Significant Hydrocarbon Accumulations Research Articles

Abnormal pressure regime in the former USSR petroleum basins

This paper represents a continuing attempt to summarize the large volume of geological and geophysical research on abnormally-high and abnormally-low pressures in different regions of the former USSR. There are many regions with abnormally-high and abnormally-low pressures. Examples can be found in the western, eastern and northern Siberia, Crimea, Caucasus, Caspian basins, Ukraine, Volga-Ural and the Timan-Pechora regions of Russia, and Sakhalin Island (Fig. 1). In these regions, the abnormal pressure is associated with significant hydrocarbon accumulations. For better understanding of abnormal formation pressures, it is necessary to conduct research on hydrodynamics and the origin of abnormal pressure. Based on observation of abnormal pressures in the former USSR petroleum basins, the authors present their theory on the origin of abnormal pressure.

Reservoir Characters of the Ypresian Carbonates, Western Libyan Offshore, Central Mediterranean Sea: ABSTRACT

Significant hydrocarbon accumulations have been discovered in Western Libyan offshore in the Ypresian carbonate reservoirs of Jdeir Formation and Jirani Dolomite. The discoveries of hydrocarbons are mainly in structural traps where the Jdeir nummulitic facies and Jirani dolomitic facies B have been structured by salt domes or underlying positive fault blocks. This study investigates the relationship between environments of deposition, diagenesis and reservoir characters of the two main hydrocarbon producing units of the Jdeir and Jirani formations. Petrographic and petrophysical studies indicate that porosity in the Jirani Dolomite is related to diagenesis in meteoric environments, while in the Jdeir reservoir is the result of the environment of deposition and diagenesis. Excellent reservoir porosity of Jdeir nummulitic facies and Jirani dolomitic facies B is related to diagenesis in meteoric water during exposure to subaerial conditions which is considered to be due to lowering of sea level and possibly local uplifting.

A case study of integrated hydrocarbon exploration through basalt

A large unexplored tectonic basin with the potential for significant hydrocarbon accumulations was identified in north‐central Oregon using a variety of geophysical techniques. The basin, informally named after the local town of Heppner, is covered by several thousand feet of Miocene Columbia River Basalt Group (CRBG) but is readily identified by a gravity low against the Blue Mountains Uplift. The Paleocene/Eocene Herren Formation (Pigg, 1961), which outcrops on the Blue Mountains Uplift south of the Heppner Basin, offered good source and reservoir potential. Based on lateral extent, thickness and paleocurrent structures in the Herren Formation, the unit was expected to be present in the basin. Gravity modeling produced nonunique interpretations, thus magnetotelluric (MT) information was used to constrain the CRBG thickness. Static shifts in the MT data were removed using transient electromagnetic (TEM) data before MT data inversion. After extensive experimentation, adequate seismic data were obtained for structural mapping, but the seismic data were interpretable with confidence only after MT determinations of the CRBG thickness. As a result of the favorable geologic and geophysical information, the ARCO Hanna ♯1 well was drilled to 9100 ft (2800 m) near Heppner, Oregon in section 23, T2S, R27E in 1988. The thickness of the CRBG and Oligocene John Day Formation were accurately predicted by the geophysical interpretations. An unanticipated thickness of Eocene Clarno Formation was encountered and drilling ceased in this unit. No Herren Formation was penetrated during drilling. Geophysical well logs indicate the Clarno Formation has densities and resistivities sufficient to account for the gravity and electrical anomalies defining the prospect. Poor seismic quality was explained by the heterogeneous nature of the pre‐CRBG volcanic section encountered in the well.

Yombo Field Exploration Model, Peoples Republic of the Congo, West Africa

Yombo field in the Congo is sourced from the lacustrine shales of the presalt rift stage and produces from the Albian and Cenomanian, postsalt, Sendji carbonate and Tchala Sandstone. The Yombo prospect exploration model included an upper Sendji stratigraphic trap with two components and a structural nose. The buried hill component of the trap is formed by topographic relief on the reservoir below the top Sendji unconformity. The lower Sendji slump blocks provide a high on which the upper Sendji grainstone shoal facies develop. Both depositional relief and erosion during the top Sendji unconformity contribute to the topography. An isochron thick in the overlying Tchala valley-fill sediments defined a drainage pattern on the unconformity around the buried hill of the underlying upper Sendji. The facies change component is formed by the pinch-out of the grainstone shoal reservoir facies into porous, but impermeable lagoonal dolomite interbedded with anhydrite and shale. Capillary pressure measurements on the 16% porosity, 0.1 md permeability lagoonal dolomite, along with pore throat radius and buoyancy calculations, demonstrated this facies could trap a significant column of low-gravity oil at shallow depth. The Tchala Sandstone contains several separate hydrocarbon accumulations. A stratigraphic trap in the lower Tchala is formedmore » by marine and tidal channel sandstones pinching out into lagoonal shales. The nearshore marine sandstones of the upper Tchala contain additional hydrocarbons in structural and stratigraphic traps. The stratigraphic pinch-out that cross the Yombo nose trap a significant hydrocarbon accumulation, even though the four-way structural closure is relatively small.« less

