Abstract The growth in estimated ultimate recovery ( EUR ) of oil and gas fields over the course of their development has been recognized as a significant contributor to hydrocarbon supply, both in the United States and abroad. Data on changes in EUR have been examined for oil and gas fields discovered on the modern shelf of the Gulf of Mexico, in order to empirically determine the possible causes of these changes. Using a semilog regression model of EUR as a function of years since discovery, from 1975 through 2002, roughly half of fields in the study area grew and the balance either shrank or remained statistically unchanged. Fields that grew were typically large discoveries to start and the volumes by which they grew were log normally distributed. The fields making the largest contributions to aggregate growth typically had at least 20 reservoirs over at least 5,000 feet of charged section, which was deposited in generally prograda-tional environments at sediment accumulation rates between 500 and 2,500 feet per million years. The principal mechanism of field growth in the study area was through the discovery of new reservoirs. In the fields having the largest growth, these discoveries occurred in cycles based on stratigraphic interval. Within each cycle, the largest reservoirs were discovered early and the size of reservoir discoveries declined exponentially. Up to four major stratigraphically based cycles were observed; generally, but not always, each subsequent cycle added a smaller volume to EUR than those that preceded it. A secondary source of growth arises through the combined effects of recognizing an increased volume of reservoir rock containing reserves and improvement in recovery factors. The contributions of these mechanisms have been examined through analysis of single-reservoir fields and growth in fields after their last new reservoir discovery. Field growth is tied to the economic conditions surrounding oil and gas production. From the mid-1970s through mid-1980s, during a period of rising and high prices, large increases in oil and gas reserves were gained through new field discoveries, discovery of new reservoirs within fields and, to a lesser extent, positive reservoir volume revisions and increases in recovery factors. Price collapses in 1986 and again in 1998 are both reflected in reductions in field growth and actually declines in aggregate EUR . Although a short time series, EUR growth between the beginning of the current price recovery in 1998 and 2002 indicates that supply of new oil and gas in existing fields is becoming more inelastic. This is most probably due to two factors: depletion of the growth potential of old, very large fields; and because of the progressive decline in the sizes of new field discoveries and the high correlation between size and growth, as newer finds have smaller growth potential.

Abstract Schiehallion is a two billion barrel deepwater clastic reservoir, situated on the Atlantic margin of the UKCS , one of the world’s most hostile environments for hydrocarbon production. The field has been developed via subsea wells tied back to an FPSO , and is one of the first developments of its kind anywhere in the world. The field may be characterized as high productivity but low energy and, as a consequence, water injection is essential to maintaining production. However, the reservoir is channelized, faulted, and has varying degrees of connectivity between the compartments, so that a good understanding of these factors is necessary to optimize the water injection distribution. Our understanding of the ‘plumbing’, or connectivity between the wells, has evolved and matured over time, using a wide range of different data types, from the initial extended well test, through RFT’s , pressure transient analyses, interference testing, PLT’s , tracer and geochemical sampling, to bi-annual 4D seismic surveys using increasingly sophisticated processing and interpretation. Much of this understanding has been incorporated in a 3D model, which uses object modeling and seismic conditioning to represent the sand distribution. Potential barriers to flow are identified from seismic coherency analysis, and the strengths of these barriers have been used as the main history matching parameters. A key learning has been that all data needs to be interpreted with great care, and it is essential to integrate several data types in order to obtain reliable conclusions. The paper gives examples of data which has been invaluable, as well as examples where the data is ambiguous or misleading.

Abstract The Ormen Lange gas field, discovered in 1997 (Hydro operated License PL209) in 1000 m (3,281 ft) water depth and covering an area of ca. 350 km 2 (217 mi 2 ) was further appraised by four wells prior to development approval in April, 2004. The partnership, Hydro (development operator), Norske Shell (production operator), Petoro, Statoil, ExxonMobil, and Dong, had a planned production-start in October, 2007, from 8 of 28 possible production wells in a staged development using four subsea templates. The development faced a number of challenges; rough seabed topography, subzero sea bottom temperatures, harsh ocean conditions and a change of operatorship at production start-up. Reservoir characterization of the areally limited, but intensely faulted turbidite reservoir has formed an integral part of the work flows. These work flows address the uncertainty of vertically and horizontally connected reservoir volumes for productivity at well targets. Model scenarios have been constructed in a 3D visualization environment where optimal integration of a multitude of seismic data volumes, derived attributes, and geological model concepts has been achieved. The roughly polygonally distributed faults are not expected to be sealing; having developed close to sea bed, their origin rules out cataclasis and cataclasis-enhanced cementation. The common gas gradient and absence of measurable depletion during well tests support non-sealing faults and vertical connectivity. However, dynamic fault seal uncertainties related to reservoir heterogeneity and compartmentalization have necessitated risking the relatively simple tank scenario and a more cautious, stepwise approach for the development concept. A significant opportunity can be realized if the gas can be produced profitably using only three templates.