most new technologies, there is more to their application than just the associated software and hardware. Many oil companies have, and continue to struggle with their ability to integrate the vast amount of data from different sources many of which operate on different IT platforms. To address this, attempts have been made to standardise data flows. A prototype of a standard for drilling data and applications dubbed ‘Wellsite Information Transfer Standard Markup Language’ was released in 2001 under a collaborative effort by most of the oil and gas majors and became widely adopted. A programme to develop a follow-up standard ‘PRODML’ was launched in August 2005 by, among others, BP, Statoil, Shell, Chevron, ExxonMobil, Halliburton and Schlumberger. Its aim was to be a low cost, low risk yet highly innovative environment for the configuration and running of advanced optimisation processes. PRODML version 1.0 was launched in July 2006. This is already helping the industry move closer to the concept of the digital oilfield.
There are other projects underway to address the data issue. For example, the Aberdeen, Scotland-based Digital Energy Exchange. This is a collaborative joint venture between several small and medium sized enterprises, who believe that “an independent, industry recognised, data exchange service is key to the realisation of the next upstream performance step change”. It says there are several reasons why the prospect of the digital oilfield is taking longer to become a reality than had been anticipated. These include: a lack of focus on people and processes and too much on the software involved; a lack of integration; too much haste to aim for a fully linked integrated model before fundamental issues have been addressed; a lack of scalability; and difficulty in sustaining momentum.
It appears that many of the challenges that have arisen on the road to the digital oilfield are on human level. The vast amount of data and its complexity require new skills and capabilities within a company to analyse them. Also, as many of the well monitoring functions become located at some distances away from the actual field site, there have been concerns that this could give rise to a loss of local familiarity with the well.
As Deloittes puts it: “Many impressive claims have, and continue to be made as to the delivered benefits of digital oilfield programmes but […] appropriate and well-thought through key performance indicators must be established up-front to ensure that the programme benefits are clearly distinguishable from other production or cost impacts.”
Ensuring the energy industry has the skills to cope with the new data demands is being addressed by the Society of Petroleum Engineers (SPE) through its IT Technical Section which is described as being “about the digital oilfield, connecting sub-surface to field operations and determining how best to enable a new kind of business and a new breed of professionals”. The Section held its first meeting in 2006 and plans to focus on: systems integration; professional development; information security; and industry forums to promote knowledge sharing, training and best practices.
While it may not yet be a fully established concept, the digital oilfield is fast becoming a reality and the practices associated with it are improving all the time. Ultimately it will succeed because the bottom line is that it means billions of barrels of oil that would not otherwise have been exploited will become accessible. And, as is already being demonstrated, digital technologies are already leading to more productive wells and more efficient field operations.