Jurassic Extension and Alpine Inversion of the Northern Morocco

The lower Mesozoic half grabens of northern Morocco form part of an extensional system that is related to the opening of the western Tethys. They appear to be somewhat younger than the Triassic-Jurassic systems associated with the opening the Atlantic Ocean. During the Tertiary and as consequence of the Alpine collision of Africa with Europe, these half graben systems were inverted as shown by the High and the Middle Atlas mountains. Seismic illustrations of similar but smaller inversion structures are available from the Guercif area and the [open quotes]Rides Prerifaines[close quotes] of northern Morocco. These seismic profiles serve as small models for the much larger Atlas Mountains. In the Guercif area, the inversions are limited in scope, but in the [open quotes]Ride Prerifaines[close quotes] are extensive decollement systems that sole out in the Triassic evaporites. These systems evolve into complex thrust faults and associated lateral ramps that are strongly influenced by the configuration of the Jurassic transtensional systems. Significant hydrocarbon accumulation have been known for some time from the [open quotes]Rides Prerifaines.[close quotes] A review of the geometry of the inverted half-graben systems, combined with detailed stratigraphic studies, is likely to lead to the discovery of additional reserves in themore » area.« less

Structural Development of Billings and McKenzie Counties, Southwestern North Dakota

Billings and southern McKenzie counties contain about 40 active oil and gas fields. In the same area, two major structural highs and several minor ones can be recognized. The Billings anticline extends approximately 60 km (18 mi) along a north-south line in central Billings County and is composed of two parallel folds. A second major structure, the Rough Rider anticline, lies west of the Billings anticline and also extends about 60 km (18 mi) along a north-south line from north-central Billings County into southern McKenzie County. Both of these structures are fault bounded on their eastern sides and are sites of significant hydrocarbon accumulation. Episodes of tectonic activity within the area were identified by study of isopach patterns derived from wireline log picks and by subsidence analysis. Although the subsidence of the Williston basin was the principal regional tectonic activity, the structural features in Billings and McKenzie counties were intermittently decoupled from the larger scale basin movement, producing local highs. The two major positive features, as well as several minor ones, have behaved independently of each other through time. Most of the development of these structures took place during the Devonian and Mississippian.

Structure and Hydrocarbon Potential of Sedimentary Basins of the Far East Marginal Seas: ABSTRACT

Crustal structural of the Bering, Okhotsk Japan, East China, and South China marginal seas consists of continental plates and deep sea basins that are the elements of the lowermost order in the structure of transition zone from the Asia continent to the Pacific Ocean. Two stages are recognized in the crustal evolution of the northwest Pacific transition zone: (1) geosyncline development that began in the pre-Paleozoic and continues to the present within island arcs; and (2) quasiplatform stage that began in the late Cretaceous and continues to the Holocene within shelf plates. The continental margins of the Far East seas consist of Cenozoic terrigenous cover and pre-Cenozoic basement composed of geosyncline rock association. Normal faults control graben features in the basement and develop rift systems. Paleogene subcontinental formations make up the lowermost section of the cover. A major Oligocene-Holocene sequence (marine formations) overlies and smooths rough topography of the basement and creates giant sedimentary basins. Sediment thickness of the basins attains 10 km. Tectonic evolution of the marginal seas implies the shelf plates to be young platforms and deep-sea basins are believed to be parts of the Pacific thalassocraton fenced by island arcs. The tectonic criterion enables us to differmore » and grade the provinces according to a hydrocarbon potential. Nearly 100 promising sedimentary basins are presently known in the Bering, Okhotst Japan, East China, and South China seas. About ten basins have been identified as hydrocarbon resources. Deep-sea basins also look promising for hydrocarbons. All the economically significant hydrocarbon accumulations in the Far East marginal seas are attributed to the Cenozoic sediment cover. Major resources are concentrated in the Miocene and Pliocene terrigenous sequences composed of progradation facies within the shelf plates.« less

