SPE Digital Energy Conference 2009, Houston

Despite the downturn, R&D is not dead. Some researchers are now attached to assets and ‘there are no more glossy brochures!’ Most agree that ‘digital’ is only partly about technology. Exxon has developed a ‘Suitcase’ of tools and processes to ensure rapid startup and sustainability.

In her Keynote, Melody Mayer, who heads-up Chevron’s Energy Technology Company noted the impact of current economic conditions that have led to ‘cost management’ and other restrictions. Meyer asked, ‘Is a digital energy strategy important in the low cycle?’ Pundits expect 2009 to be hard on innovation. There are cutbacks on endowments to universities and questions as to where R&D fits-in. Mayer believes that those who keep at it will come out ahead at the end of the recession. Kicking-off the panel discussion, Mayer suggests that digital energy means different things to all. In the late 1990s a powerful idea came along to use existing technology to integrate differently with the dream of optimized oil field operations. But we forgot that some of our fields were ‘built’ 100 years ago! We had to step back and rethink things, starting with the existing data and field systems and rebuild our ‘transformed operations’ to optimize performance. The i-Field is also about upstream business transformation—in fact it is ‘only 5% technology,’ and much more about workflow. The i-Field also represents a shift from a linear, silo-oriented process to an optimized, collaborative approach. Today, Chevron’s Asset Decision Environment (ADE) lets remote field teams plan and trouble shoot field operations. This has led to safer and more efficient operations. While an ADE is dedicated to a particular field, Chevron’s integrated decision environment’s scope is broader and is used to optimize technology development and to leverage subject matter experts. Mayer’s own definition of the digital oilfield is ‘a workflow transformation from well to sales meter.’ Chevron is using integration in these challenging times to reduce costs. Digital energy is transforming the way we work. Asked what the ROI of i-Field might be, Mayer elegantly ducked the question.

According to David Latin, $40 oil is an opportunity for BP and is in fact ‘really good news’ for the digital oilfield, known in BP as the field of the future. Latin’s definition revolves around real time workflows and making better decisions faster, about codifying knowledge and eliminating inefficiencies. Latin agreed with Mayer recalling that mistakes were made with the early focus on tools. BP is now more aware of the importance of people. That said, Latin started enumerating BP’s digital oilfield inventory comprising, inter alia, 2,000 km of fiber, 2 million equipment tags and advanced collaboration environments that today manage 40% of BP’s production base. Digital has added 85 million barrels per day to BP’s production and is ‘cheaper than well work.’ Examples include WITSML data feeds that speed recovery from well incidents, better slug control and the use of physics-based modeling to optimize multi-phase flow. Latin’s team has less money than before but BP is not about to stop doing R&D. Team members have been redeployed to assets and there are ‘no more glossy brochures.’ The focus now is on extracting value from the technology with at-scale deployment. BP is on track for a billion barrel reserve hike and 100,000 barrels per day of increased production over 10 years.

Derek Mathieson (Baker Hughes) defined the digital oilfield as ‘technology and workflow solutions connecting in a spatially-distributed way and in process-consistent time.’ For instance, data from a single sensor might be seen by 100 people around the world. For Baker Hughes, commercial solutions have sped things up greatly. Remote control and intelligent completion are now maturing. In its report on the Digital Oilfield, CERA deemed automation to be ‘a commodity.’ Mathieson does not agree, ‘We are only just coming to terms with control systems theory and optimization—which are an essential prelude to optimization.’ Baker Hughes was a late entrant in the digital oilfield. In 2002 it only had 3 rigs in Norway that were ‘connected.’ Today, 100 rigs are operated from three Beacon centers around the world and 30% of its high end MWD operations are run out of a Beacon center. Technology is no longer an obstacle but the business case is ‘harder to see from the service side.’ Russ Spahr (ExxonMobil) described the digital ‘endgame’ as being about improved reliability, more uptime and about working with partners of choice to improve recovery. Integrated operations for Exxon are about blending expertise, process and technology and again, only 5% about technology. Digital needs to be placed in the context of the bigger picture which, for Exxon, is about ‘applying the right technology to the right asset.’ This is the real challenge because ‘digital is chasing the same barrels as other asset management processes.’ Exxon has twenty production management best practices along with supporting change management processes. The long term is also important, ‘You need to think through how to staff up for the next decade, what will be needed by the business, back room, networks, etc.’ Exxon is also keeping a focus on some R&D activity and proprietary technology ‘where it makes sense.’

