The SPE is in excellent financial health with some $57 million in total assets and net income of almost $ 5 million for the year ending March 2005. The ACTE is commensurately grandiose with over 500 papers and, this year around 8,000 attendees. Outgoing president Giovanni Paccaoli reported massive membership growth to a global total of 64,000. As a not for profit, the SPE ‘redeploys’ all of the $2.8 million revenue from meetings to its distinguished lecturer program (there are currently 33 distinguished lecturers) and the online resources of spe.org. Some 2% of the SPE’s reserves are set aside for ‘innovations’ such as a new magazine for young engineers—The Way Ahead.
Incoming president Eve Sprunt reflected on current public perception of the oil business as a ‘sunset industry that pollutes.’ A perception that is adversely affecting recruitment—and one that needs to be redressed. Sprunt suggests talking to your children, other family members and friends to correct such perceptions.
10 year plan
Under Sprunt, the SPE is to kick-off a ten year plan with, inter alia, the aim of producing a ‘single set of reserves best practices’, bringing together the UN, the SPE and the International Accounting Standards Board’s work. The SPE will create new programs to address gaps in its continuing education program and will build the spe.org website, which, Sprunt insisted, ‘must break even financially’ (spe.org caused a $1.1 million write-down in last year’s accounts). Other key programs are the e-library and technical publications—with plans to reach out to other orgs—and a new SPE women’s professional network.
Russell Foreman’s paper covered BP’s web services-based Real Time Data Architecture Project (RTAP). Web services are ‘untangling the spaghetti’ of a multiplicity of data sources and applications where ‘IT has become the bottleneck.’ BP launched RTAP in 2003 (OITJ Vol 8 N° 12). RTAP includes a US onshore project that wraps legacy data sources such as P2000, SAMS, WonderWare, Oracle to client tools such as Microsoft Office and Matrikon’s ProcessNet. The system has been rolled-out at 30 locations. Foreman commented that, ‘We have yet to find a legacy system that was so ugly that we couldn’t wrap it!’ Foreman warned that because everything is so new there are few truly standard definitions. Problems were reported with ‘boxed’ WS solutions from SAP and others.
Cynthia Rees explained how ExxonMobil plans to ‘significantly’ improve its subsurface work environment by the year 2010 by adopting a global functional organization and global standards. The project, Exxon’s ‘EM2010 Vision’ comprises three components: the Technical Computing Systems for engineers, a ‘WellWork’ data and process management (the subject of Rees’ talk) and the RETR interpretation methodology presented at the Calgary AAPG earlier this year (OITJ Vol. 10 N°7/8). WellWork is built on Peloton’s WellView application which Exxon has been using since 1996. Originally just a well sketch tool; WellView has evolved into a complete well data system. WellWork is the most widely used application in Exxon with 18,000 operated wells and 500 users.
Ron Cramer (Shell Services) presented a new initiative to establish a standard, ‘PRODML’ to underpin the ‘digital oilfield’ concept. PRODML has backing from BP, Shell, Chevron, ExxonMobil, Statoil, Weatherford, Halliburton, Schlumberger, PETEX, Invensys, Microsoft, OSI Soft, Sense Intellifield, Kappa, TietoEnator and POSC. Scope of the new standard is the process control domain but the group intends to ‘keep out of SCADA.’ XML will work upstream of the data historian and will initially focus on gas lift optimization. The PRODML group is ‘in phase’ with the process control SP95 standard - but the latter is more relevant in the context of the factory. Harmonization is also being sought with the existing ProdML Norwegian production reporting standard. Once developed, POSC will be the ‘custodian’ of PRODML – due for publication in August 2006.