A regional assessment of the intra-Carboniferous play of Northern England

Abstract Hydrocarbons have been produced from the Carboniferous of the East Midlands since the 1920s. Some 30 discoveries have been made to date and although field sizes are generally small, the relatively low costs have made exploration and development an attractive commercial proposition. Many of the factors which contribute to success in the East Midlands occur in other basins in Northern England but have not produced significant hydrocarbon accumulations. This paper examines the key attributes of the intra-Carboniferous play and through an integrated regional geological framework contrasts the successful East Midlands oil province with the other Carboniferous basins of Northern England.

Presence and Control of Evaporite Top Seals on Occurrence and Distribution of Hydrocarbon Traps: Main Fairway, Central Overthrust Belt, Wyoming and Utah: ABSTRACT

In the Central Overthrust belt fairway, there are 18 known productive formations ranging from Cambrian to Cretaceous in age. Four units - the Ordovician Big Horn formation, Mississippian Mission Canyon formation, Jurassic Nugget formation, and Jurassic Twin Creek Formation - account for 99% of a reported 1.4 billion bbl of oil estimated recoverable reserves discovered to date. A critical factor necessary for significant hydrocarbon accumulations is the presence of effective evaporite seals above these reservoirs. Major accumulations exist in anticlines associated with Paleozoic or Jurassic cutoffs in the hanging wall of the Absaroka thrust with recognized source rocks occurring in the Cretaceous footwall section. Vertical migration is required to source the overlying reservoirs. Migration pathways are via hanging wall cutoffs of these reservoirs or through fractures in the cores of the structures. Hanging wall reservoirs either lacking top seals or having top seals disrupted by extensive fracturing due to folding or faulting, permit vertical migration into higher, more effectively sealed reservoirs. In the Overthrust producing fairway, anhydrites of the Mission Canyon formation and Gypsum Spring Member of the Twin Creek formation as well as the Jurassic Preuss salt are the three effective seal units. Analysis of Overthrust belt traps suggestsmore » that the presence and ductile nature of these evaporite seals are important controlling factors for the significant hydrocarbon accumulations in this highly deformed terrain.« less

Source Rock Potential of Upper Devonian-Lower Mississippian Formations in Oklahoma and Western Arkansas: ABSTRACT

In central and southern Oklahoma, Upper Devonian-Lower Mississippian strata are rich oil source beds (mean = 7% TOC) at an early stage of generation. The major accumulations of oil in this region have been documented as coming from the Woodford formation. Equivalent-age source rocks in the deep part of the Anadarko basin have matured to or beyond the gas generation stage and significant generation is still occurring within parts of the basin. Around the Ozark uplift, age-equivalent rocks contain less organic matter (mean = 3.5% TOC) and more terrigenous clastic sediment than in central and southern Oklahoma. Both oil- and gas-generating types of kerogen are present and the organic matter has reached the early to main stages of oil generation. Upper Devonian-Lower Mississippian source rocks in the Ouachita core area are metamorphosed and no longer have significant hydrocarbon-generating capability. Age-equivalent rocks in the frontal zone are rich oil source beds at an early stage of generation. Significant hydrocarbon accumulations are possible at depth within the frontal zone and from frontal zone rocks that have been overthrust by metamorphosed Ouachita core-area rocks, particularly in the northwestern part of the Ouachita province.

Geology and Seismic Modeling of an Aneth-Type Desert Creek Mound Trend, Paradox Basin, Southwest Colorado: ABSTRACT

