Abstract T his P ortion of the field trip features visits to the worldfamous Sterling Hill and Franklin mines, in northwestern New Jersey, and their respective mining museums. Although both mines are no longer in operation, important geologic features can still be observed. At the Sterling Hill mine, we will have the opportunity to see zinc ore in place, both in an underground drift and in the Passaic open pit; at Franklin the pit is filled with water and only disseminated mineralization is still visible. The Furnace magnetite bed will also be seen adjacent to the Franklin open pit, as well as a large postore minette dike. If time permits we will visit a surface exposure of the Zero Fault in Franklin, which is an important regional structure that cuts the Sterling Hill orebody.

Abstract The New Hope field is in southeastern Franklin County, 10 mi south and slightly east of Mt. Vernon, the county seat. Geologically, it is along the northern margin of the East Texas basin, 20 mi south of the Mexia-Sulphur Bluff-Talco fault zone. Although production history of the New Hope field dates back to the early 1940's, this paper is limited to a discussion of the geology and reservoir characteristics of the Jurassic Smackover Formation.

Abstract The Aetna gas field is in Franklin and Logan Counties, Arkansas. In 1955, Athletic Mining and Smelting Company drilled the No. 1 Mantooth, Sec. 15, T. 8 N., R. 27 W., as the discovery well for the deep Atoka and Morrow gas reserves. The wildcat was drilled to 5,700 ft and was a triple-zone completion. As of September 1966, a total of 57 tests had been drilled. Drilling depths range from 1,800 ft in the upper Atoka to 8,800 ft in the Morrow. Multizone completions are common throughout the field. The field produced 12,755 million cu ft of gas during 1965 and the overall cumulative total was 70.8 billion cu ft. The natural gas from the Aetna field is almost 98 per cent methane. Reserves of individual wells range from 1 billion to more than 25 billion cu ft. The horizontal field limits are not defined fully, although production on the west and northwest now has merged with development drilling from Peter Pender (T. 8 N., R. 28 W.) and the vast Cecil field (T. 9 N., Rs. 27-29 W.). Trapping is effected by structure, faulting, and stratigraphic pinchouts. The pre-Mississippian rocks have not been tested on the crest of the Aetna anticline.

Abstract The Talco oil field in northwest Titus and northeast Franklin counties, Texas, is located in the north-central part of the East Texas basin on a fault structure which comprises a part of the Mexia-Powell-Talco fault zone. Most of the oil produced from earlier discoveries along this fault zone, such as Mexia, Powell, and Wortham, came from the Woodbine sand. Although the Talco fault was mapped by surface geology as early as 1924, the W. B. Hinton et al. C. M. Carr No. 1, field discovery well, was not completed until March 13, 1936. This well established the first Paluxy production along this fault zone and proved the Paluxy formation to be a major oil-producing section in northeast Texas. A detailed description of the stratigraphy of the area is presented, which includes beds from upper Jurassic to lower Eocene in age. Data concerning the formations below the Paluxy were derived from several deep tests which were abandoned as dry holes. The structure at Talco is a crescent-shaped graben, approximately 35 miles in length, bounded by two nearly parallel faults. The faults have a maximum surface displacement of about 360 feet which increases with depth to more than 1,400 feet on the base of the upper Glen Rose. Early and long continued movement is indicated by a thickening of the late Comanche and early Gulf formations in the graben. The oil accumulation, which is trapped in upthrown Paluxy against the south or basinward side of the graben, underlies about 9,000 surface acres. It is 13¼ miles long and averages one mile in width. Closure on the base of the Goodland limestone, which occurs at the top of the oil column, is approximately 450 feet. The reservoir sands are generally variable in their development throughout most of the field. About one-fourth of the Paluxy section in the oil column is considered effective oil sand with an average thickness of 44 feet and an average porosity of 25 per cent. The average permeability is 2,460 millidarcys, ranging from a minimum of 100 to a maximum of about 10,550 millidarcys. Talco crude is brownish black to black in color, and the gravity varies from about 16º in the basal part of the oil column to slightly more than 25º at higher levels. An imperfect water drive and the greatly undersaturated condition of the crude oil resulted in a rapid decline of bottom-hole pressures, and it became necessary during the early life of the field to pump all wells. On June 1, 1947, there were 728 producing wells in the field with a total allowable of 24,579 barrels per day. Cumulative oil production to July 1, 1947, was 97,369,193 barrels.

