PETEX 2010

OSPRAG and the UK North Sea post Macondo, Statoil and WoodMac on shale gas, Integrated asset modeling and a call for more ‘robust’ and transparent production forecasting.

Petex, the biennial conference and exhibition of the Petroleum Exploration Society of Great Britain1 saw around 100 exhibitors and 2,500 registrants for its 2010 edition last month. Mark McAllister, chair of the UK Oil Spill Response Advisory Group and CEO of Fairfield Energy presented the UK’s response to Macondo. Preventing such incidents requires cooperation between trades unions, operators and contractors. OSPRAG has four sub groups—Technical (well design, inspection and control, first response), Spill Response (response capability and remediation) and Financial & Insurance (liability, indemnity and insurance provisions). The group is also looking at North Sea-wide regulations and response mechanisms. OSPRAG has developed a well capping device. A test of a national contingency plan is slotted for May 2011.

Malcolm Brown, Senior VP Exploration with BG Group, pondered on the new ‘giants’ of the 21st century—shale gas, cretaceous fans, rift plays, pre-salt and coal seam gas. US shale gas is ‘developable’ at $5/Mcf. In the session on unconventionals, Statoil’s Iain Scotchman related its $ 3.3 billion deal with Chesapeake. This covered some 1.8 million acres of the Marcellus shale in Pennsylvania, West Virginia and New York states. Initial large gas flows of up to 10MMcf/day decline rapidly as free gas is replaced by the slower desorbtion process. Wells have an estimated productive life of 30—60 years with reserves in the range of 3 to 8 BCF per well. Scotchman observed, ‘To be successful, the play requires the continual drilling of new wells to replace those on the decline2.’ Technology-wise, 3-D seismic and micro-seismics ‘are becoming increasingly important in the locating of wells, avoidance of geo-hazards and frac monitoring.’

Rhodri Thomas (Wood Mackenzie) noted that the unconventional gas has taken off in North America and eastern Australia. The US ‘could now be self sufficient’ while in eastern Australia, the coal bed methane play has had a similar impact, albeit in a much smaller market. WoodMac puts European resource potential at 1,400 TCF—a potential made especially attractive by Europe’s high gas price. Subsurface ‘deliverability’ and ‘above ground factors3’ will hamper development. China is the next big unconventional playground.

David Aron (Petroleum Development Consultants) noted that the potential for integrating sub-surface knowledge and topside design has been recognized for years. Amoco used a two-phase gas reservoir simulator coupled to a surface network to manage production of a number of Southern North Sea gas fields. More recently, software has evolved from in-house developed tools to off-the-shelf software such as Petrel, Eclipse and other dynamic modeling tools such as HySys, Resolve and Prosper. Aron advocates deployment of such integrated software ensembles on a ‘parallel virtual machine’ (PVM). Schlumberger’s Open Eclipse provides the linkage between Petrel, Eclipse and the HySsys process simulator from AspenTech. Petroleum Experts also leverages a PVM to couple Resolve with Eclipse, Prosper and Gap and other tools. Elsewhere Halliburton’s Nexus simulator has been linked with HySys.

Such comprehensive integration creates new problems such as very large run times when models with a cell count are used, or when a large number of hydrocarbon components are modeled. Shell has worked around this by simplifying the models. Cross-discipline integration brings new communication problems between reservoir and facility engineers. ‘Process engineers are not used to dealing with uncertainty.’

Aron cited some strong claims for the financial benefits of the integrated approach. ENI reports that the integrated approach gave a 6.5% hike in produced oil thanks to better allocation of gas lift rates than was achieved by standalone reservoir models. Halliburton reported a 14.2% increase in oil production from integrated studies that ‘helped asset teams make optimum field development plans.’ Petrobras reported on use of a ‘next generation’ reservoir simulator and integrated asset optimizer to optimize a production platform’s location. The best case of 200 simulations showed an NPV that was 4.6 times that of the original location.

University of Edinburgh professor Ian Main believes that reservoir simulations should be subjected to testing against ‘publicly documented field data.’ These should be ‘blind’ tests conducted by a third party. Such an approach would reduce bias and provide concrete estimates of uncertainty. Until we know quantitatively how well current technology is faring, the utility of increasing the simulator grid-block count, better reservoir descriptions and improved history-matching cannot be judged. Main advocates using the same approach as is used by meteorologists to monitor the accuracy of weather forecasts. This has led to the development of the ‘statistical reservoir model’ (SRM).

The SRM uses production data and Bayesian information criterion to identify correlated well pairs. Bayesian dynamic linear modeling is then applied to generate a parsimonious model in which ‘only 5-25% of the wells in a field determine the rate history at each subject well.’ The method has been trialed on several North Sea fields. A blind test on the Gullfaks field (by Reservoir Deformation Research (RDR) found that 70% of the production figures for individual wellbores lay within the predicted 95% intervals. SRM sponsors include Amerada Hess, BG Group, BP, Conoco-Phillips, DTI, Kerr-McGee, Statoil, Shell and Total.

John Wingate described Baker Hughes’ new casing while drilling (CwD) technique that has been successfully used to drill and set casing in a 2,500 m well. CwD uses disposable polycrystalline diamond bits mounted on the casing string. 90% of the onshore well was drilled using CwD.

Adrock continues to vaunt the merits of its improbable ‘Lidar-like’ imaging spectrometer that uses ‘invisible laser light’ to identify subsurface lithologies. While the Petex paper did not make quite so strident claims for depth penetration as at Adrock’s 2009 EAGE presentation, the phenomenal claim that light reflections can be obtained at a depths of ‘up to 4 kilometers and beyond’ is repeated on Adrock’s Wikipedia page. More from

2 Why are we thinking, ‘Bernie Madoff?’
3 See (in French).

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