The debate over the peak oil theory revved up Thursday after Cambridge Energy Research Associates (CERA) and IHS Inc. said their indepth analysis puts the aggregate global decline rate at 4.5%, or only about half the 8% rate that many industry pundits have pegged.
The analysis did not include natural gas fields, but CERA is working on a companion study on North America, CERA Chairman Daniel Yergin said.
The CERA and IHS report, “Finding the Critical Numbers” used the IHS global database to analyze 811 separate oilfields, which comprise about 57% of worldwide oil production.
“Some of the more gloomy, pessimistic ‘peak oil’ views about the future of oil supplies that are current today result from an assumption of high decline rates,” said the report’s author, Peter M. Jackson, CERA oil industry activity director. “This new analysis provides the basis for more confidence about the future availability of oil.”
Yergin said CERA decided to take on the study — and controversy — because “this issue of decline curves looms quite large in the supply and demand curve, and we felt…it was our sense that a lot of numbers had been thrown around.” Jackson’s six-month study was to “actually ascertain what is the global oil decline number.” IHS has a database of information on about 24,000 different fields in the world.
“The absence of definitive, comprehensive analysis of production timelines and decline rates has led to widely differing estimates of the potential future availability of oil…an information vacuum that has contributed to the ‘peak oil’ theory of future liquids production capacity,” Jackson said. “We hope that this study will contribute to a more informed understanding of the issues, both below ground and above ground.”
Jackson explained that “getting this right, and understanding the underlying dynamics, are key because the amount of new oil supply that will come onstream to satisfy present and future oil demand depends to a large extent on a comprehensive understanding of annual decline rates of existing fields.”
Decline rates are a function of reservoir physics and investment strategies, and Jackson noted that “there is a general historical trend toward lower decline rates in recent years, which may be due to better reservoir management practices and the impact of new technology. In addition, because reservoir physics is only one of the key drivers, we would not expect to see a very rapid change in average decline rates in the future without a step change in technology or field development strategies.”
Where some analysts have pegged the decline rate “may be a function of the generally more rapid decline rates observed in small fields — increasingly being developed in mature non-OPEC countries — and the rise of deepwater projects, which tend to flow at high rates as a requirement of commerciality, but which also decline rapidly,” Jackson said. His study indicated only 41% of production is from fields in the database that are “beyond the plateau stage” and into the decline phase of their production lives.
Jackson noted that annual field decline rates may not be increasing, “but as a result of increased investment, improved planning and technology,” many fields may have their output prolonged, and “field life is very often longer than originally projected.” This finding compares with similar findings on North American unconventional gas fields, illustrated by studies indicating well output increases instead of declines in the Barnett Shale (see Daily GPI, Nov. 27, 2007).
According to the study, individual offshore fields are declining at a 10 % annual rate compared with 6% for onshore fields, and deepwater fields declined at 18% annually compared with 10% for shallow-water fields. The CERA analysis also found significantly different production patterns in large fields versus small fields. Typically, large fields build up over an average of six years, produce on plateau for seven years at 93% of their maximum annual production rate, and decline on average for more than 20 years. In contrast, small fields build up over an average of three years, produce on plateau for five years, and decline on average over more than 14 years.
Because large fields with more than 300 million bbl of originally present reserves represent more than 95% of the reserves and 86% of the production in the study data set, their lower decline rate and higher production level through extended decline periods “is likely to make a major contribution to overall future liquids production capacity,” the study noted. “It is likely, according to CERA’s analysis, that improved understanding of giant fields’ complexities and reservoir models over the course of long-life cycles has allowed late field expansion that has arrested decline and, in many cases, allowed production to increase significantly.”
The CERA study also highlighted other factors, in addition to field size, that influence post-plateau decline rates, which include reservoir characteristics, development location, regional setting and operational tactics. OPEC fields generally decline at a slower rate than non-OPEC fields, possibly in relation to basic geological differences, the relative size of OPEC fields, their locations, and perhaps production constraints set by the organization, CERA noted. Also, limestone reservoirs (more prevalent in OPEC) tend to deplete more slowly than sandstone reservoirs. Offshore projects, prevalent in non-OPEC regions, decline more rapidly than onshore projects.
“The results of this new study reinforce CERA’s existing bottom-up global liquids capacity model showing that liquids capacity of around 91 million bbl/d in 2007 could climb to 112 million bbl/d by 2017,” said Jackson. “This outlook is supported by a key conclusion of this study: there is no evidence that oilfield decline rates will increase suddenly. It is important, though, to continue to research and understand evolving decline trends and further develop insight into the declines.”
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