Abstract The Elgin, Franklin, Glenelg and West Franklin fields lie approximately 240 km (150 miles) east of Aberdeen in Blocks 22/30b, 22/30c, 29/4d, 29/5b and 29/5c of the UK Central Graben. Franklin was discovered in 1985, Elgin in 1991, Glenelg in 1999 and West Franklin in 2003. Elgin is a complex faulted anticline comprising four panels, while the others are simpler, tilted fault block structures. The main reservoir is the Upper Jurassic Fulmar Formation shoreface sandstone, although the Middle Jurassic Pentland and Triassic Skagerrak formations have also been produced on Franklin. Initial pressure was c. 1100 bar (16 000 psi), with a reservoir temperature of around 190°C (375°F). Production wells are drilled from four wellhead platforms; all connected to a central process, utilities and quarters facility above Elgin. Gas and condensate production started in 2001 from six wells on each of Elgin and Franklin, with the plateau being extended by satellite and infill wells. The project remains the world's largest high-pressure–high-temperature development, requiring continued innovations in geoscience, drilling, completion and operations. Cumulative production at end 2017 is 886 Mboe, with estimated ultimate recovery around 1300 Mboe.

Abstract The Elgin–Franklin complex contains gas condensates in Upper Jurassic reservoirs in the North Sea Central Graben. Upper parts of the reservoirs contain bitumens, which previous studies have suggested were formed by the thermal cracking of oil as the reservoirs experienced temperatures of >150°C during rapid Plio-Pleistocene subsidence. Bitumen-stained cores contaminated by oil-based drilling muds have been analysed by hydropyrolysis. Asphaltene-bound aliphatic hydrocarbon fractions were dominated by n -hexadecane and n -octadecane originating from fatty acid additives in the muds. Uncontaminated asphaltene-bound aromatic hydrocarbon fractions, however, contained a PAH distribution very similar to normal North Sea oils, suggesting that the bitumens may not have been derived from oil cracking. 1D basin models of well 29/5b-6 and a pseudo-well east of the Elgin–Franklin complex utilize a thermal history derived from the basin's rifting and subsidence histories, combined with the conservation of energy currently not contained in the thermal histories. Vitrinite reflectance values predicted by the conventional kinetic models do not match the measured data. Using the pressure-dependent PresRo ® model, however, a good match was achieved between observed and measured data. The predicted petroleum generation is combined with published diagenetic cement data from the Elgin and Franklin fields to produce a composite model for petroleum generation, diagenetic cement and bitumen formation.

Abstract This paper highlights how a global approach to quantifying structural uncertainties has ultimately reduced overall structural uncertainty through improved seismic imaging, notably anisotropic pre-stack depth migration, in a structurally complex area. The Elgin/Franklin high pressure/high temperature (HP/HT) fields lie in the Central Graben area of the North Sea UK sector, c. 240 km east of Aberdeen. The fields are the deepest production in the North Sea and represent the largest gas condensate development in the world, with recoverable reserves estimated at over 700 × 10 6 BBL equivalent. The reservoirs produce from the Jurassic Fulmar shallow-marine and Pentland fluvial reservoirs at depths of 5100–5600 m subsea. Production from these HP/HT reservoirs (1100 bar/200°C) started in March 2001 and flows over 200 000 BOE per day from 12 wells. For this type of producing environment, the stakes are high for understanding uncertainties related to imaging. Improved fault imaging translates not only to reduced uncertainties in bulk rock volumes, and ultimately in-place hydrocarbon volumes but also to an increased understanding of the static/dynamic behaviour of the fields through better imaging of internal faulting. The application of various proprietary and contractor-based seismic depth processing since 1997 has allowed for a better understanding of structural configuration of the deep reservoirs. This rich processing history has provided the interpretation team with various processing volumes (isotropic Post-SDM, anisotropic Post-SDM and, most recently, anisotropic Pre-SDM) to allow a more complete understanding of the uncertainties related to different imaging approaches. Historically, the effects of anisotropy on vertical and lateral positioning were realized and a number of internal proprietary software tools were developed to quality control depth imaging processing. The 1998 Glenelg discovery southwest of Elgin Field was the focus for the initial anisotropic Pre-SDM study, which was later expanded to include the Elgin/Franklin fields area. This processing benefited from Total’s internal QC tools and a combination of additional data (e.g. walk-away VSP profiles with different orientations, long-offset 2D seismic data) which provided an optimum mix to derive and verify the anisotropic parameters for the velocity model. Overall, the new seismic data shown significant improvement over the previous time- and depth-migrated datasets, reduced uncertainty on internal and bounding-fault positions and allowed the observation of the vertical and spatial uncertainties attached to different migration approaches. This understanding of the variability in seismic imaging and its effects on the reservoir parameters and structural configurations in depth is used as an input to understand ranges of in-place hydrocarbon volumes, the potential of near-field exploration and future infill-drilling strategies.