No abstract

The Terra Nova Oilfield located offshore Newfoundland, Canada, is currently under development according to a subsea layout with 4 "drill" centres and a floating production storage and offloading (FPSO) vessel. First Oil is planned for mid 2001. The base case reservoir development requires a total of 24 development wells plus flexibility to develop additional upside potential. Reservoir flexibility management requires waterflood and gas injection capability. The options of changing to water-alternating-gas (WAG) later in field life as well as converting certain producers to injectors are also a feature of the reservoir management plan. The development plan requires that 6 wells be pre-drilled prior to the arrival of the FPSO vessel. Results from these wells have confirmed the vertically layered reservoir and the need for horizontal as well as vertical and highly deviated wells. The presence of faults that potentially may ompartmentalize the reservoir has resulted in a development plan where the early wells are laid out as producer - injector pairs within individual fault blocks. Each fault block has been designated for either gas injection or water flooding. However, as new information about the reservoir, its geology and degree of compartmentalization becomes available through the drilling of the development wells and early production experience, the location and type of later wells will ensure that the all parts of the field are being produced in an optimized way. Introduction The Terra Nova Oilfield is situated offshore on the Grand Banks, 350 km east-southeast of St. John's, Newfoundland, Eastern Canada (Fig. 1). Water depth in the area is about 95 m. The field is estimated to contain over 150 million cubic meters (one billion barrels) of oil in place, of which around 58 million cubic meters (370 million barrels) are expected to be recovered. Based on a daily production rate of up to 23,850 cubic meters (150,000 barrels) per day, the field would produce for about 12 to 15 years, beginning in mid 2001. Terra Nova was discovered in 1984 with the drilling of the K-08 discovery well. A total of nine wells were drilled in and around the field between 1984 and 1988. Terra Nova is the second major oil field discovered on the Grand Banks, the first field being Hibernia which was put on production in 1997. In August 1996 a Development Application for Terra Nova was submitted to the Canadian-Newfoundland Offshore Petroleum Board (C-NOPB). The application outlined a subsea development with up to six "drill" centres and a Floating Production Storage and Offloading (FPSO) vessel. A total of 32 development wells was included for the delineated area of the field, covering both producer and injector wells. It was anticipated that 10 wells would be drilled and completed before production of First Oil. The selected facility had flexibility to develop additional upside potential in the field provided by non-delineated areas, and another 12 wells were foreseen for these areas.

Summary. The Frigg field is a major North Sea gas reservoir composed of turbiditic sediments. This paper describes the detailed geologic modeling and three-dimensional (3D) reservoir simulation of the field.A geologic model containing sand lobes and intercalating shales has been defined from seismic and well data. Special attention was paid to the realistic modeling of the shales. The more continuous (deterministic) shales between the turbiditic sand lobes of the reservoir were directly implemented in the model as horizontal flow barriers. The more discontinuous shales within the lobes were modeled with the method of Haldorsen and Lake and Begg and King. This method uses statistical geologic information and well data to calculate effective vertical permeability. The simulator was built as a 3D, two-phase (gas/water) model. Field data for 8 years of production were matched. A good match of both fluid levels and pressures was obtained. This reservoir study demonstrates that the impact of the shales on the reservoir behavior in general and the movement of the gas/liquid contact (GLC) in particular is essential. Introduction The Frigg field straddles the Norway/U.K. boundary in the northern North Sea (Figs. 1 and 2). Discovered in 1971 and brought on stream in 1977, the field is unitized and jointly owned by the Frig-U.K. Assn. (Elf U.K. and Total Oil Marine and the Frigg-Norwegian Assn. [Elf-Aquitaine Norge (operator), Norsk Hydro, Total Oil Marine Norsk, and Statoil]. Top reservoir is at about 1790 m [5.875 ft] mean sea level (MSL). The gas has a maximum column of 160 m [525 ft] overlying an ∼ 2- to 10-m [∼ 6.6- to 32.8-ft] -thick oil rim. Gas initially in place was illustrated at 265 × 10(9) std m3 [9,360 × 10(9)scf] before unitization in 1976. Initial model studies assumed a homogeneous sand reservoir with local occurrences of shale and limestone (Fig. 3) A tuff and shale layer separating the Frigg from the Cod formation, well below the GLC, was considered the only barrier for flow in the reservoir model. That this barrier had to contain permeability windows could be deduced from the active aquifer response during the production phase.GLC movements in the first observation well, Well 25/1-A22, did not give rise initially to drastic changes in the basic concept of the reservoir. However, results of the second observation well, Well 10/1-A25, which was deepened in Aug. 1984. demonstrated an ∼40-m [∼130-ft] -higher rise in GLC than observed in Well 25/1-A22. Furthermore, repeat formation tester (RFT) data of this well showed a pressure step over shales above the assumed tuff and shale barrier and no pressure step across the "tuff zone" itself (Fig. 4). This indicated a more complex, dynamic behavior of the reservoir than originally anticipated. An intensive appraisal involving the drilling of three remote appraisal wells (Wells 1011–5, 25/1–7, and 25/1–8) and the deepening of two platform wells was consequently undertaken. The planning of a 3D seismic survey was also initiated. The presence of shales in the Frigg formation that varied in lateral extent, forming horizontal flow barriers, appeared to be the main cause for the complex behavior of the reservoir. At the end of 1984, Norsk Hydro initiated the independent study described here to model and to simulate the effect of these shales in the Frigg reservoir. This 3D simulation study was concluded in Sept. 1985 and incorporates the results of all recently drilled remote appraisals and the deepening of Well 25/1A 14. A combination of direct and statistical methods was selected for the modeling to reflect the impact of the shales. Note that the geologic complexity combined with relatively sparse well spacing gives room for many uncertainties. For this reason, the interpretation presented here should also be seen as Norsk Hydro's own. among others. Note also that the field operator and the other Frigg partners are still conducting substantial studies. Theoretical Concept The basic philosophy behind the theoretical concept of this study is defined as follows. The complete incorporation of the effects of contrasting lithologic units is essential for reservoir simulation. Consequently, realistic estimations of occurrence and geometry of these units have to be made when data are not sufficient to define all units separately. Application of this philosophy will improve consistent incorporation of reservoir heterogeneity, which is often neglected when only the correlatable events/units are represented in the model. It will consequently yield a more realistic production forecast on a field scale. The situation in the Frigg field was typical for the application of the stated philosophy because insufficient data were available to define all contrasting lithologic units (sands and shales) separately at the time the study was initiated.A combination of direct and statistical methods has been selected for the modeling. The more continuous shales at the boundaries of the reservoir units (lobes) were modeled directly as vertical transmissibility barriers. They are classified here as deterministion shales. Their mapping, involved much postulation, however, because of a lack of data. The less continuous and uncorrelatable shales within the reservoir units (lobes) were handled statistically and are classified as stochastic shales (Fig. 5). Concepts based on the ideas of Haldorsen and Laker and Begg and King' were used for the statistical handling of the stochastic shales. In fact, a modified version of the Begg-King streamline method was applied. SPEFE P. 493^

