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Robson W.,Nexen | Siveter R.,IPIECA
Society of Petroleum Engineers - Carbon Management Technology Conference 2012 | Year: 2012

The effectiveness and efficiency of regulatory and other policy approaches intended to reduce the greenhouse gas emissions from transportation fuels can hinge on the fuel life-cycle analysis (LCA). Emerging regulation has raised urgent questions about both definition and evaluation of life-cycle emissions, and the effectiveness, efficiency and equity of regulatory approaches which use such analyses. This paper focuses on the LCA for transportation fuels from unconventional hydrocarbon sources and associated regulatory issues and implications, and examines these in the context of experience gained in the study of conventional hydrocarbon sources, biofuels, electric vehicles, and other alternatives. Critical issues arise in the regulatory use of life-cycle emissions analysis when comparing different types of fuels, for different types of vehicles, including: • Uncertainty in life-cycle emissions - Differences in estimates of the life-cycle emissions for one fuel can exceed the differences in estimates for different fuels; boundaries, accounting, aggregation and accuracy of LCA are each critical and determining issues in its application in regulations. • Flexible pathways - In order to incentivize innovation in fuel production, many pathways (with the ability to be altered) are needed to map production from each individual agent, who will each have their own process. • Energy security - Regulation to lower the life-cycle emissions is often also intended to improve energy security (e.g. by increasing supplies of indigenous biofuels); however, in the case of unconventional sources of oil such regulations may aggravate energy security. For complex policies, such as those involving LCA - especially where there are international ramifications - much broader dialogue is needed to improve the policy's effectiveness, efficiency and ultimately credibility. Copyright 2012, Carbon Management Technology Conference.

Gray F.D.,Nexen | Schmidt D.P.,CGGveritas | Delbecq F.,CGGveritas
Society of Petroleum Engineers - Canadian Unconventional Resources and International Petroleum Conference 2010 | Year: 2010

Parameters of interest in hydraulic fracturing are the principal stresses, hoop stress and rock strength parameters such as Young's modulus and Poisson's ratio. Modern seismic inversion algorithms allow us to extract rock strength parameters. We show that they can be estimated between wells from seismic data. The azimuthal response of conventional and/or multicomponent seismic data is related to the stress field of the earth. By combining these methods, the magnitude of the principal stresses and the directions of the horizontal stresses may be estimated and then, hoop stress and fracture breakdown pressure can be approximated. These estimates may be used to guide field development away from existing wells. Copyright 2010, Society of Petroleum Engineers.

Johnson B.A.,Nexen
Society of Petroleum Engineers - Canadian Unconventional Resources and International Petroleum Conference 2010 | Year: 2010

In developing the Doris Mannville Coal Bed Methane (CBM) gas field near Fort Assiniboine, Alberta, the Nexen exploitation team encountered many unforeseen artificial lift challenges using Electric Submersible Pumps (ESPs). High failure rates and short pump run times made forecasting of production volumes and reserves difficult, while high operating costs driven primarily by downhole servicing reduced the economic viability of the project. The root cause of the high pump failure rate was attributed in most part to the unanticipated volume of produced coal fines and reservoir solids in the produced water stream. The production of these solids, coupled with lower than expected water production rates, led to a re-evaluation of the field's artificial lift strategy. Following a thorough artificial lift evaluation, a change from an ESP to a reciprocating rod pump (Pump Jack) system was initiated. The largest anticipated benefit of reciprocating rod pumping systems over ESP artificial lift systems were: • Increased minimum flow path area through the system, reducing the frequency of solids plugging, leading to longer pump run times. • Reduced well servicing costs with reciprocating rod pumps through elimination of services required solely by ESPs. • Elimination of pump failures due strictly to electrical shortages by changing from an electrical/mechanical (ESP) to a straight mechanical (Pump Jack) downhole system. • Improved operating efficiency by matching artificial lift design with actual water production rates. The change in artificial lift strategy made an immediate impact on pump failure rates in the Doris field. This paper will present the resulting increased pump run times, sustained production rates and drastically lower operating costs that has made reciprocating rod pumping systems the artificial lift method recommended by Nexen to exploit Alberta's Mannville coal for CBM. Copyright 2010, Society of Petroleum Engineers.

Cockram M.,BG Group | Christensen A.W.,RMN | Thistle B.,Suncor Energy | Von Ochssee W.B.,Noreco | And 3 more authors.
SPE/IADC Drilling Conference, Proceedings | Year: 2013

When the operator embarked on an intermittent 5 well exploration, appraisal and development campaign offshore Norway between 2009 and 2012 using the West Alpha there were many challenges. The rig contract was part of a multi company consortium, the well program was varied, a 3rd generation semi submersible rig was being used and all inclusive operating rates were high at around $1,000,000 per day. Following and expanding upon the management principles previously employed 1, the lead operator identified an opportunity to leverage the consortium program and develop a strong relationship with the service companies, in particular the rig contractor. Health, Safety, Security and Environment (HSSE) was a key driver and over 1000 rig days were delivered without a Lost Time Incident (LTI). The lead operator was able to harmonise and standardise procedures used on every well, regardless of who operated the rig. This enabled a much clearer and more consistent message to be delivered to the work environment. This paper will outline the management process taken by the operator and contractor that enabled the following performance to be delivered: • 1000 days LTI free rig operations. • Record setting drilling performance with improvements up to 40%. • No damage to the environment. This paper will also describe how the principles have been transferred to other parts of the operators & contractors organisations. Copyright 2013, SPE/IADC Drilling Conference and Exhibition.

Orr B.W.,Nexen | Srivastava P.,Baker Hughes Inc. | Sadetsky V.,Baker Hughes Inc. | Stefan B.J.,Baker Hughes Inc.
Society of Petroleum Engineers - Canadian Unconventional Resources and International Petroleum Conference 2010 | Year: 2010

North America's long-term energy future depends heavily upon the Athabasca oilsands. Only 15% of these deposits are at mineable depths (<90m) and thus 85% of the oilsands (232 billion bbl recoverable reserves) must be recovered using in-situ techniques. Steam-assisted gravity drainage (SAGD) has become the method of choice for oilsand producers and it is therefore critical to optimize this process. Steam additives can improve recovery from the SAGD process. The additive, hydrocarbon or not, is soluble in bitumen at reservoir conditions and serves to decrease its viscosity, thereby increasing the production rate over a process driven solely by steam. This paper investigates several steam additive pilot projects with a focus on a project at Long Lake. Also, this paper discusses laboratory experiments involving a comparison of the performance of different hydrocarbon and non-hydrocarbon additives for assisting the SAGD process. Steam additives should be pursued because successful implementation would significantly improve profitability by accelerating production, decreasing water losses and decreasing steam requirements. Additionally this will address environmental concerns by decreasing CO2 emissions associated with steam generation using natural gas. If successful, these steam additives will also increase reserves both per well pair and on a total oilsands basis. Copyright 2010, Society of Petroleum Engineers.

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