In the Paradox basin of southwest Colorado, a major facies change from thick, porous algal dolomite to thin, tight anhydrite occurs within the Desert Creek zone of the Pennsylvanian Paradox Formation. This northwest-trending algal mound belt is subparallel to and separated from the ancestral Uncompaghre mountain front by lagoonal anhydrite and nearshore arkosic fanglomerates. In the belt, carbonate rocks attain a gross thickness of 200 ft, which can include 100 ft of reservoir quality dolomite. These rocks have an updip and abrupt eastward facies change to thin evaporites that form a regional master trap for potentially significant hydrocarbon accumulations. Reservoir parameters and trapping mechanisms are similar to Utah's Aneth field, where oil production exceeds 340 million bbl. The subsurface stratigraphic changes have been seismically modeled with a microcomputer for the purpose of defining the extent of each facies. The modeling is based on sonic logs from two wells that exhibit the end-member facies of thick, porous dolomite versus thin, tight evaporite. An interpolation routine creates intermediate logs between these end-members, thereby defining the geometry of the model. The depth model is convolved with a zero-phase wavelet of 10/20-40-60 hz, and the result is an extra seismic cycle where reservoir thicknessmore » exceeds 40 ft. Updip loss of the cycle defines the transition from reservoir dolomite to trap anhydrite. The modeling demonstrates that this major facies change can be detected at frequencies reasonably attainable by modern seismic methods. Regional subsurface stratigraphic analysis and modern seismic data provide an integrated approach to hydrocarbon prospecting in the Pennsylvanian Desert Creek zone.« less

Future Prospects on Rawlins Arch: Modern Look at Oil and Gas Exploration in a Historic Area: ABSTRACT

The Rawlins arch in south-central Wyoming is a major north-south feature that is approximately 60 mi long and 20-40 mi wide. It is bounded by the Granite-Ferris-Seminoe Mountain uplifts on the north, the Medicine Bow-Sierra Madre Mountain uplifts on the south, the Hanna and Kindt basins on the east, and the Great Divide and Washakie basins on the west. Major tectonic events have occurred in the area during the Pennsylvanian, Jurassic-Cretaceous, and Late Cretaceous-Tertiary. Locally, evidence exists for structural deformation that predates the Cambrian. Significant production was established on the Rawlins arch in 1916, at Lost Soldier field, which has the highest recovery per acre of any Rocky Mountain oil field. Within the area, major exploratory efforts were made in the 1920s and 1940s. Since that time, little new exploration has taken place, although development and enhanced recovery operations are ongoing. The area is sparsely drilled and has the potential for significant hydrocarbon accumulations. Historically, fields were found by surface mapping, and involved structural closures. Recent discoveries include stratigraphic and subtle structural traps. Productive rocks range in age from Cambrian through Late Cretaceous, and include clastic and carbonate reservoirs with matrix and fracture porosity and permeability. Multiple source and sealingmore » beds, fault conduits, and sealing faults allow multiple pay zones. Drilling depths are relatively shallow, and few drilling and completion problems exist. Many pipelines afford good access to markets for produced hydrocarbons. All these factors make the Rawlins arch an attractive area for exploration.« less

North African Geology: Exploration Matrix for Potential Major Hydrocarbon Discoveries: ABSTRACT

Based on results and models presented previously, it is possible to consider an exploration matrix that examines the 5 basic exploration parameters: source, reservoir, timing, structure, and seal. This matrix indicates that even those basins that have had marginal exploration successes, including the Paleozoic megabasin and downfaulted Triassic grabens of Morocco, the Cyrenaican platform of Libya, and the Tunisia-Sicily shelf, have untested plays. The exploration matrix also suggests these high-risk areas could change significantly, if one of the 5 basic matrix parameters is upgraded or if adjustments in political or financial risk are made. The Sirte basin and the Gulf of Suez, 2 of the more intensely explored areas, also present attractive matrix prospects, particularly with deeper Nubian beds or with the very shallow Tertiary sections. The Ghadames basin of Libya and Tunisia shows some potential, but its evaluation responds strongly to stratigraphic and external nongeologic matrix variations based on degree of risk exposure to be assumed. Of greatest risk in the matrix are the very deep Moroccan Paleozoic clastic plays and the Jurassic of Sinai. However, recent discoveries may upgrade these untested frontier areas. Based on the matrix generated by the data presented at a North African Petroleum Geology symposium, significant hydrocarbon accumulations are yet to be found. The remaining questions are: where in the matrix does each individual company wish to place its exploration capital and how much should be the risk exposure? End_of_Article - Last_Page 271------------

Eolian Paleotopographic Highs as Stratigraphic Traps: Origin and Distinction: ABSTRACT