John Brutz described Shell’s goal of constant, routine surveillance to highlight production anomalies from its Gulf of Mexico operations. Shell’s ‘graying’ workforce is at odds with a portfolio of greenfield and ‘end of life’ project that are people intensive. Shell has deployed an advanced alarm tool from Matrikon to flag anomalies for technicians and engineers. The SharePoint-based Central Surveillance Center (CSC) is a service that Shell has carved out of from its assets and centralized. A typical CSC use case is pressure transient analysis. While this does need local knowledge, a lot of preparatory work (populating software etc.) can be automated in the CSC. Other CSC uses include ‘operating envelope’ (well) surveillance and subsea flow line surveillance. These are backed up with rigorous ‘who does what’ documentation. Booz & Co also helped with change management.

Jim Hoffman (Occidental) reported on a trial of SharePoint TeamSites’ Wiki component. ‘OxyPedia’ is an employee knowledge base to which all have read/write access. A proof of concept used data from Oxy’s Elk Hills asset. This has 300 employees and 20 contributors to the Wiki. The results are promising. The tool was described the tool as ‘a godsend’ by one user. OxyPedia is now going world-wide.

John Hudson outlined how Shell is using ‘Lagosa’ to improve production operations and gas marketing. Lagosa is a SharePoint-based system that rolls-up components including Honeywell’s Unisim and Prosper from Petroleum Experts. Lagosa has been deployed at Shell’ Bacton (UK) terminal to mimic control system operators’ manual actions and on Sakhalin II to integrate information from well head to onshore processing facility. Exceptions drive Lagosa workflows. Shell gets subject matter experts to explain how they know when the model is not giving correct result. The results are analyzed and embedded in the model. Operators try to ‘crash’ the plant in simulation mode, e.g. by running for a long time at a low rate, then ramping up fast and putting a pig in the line! Today Lagosa is used by the ‘rich kids,’ i.e. Shell’s major projects. But the toolset is being simplified for deployment across all assets.

Russ Spahr was back with an in-depth look at what digital oil technology means to an integrated oil company. Exxon currently runs ten advanced visualization centers, a large drilling information management facility in Houston and other digital stuff—for surveillance, downhole control, 4D seismic, gas lift and process optimization. Exxon has developed a systematic approach from hardware to automation, passing through standardized data management collaboration and automation. Exxon deploys a ‘Suitcase’ of real time tools, HSE, volumetrics etc. At the Kome control room in Chad, the Suitcase enabled rapid startup and now supports operator training and best practices. In 2004, Exxon chartered a new subsurface work environment that includes data access and a portfolio of approved applications all rolled into an integrated system. This is in the process of being rolled out now. Spahr offered some metrics on the effectiveness of digital technologies in Exxon. Use of an advanced visualization center, a ‘shared earth’ environment for geoscientists and engineers saved $10 million drilling costs on one field and contributed to the decision to forego an additional platform, saving a further $100 million. Remote real-time monitoring now happens on 75% of Exxon’s wells—with 20-30 monitored daily. A ‘fast drill’ process has led to a 57% average increase in performance. Improved reservoir modeling allows for fewer well tests. In the North Sea Exxon has leveraged communication and Petroleum Experts’ IPM model for debottlenecking and gas lift optimization. Elsewhere fiber communications enable high bandwidth connections between platforms and the FPSO. Platforms can be converted to remote operations and de-manned, reducing cost and risks. Surveillance is particularly important in the Canada tar sands play where data mining and surveillance have identified work process efficiencies and minimized downtime.

David Feinman described how BP is ‘realizing the value’ from real time well monitoring in its greenfield assets. The year before and the first six months of production are critical in a field’s development. In 2006, BP rolled out its ‘ISIS’ real time well monitoring program and found that adoption was easier in greenfield sites. Cross cultural change management is a major concern. BP has encountered issues with authority, status, individualism (US and UK employees) vs. collective (Indonesia, Angola). Now, ‘systems thinking’ and peer learning are incorporated into rollouts—allowing for fine tuning with regard to local differences. Angola was the first greenfield site to benefit with Portuguese localization. Next Indonesian greenfield gas fields were rolled out with Bahasa language support. Greenfields are generally more amenable to real time well monitoring and they can quickly ‘leapfrog’ brownfields in knowledge management. BP is now trying to understand why and figure out how to replicate this ease of rollout in brownfield sites.

This article is an abstract from The Data Room’s Technology Watch from the 2009 DEC. More from tw@oilit.com and www.oilit.com/tech.

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