The giant Troll Gas Field is located offshore Norway in water depths of 315–340m. Hydrocarbons are trapped in a shallow Upper Jurassic reservoir sequence comprising sands of excellent reservoir quality. The structure is subdivided into three large eastwardly dipping fault blocks. each with an underlying oil rim of varying thickness. A development plan is approved for the western most fault block area (Troll West Oil Province), which has the thickest oil rim (22–26m). The plan encompasses an extensive subsea development, based upon 18 horizontality completed production wells, the first of which will be drilled in early 1994. During the past years, Norsk Hydro a.s have through integrated production geology evaluations, reservoir simulation studies and Iongterm horizontal well testing, both proven the producibility of these thin oil rims, and identified the critical elements of a successful horizontal well. The current production geological efforts are directed towards effective geophysical, geological and petrophysical modeling of the reservoir package, to reduce the uncertain y associated with mapping of the location and geometry of high permeability sands within the oil column. This has involved increasing utilization of the extensive high frequency 3-D seismic datasets. Uncertainty will not be removed by adopting such techniques, so to quantify and understand the remaining uncertain y, stochastic modeling of the reservoir heterogeneities has been conducted in parallel with deterministic modeling. Evaluation work also continues within the Troll West Gas Province fault block (12–14m oil rim). in an effort to prove The commercial potential for an additional 25–30 horizontal/ Producers. 1 INTRODUCTION The Troll Field is located offshore Norway, in water depths of 315 to 340 m, some 100 km north of Bergen as shown in fig. 1. The field stretches into 4 Concession Blocks and comprises 2 Production Licences; i.e. Block 31/2 awarded in 1979 under Licence 054 with A/S Norske Shell as operator and the Blocks 3113, 3115 and 3116 awarded in 1983 under Licence 085 with Statoil, Saga Petroleum a.s and Norsk Hydro a.s as joint operators. Other participating companies are Conoco Norway Inc., Elf Aquitaine Norge A/S and Total Norge A/S. The individual shares of the participating companies were unitised in 1986 on the basis of Troll as a single field. The Troll Field is a major gas accumulation with considerable volumes of oil located in thin oil rims between a large gas cap and a large aquifer. It can be separated into three major provinces:Troll West Oil Province (TWOP) Gas accumulation with an oil rim of 22:26 mTroll West Gas Province (TWGP) Gas accumulation with an oil rim of 12-14 m.Troll East (TE) Gas accumulation with an oil rim of O -4 m. The outline of the provinces and the distribution of hydrocarbons in place are shown in fig. 2.