James Crompton (Chevron) described the digital oilfield’s impact on the petroleum engineer’s workflow. The challenge of the digital oilfield is linking across the traditional ‘silos’ of drilling, completion, petroleum engineering, surface facilities etc. Fields are designed statically, but production is a dynamic process and after a few years, ‘debottlenecking’ is usually required. We still reacting to ‘red lights’—we don’t see the yellow lights. ‘Digital Oil’ is a huge opportunity to leverage reservoir surveillance, well performance etc. Today it is easier to acquire more data by adding measurements (tags). One major West African development has 30k tags already - and a lot of analysis capacity. But the real problem is the information ‘pipeline’ between data collection and analysis. Who owns it, what is possible, what is affordable. Evaluating new technology is also getting harder. Crompton suggests a metric of return on technology deployed (ROTD), and asking vendors to ‘prove that your technology is better than my spreadsheet.’
i-Field asset management
Trond Unneland (Chevron) stated that our ability to measure is much greater than our ability to use data. In general, data is ‘weakly exploited and poorly managed.’ Tools, especially spreadsheets, are unsuited to real time. In answer to a survey of i-field technology, Chevron’s assets teams responded, ‘do not give us more data!’ So Chevron is trying to make the oilfield more like a factory, as the refining business has been doing for a decade or so. Chevron is creating a business case for a multi-well instrumentation program designed to minimize lost or deferred production, to accelerate first oil, avoid contractual penalties and to increase recovery. Chevron has already kicked-off several autonomous i-field R&D initiatives including ‘RTPRO’ (with Schlumberger) for visualization and modeling of real time data. Other initiatives target the application of artificial intelligence to production optimization, an ‘Asset Decision Environment’ for control rooms (with SAIC) and the CiSoft training program with the University of Southern California. (OITJ Vol. 8 N° 9). Chevron’s de-centralized organization means that such initiatives ‘can’t be forced down assets’ throats’. The solution? Encourage local i-field projects like continuous compressor optimization on the East Texas Carthage, heat management and resources optimization on the San Ardo field in California and a holistic approach to production management on the North Sea Captain field. Here the aforementioned Asset Decision Environment is used to support voidage and water management. Chevron’s partners in the i-field include Schlumberger, SAIC, Norwegian EPSIS and Microsoft. Unneland didn’t say what Microsoft’s take was on ‘eliminating’ the spreadsheet from production engineering!
Eric van Oort described Shell’s real time operations center (RTOC) in New Orleans. The business driver for the RTOC is the fact that operators waste a lot of money on non-productive time in drilling. IT is now so good that you have to capitalize on the possibility for remote control and optimization of operations that the RTOC offers. The RTOC is a Shell/Halliburton joint venture with 20 staff and 24x7 operations. RTOC staff is made up of software (application) specialists and Shell’s drilling engineers. The RTOC has managed up to fifteen concurrent rig operations including global ‘big cat’ wells. Global reach is achieved with regional hubs and satellites. The RTOC has helped Shell cull best practices from around the world and to react to emergencies such as an abnormal pressure situation with a cross-discipline team. To avoid the ‘big brother syndrome’ whereby the RTOC is perceived as an ‘expensive intrusion’ by local operators, Shell rotates field staff through the RTOC. That is they did, until Katrina. Today the facility has been abandoned pending relocation to Houston.
Drill pipe data rates
Li Gao (Halliburton) presented a succinct analysis of data rates that could be achieved using acoustic transmission up the drill pipe. Current mud pulse technology can attain 2 to 10 bits per second (bps) but operators want to send more data up the drill pipe. By using state-of-the art Discrete Multitone Demodulation, transmission rates of several hundred bps are achievable.
SPE for managers
Ahsan Rahi from Schlumberger’s Integrated Project Management (IPM) unit proposes a scoring model for project complexity and risk. Projects may be complex but not risky and vice versa. Understanding such project metrics can help manage and mitigate project risk and also be used to assign project managers from the ‘HR pipeline’. Risk can also be transferred during project negotiations. A ‘bubble map’ of profitability in risk/complexity space proved ‘very insightful’ and has helped Schlumberger and its clients to mitigate these factors.
This article has been abstracted from a longer, illustrated report from the SPE ACTE, produced as part of The Data Room’s Technology Watch reporting service. For more on this subscription-based service please visit oilit.com or email firstname.lastname@example.org.
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