Significant hydrocarbon accumulations occur where eolian paleotopographic highs are preserved beneath transgressive marine deposits. Paleotopographic highs can represent erosional remnants of an unconformity, or partly preserved eolian dunes, or combinations of both. Paleotopography reflects the extent of modification undergone by eolian units prior to or during transgression. Modification varies between extremes of (1) destruction--where eolian deposits are deeply eroded and the former dunal profile is lost, and (2) preservation--where dunes and interdune areas are preserved nearly intact. The extent of modification that occurs during transgression is controlled primarily by (1) the energy of the transgressing sea, (2) the speed of transgression, and (3) the abundance of sand-stabilizing early cements or plants. High-energy seas destroy dunes through persistent erosion by tides and waves and by initiating dune collapse and mass flowage of dune sands. Preservation occurs where quiescent seas flood interdune areas and create shallow to periodically emergent marine environments, such as interdune sabkhas or tidal flats. Gradual filling of interdune areas with shallow marine sediments can fortify and preserve adjacent dunes. These varied processes that interact between marine and eolian environments to create different types of topography are exemplified in ancient eolian-marine sequences of the Western Interior of North America, and preserved Holocene dunes of coastal Australia. Different types of eolian highs can be recognized by analysis of bounding surfa es in outcrop or core. An understanding of eolian-marine processes and environments that create topography allows for prediction of areas of potential stratigraphic traps. End_of_Article - Last_Page 253------------

Petroleum geochemistry of the Southern Santos Basin, offshore Brazil

Significant thicknesses of hydrocarbon source rocks (up to 1000 m) were identified in 1–SPS–17, l–SCS–4A, –5 and –6, in the Southern Santos Basin. These marine shales of Cenomanian to Coniacian ages generally contain l–2.5% organic carbon. Pyrolysis maximum potential yields are moderate rather than good, averaging 3–4 kg hydrocarbons/tonne of rock over the hydrocarbon source intervals. Oil will be the principal product, although horizons of gas-prone kerogens are also present. Palaeotemperature indicators (spore colour and vitrinite reflectance measurements) show that the basin is characterized by relatively low maturation gradients; calculated depths to the oil generation threshold (OGT) range from c . 3600–4500 m. The identified source rocks generally lie within ±500 m of the OGT and the presence of 1000–1500 m of Miocene and later sediments therefore restricts the time available for significant generation and migration to, at most, about 10 Ma, i.e. from late Miocene onwards. However, a variety of basin models predict substantially greater maturities and, in some instances, suggest oil generation commenced in Palaeogene times. Direct measurements of evolved hydrocarbons give support to some of the modelling predictions by apparently demonstrating hydrocarbon evolution at depths less than the palaeotemperature OGTs. The absence of significant hydrocarbon accumulations is probably a function of inadequate source richness and the short time available for generation. Migration from thick shale source beds bounded above and below by non-generative shales may also be a problem.

Hydrocarbon source rock analyses of Pakawau Group and Kapuni Formation sediments, northwest Nelson and offshore South Taranaki, New Zealand

Abstract Gas-liquid chromatographic (GLC) analysis of cuttings and outcrop of Pakawau Group and Kapuni Formation sediments from the South Taranaki Basin gave thermal maturity and provenance results consistent with previous work in the region. Explanations were sought as to the origin of hydrocarbons already discovered, and the absence of significant hydrocarbon accumulations elsewhere within the basin. GLC analysis centred on the C15+ saturated hydrocarbon extract of rock samples, and geochemical fossil molecules were examined for their presence and relative abundance. Resulting information on the thermal maturity and provenance of the rock samples was obtained. Both Maui-2 and Maui-4 wells gave Odd Even Predominance (OEP) and Carbon Preference Index (CPI) values of 1.1 (±0.1) to 1.4 (±0.1), consistent with thermally mature sediments. Both showed pristane levels typical of land-derived sediments. However, Kupe-l well gave a CPI value of 1.7 (±0.1) which correlates with the early dry gas substage of the immature stage of hydrocarbon generation. Recent heat-flow studies in the region agree with this result. Brunner Coal Measures proved thermally immature and the Pakawau Coal Measures indicated an increase in maturity with depth.

Regional Tectonics and Petroleum Geology of Tunisia--Introduction and Overview: ABSTRACT

