GE Oil and Gas User Group 2010, Florence

GE Oil & Gas 2010 User Group meeting in Florence offered insights into GE’s approach to managing innovative R&D, Chevron’s mega projects, BP’s high tech and new trends in deepwater drilling.

President and CEO Claudi Santiago described 2009 as a ‘challenging year’ for GE’s Oil and Gas unit and for the industry in general. Demand was down and volatility affected investment decisions. 2010 is looking ‘encouraging’ as demand is ‘set to return to 2007 levels.’ The US rig count is up 37% since mid 2009 and E&P spend is up 10%. We now live in a ‘multi polar’ world with hydrocarbon demand growth coming from India, the Middle East and China. In 2020 China and India will consume the equivalent of all of Saudi Arabia’s production. Combine this with our currently depleting reservoirs means that we will need ‘five times Saudi Arabia’s oil production’ to satisfy worldwide demand. This opens up the market for gas as a ‘bridge fuel.’ But for this to happen, we have ten years to find ‘four times Russia’s current gas production!’

Working on mega projects inside and outside oil and gas GE has developed a process that ‘mitigates the risk of innovation.’ The process starts with customer ‘intimacy’ to ensure GE understands what’s needed. Next appropriate domain expertise is assembled from scientists, engineers and systems integrators. GE then leverages technologies from sister companies (notably aviation, converting jet engines for use as gas compressors). GE Oil and Gas plans to spend $500 million on R&D over the next three years and will also benefit from its parent company’s global $5 billion per year R&D spend.

Michael Illane (Chevron) described ‘mega project’ performance on the Gorgon liquefied natural gas (LNG) project where GE has captured around $2 billion of project value. Alongside the initial eight wells, each with a 65 ton subsea tree, there is an LNG plant on Barrow Island and the largest carbon capture and storage project in the world, complete with 4D seismic monitoring. Mega project issues include the impact of subsurface risk on topside design and the potential large cost of rework. ‘Dis-economies’ of scale are an unfortunate reality. Illane noted that engineering companies ‘don’t do a very good job of managing productivity.’ In a Canadian oil sands project, less than 50% of time is actually on the job. ‘We need to put more effort on analyzing and mitigating risk, particularly of high impact low probability events such as security and labor relations.’

Jackie Mutschler described the impact of new technologies on BP’s E&P challenges. These include thin beds, high pressure/high temperature wells, hard to image traps, seals as reservoirs and ‘access issues.’ Wide and multi-azimuth seismic has been a big breakthrough for BP along with ocean bottom seismic. On land, ‘independent simultaneous sweep’ seismic has brought a five-fold seismic productivity hike. In production engineering, ‘BrightWater,’ (a joint Nalco, BP and Chevron development) has been used successfully in Pakistan, Argentina and elsewhere to shut off bad water flood pathways and optimize sweep efficiency. BrightWater has added 500 million barrels to BP’s books at a cost of $3 per bbl.

More generally, BP’s Field of the Future is ‘transforming the value chain.’ BP’s Gulf of Mexico digital infrastructure (fiber) incorporates information with workflows and is ‘changing how people work.’ The ‘real time challenge’ is the hardest, BP has around two million data tags worldwide. Production data feeds into reservoir models along with data on well bore conditions and shape. BP’s ‘advanced collaboration environment’ (ACE) brings it all together. ACE is used in the North Sea to perform holistic model-based analysis of slugging issues. The Field of the Future program has added 30,000 bopd net to BP.

A combined ‘legacy’ Hydrill/VetcoGrey (now both GE) session conducted by Bob Judge and Jim Allison looked at trends in high-end drilling technology. GE’s kit was used in the current world water depth record of 3,051 meters. Ultra deepwater brings challenges of pressure, hydrostatic load, and bending load on the drill string. Wells are getting hotter (up to 500°F) and are encountering higher pressure formations. Deepwater day rates of $500k/day make rework and non productive time serious issues. One intriguing answer to ultra deep environments is ‘dual gradient’ drilling. A seabed-located unit and secondary riser system isolate the subsurface from the pressure of the drilling mud in the primary riser. Dual gradient drilling detects kicks sooner than surface systems. Elsewhere the combination of remote diagnostics and increasingly instrumentalized blow-out preventers and other subsea components is extending the digital oilfield concept to the seabed. More from

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