Tunisia can be divided into five tectonic provinces: (1) La Galite-Numidian zone, (2) zone of diapirs-Zaghouan fault, (3) Kasserine Island, (4) Gabes basin-Cretaceous platform-Offshore, and (5) Djefarra-Paleozoic complex. Thin-skin tectonics dominate the La Galite-Numidian zone. Perhaps as much as 20 km of shortening indicates that the best petroleum prospects may lie beneath the thrusts. Oil and gas seeps in Algeria suggest that lower Numidian clastics induce favorable hydrocarbon generating environments. In the Kasserine Island area, as much as 5 km of late Miocene shortening complicates earlier extensional structures. Basement involvement in early extension and its possible influence on later compressive events could generate significant hydrocarbon accumulations. The ection beneath the decollement also may have significant petroleum potential. The zone of diapirs-Zaghouan fault, intermediate between the allochthonous Numidian-La Galite complex and the Kasserine Island may have potential beneath a possible decollement. Of particular interest are favorable autochthonous Jurassic facies. These prospects must have been generated during Early Cretaceous time with the subsequent trap improved during the Miocene orogeny. The Gabes basin-Cretaceous platform-Offshore province has well-developed extensional structures. Hydrocarbon source and maturation appear to be sufficient, as seen in the Isis and Ashtart fields. Reservoir quality is the major problem. The Paleozoic tectonic province has favorable extensional structures in the Djefarra complex, but source problems and tilting may have a negative effect. Paleozoic truncation plays outh of the Djefarra are possible. However, large structures and thick reservoirs have not been found. The petroleum potential of Tunisia must be rated high, but only sophisticated and imaginative exploration programs will realize this potential. End_of_Article - Last_Page 477------------

Underwater Drilling and Completion Methods

Abstract Exploration and development of offshore hydrocarbon accumulations underlying deep water greater than about 150 ft. have been restricted by the physical and economic limitations of conventional procedures using bottom-supported drilling and producing facilities. To overcome these difficulties, underwater drilling and completion methods and equipment have been developed for drilling and producing wells from floating platforms in potentially any depth of water without the need for divers or visual observations of the underwater operation. The techniques have been successfully demonstrated in the Gulf of Mexico. The well control systems used for drilling, completing and producing the wells are designed to be fail-safe, remotely actuated and installed on the sea bottom. Model test of drilling platforms indicate that a semi- submersible, triangular-shaped configuration suitable moored provides the most stable working surface for floating drilling operations. The Problem Geologists have long believed that significant hydrocarbon accumulations exist at deep-water locations. Unfortunately, current mobile bottom-supported drilling rigs are limited to about 150-ft water depths. Moreover, bottom-supported drilling and producing platforms appear to be limited to 300 to 400 ft. of water due to limited technology and unfavorable economics. To economically explore for and exploit oil and gas prospects in deep water, development of new techniques was undertaken by Shell Oil Co. in 1955.In defining the problem, the important aspects of deepwater drilling and completion were considered to beunderwater wellhead control systems,floating drilling platforms,production handling facilities,well maintenance techniques andinstrumentation. Moreover, these technical investigations required support from other areas of the company's research and development activities, namely:oceanography and meteorology, andsoil mechanics and structures. The purpose of this paper is to describe system components and procedures developed to meet the exacting conditions of deep-water operations. Summary And Conclusions The success of Shell's underwater drilling, completing and producing methods and equipment results from an over-all definition of the problem which has assured compatibility of all procedures and facilities. Further, thorough engineering and comprehensive land testing of complete assemblies are required to minimize economic losses due to equipment failure in the high-cost offshore environment and to achieve acceptable standards of safety. Wells can be economically and safely drilled in deep water from a floating platform using wellhead equipment located on the sea floor. All desired operations, surveys and tests have been performed successfully without divers or the need for visual observation. Wells have been drilled to over 13,000 ft into typical Gulf Coast geopressured strata overlain by 300 ft of water. An optimal design for a floating drilling platform is a suitably moored, semi-submersible, triangular-shaped configuration. A rectangular-shaped, bottom-supported drilling platform, "Bluewater", modified to operate as a semi-submersible floating platform has demonstrated the validity of the design criteria. Drilling operations have been carried on in 15 ft seas and partial operations continued in 28-ft seas with 65-mph winds. Wells have been completed under water with remotely actuated fail-safe wellhead controls located on the sea bottom which have been tested under simulated conditions to have a life of 60 years. Flowlines can be connected without divers, but additional development of materials for flexible flowlines in conjunction with steel or aluminum is necessary. Moreover, through-the-flowline production maintenance tools to control paraffin, measure pressures, place gas-lift valves, etc., are feasible and have been tested successfully. Studies show that production methods depend primarily upon local conditions, such as water depth, well spacing, bottom conditions, distance to land, pipeline availability and others, but bottom-supported production platforms appear economically attractive in water depths of 300 to 400 ft, with floating production platforms attractive in greater depths. Adequate instrumentation of wellhead and platforms must be provided to assure efficient and safe operations. JPT P. 595ˆ