Delineation Drilling Research Articles

Hydrochemistry and geothermometry of thermal waters from UAE and their energetic potential assessment

Two main low-enthalpy geothermal fields are present in the UAE: Mubazzarah-Ain Faidha (Al-Ain city) in the Abu Dhabi Emirate and Ain-Khatt in the Ras Al-Khaimah (RAK) Emirate. The chemistry of nineteen waters was analyzed to calculate geothermal reservoir temperatures using cation and silica geothermometers, and to describe the source of recharge of the hot waters from isotopic data. In total, 19 water samples (16 from wells, 2 from springs AF and KT1 and one sea water) were collected and analyzed for major anion and cation concentrations. The isotope and chemical data suggest that the hot waters from Al-Ain (Mubazzarah and Ain Faidha) are almost entirely recharged by rainwater, which originates at higher altitude, heats up through deep water circulation, and travels to the surface through fault structures within the study area. The waters are mainly Na-Cl type, and the discharge temperatures range from 32.5 °C to 49 °C. The Na-K geothermometers predict a geothermal reservoir temperature of 151 °C for the Mubazzarah-Ain Faidha hot waters and 112 °C for the Ain-Khatt hot waters with estimated depth of water penetration of 3.8 km and 2.6 km, respectively. The existing known geothermal resources in the Mubazzarah and Ain Khatt areas can be immediately and sustainably used for low-temperature, direct-use geothermal applications. A stochastic Monte Carlo simulation was performed to estimate the geothermal energy stored in the two main low-enthalpy geothermal fields for 25 years and 50 years. The geothermal electricity potential at Mubazzarah-Ain Faidha is ∼16.5 MWe and ∼8.27 MWe for 25 and 50 years, respectively. The geothermal electricity potential at Ain Khatt is ∼291 kWe and ∼146 kWe for 25 and 50 years, respectively. These preliminary potential assessments are subject to further delineation drilling and availability of field performance data and considered that the geothermal power plant has either a single or multiple ORC systems due to the very low temperature.

A Review of Exploration, Development, and Production Cost Offshore Newfoundland

Operators have spent $84 billion Canadian dollars in exploration, development, and production offshore Newfoundland, Canada, between 1966 and 2019, and have produced about 2 billion barrels of an estimated 3.3 billion barrels recoverable oil. Four major projects have been developed—Hibernia, Terra Nova, White Rose/North Amethyst, and Hebron—using two development concepts, gravity-base structures and floating production storage and offloading vessels. The region is characterized by severe storm and sea conditions, including the presence of icebergs, which challenge all aspects of exploration and development. From 1998 to 2019, exploration and delineation drilling cost averaged $90.9 million per well and $26,494 per meter drilled. Development wells drilled from mobile offshore drilling units over the same period averaged $91.1 million per producer well and $68.8 million per injector well. Regional development cost was $32.5/bbl since the start of production and is expected to fall to $22/bbl when recoverable volumes circa 2020 have been extracted. Average regional production cost from 2006 to 2019 is estimated at $23.4/bbl and ranges from $16.8/bbl at Hibernia to about $35/bbl at Terra Nova and White Rose. This is the first detailed evaluation of exploration, development, and production cost offshore Newfoundland.

3D geological modelling of the Renard 2 kimberlite pipe, Québec, Canada: from exploration to extraction

The Renard 2 kimberlite pipe is one of nine diamondiferous kimberlite pipes that form a cluster in the south-eastern portion of the Superior Province, Quebec, Canada and is presently being extracted at the Renard Mine. It is interpreted as a diatreme-zone kimberlite consisting of two Kimberley-type pyroclastic units and related country rock breccias, all cross-cut by coherent kimberlite dykes and irregular intrusives. Renard 2 has been the subject of numerous diamond drilling campaigns since its discovery in 2001. The first two geological models modelled kimberlite and country rock breccia units separately. A change in modelling philosophy in 2009, which incorporated the emplacement envelope and history, modelled the entire intrusive event and projected the pipe shape to depth allowing for more targeted deep drilling where kimberlite had not yet been discovered. This targeted 2009 drilling resulted in a > 400% increase in the volume of the Indicated Resource. Modelling only the kimberlite units resulted in a significant underestimation of the pipe shape. Current open pit and underground mapping of the pipe shape corresponds well to the final 2015 geological model and contact changes observed are within the expected level of confidence for an Indicated Resource. This study demonstrates that a sound understanding of the geological emplacement is key to developing a reliable 3D geological and resource model that can be used for targeted delineation drilling, feasibility studies and during the initial stages of mining.

Seismic delineation of the Orion South kimberlite, Fort à la Corne, Canada

The Orion South ([Formula: see text]) kimberlite is a diamondiferous, multiphase volcano-sedimentary complex within the Cretaceous Fort à la Corne kimberlite field of Saskatchewan, Canada. A network of seven high-resolution 2D seismic reflection profiles were acquired to test the utility of using seismic methods in defining the subsurface architecture of the kimberlite complex, and to provide auxiliary constraints on interborehole geologic correlations. The seismic data were interpreted in conjunction with a set of drillhole geologic logs and associated geologic sections and models, and physical rock properties from core measurements and geophysical logs. Core-determined average density values for the kimberlite suite are low ([Formula: see text]), but with some kimberlite facies having significantly higher values (2330 to [Formula: see text]). Sonic velocities for the kimberlites are [Formula: see text] as compared with [Formula: see text] and [Formula: see text] for the enveloping shale and sandstone units, respectively. The kimberlite is imaged to depths of [Formula: see text] as a lenticular-shaped body lying beneath, Quaternary glacial till and a mantle of Cretaceous marine sediments. The base of the kimberlite is variably imaged due to faulting and lateral changes in the seismic contrast with the underlying Cantuar sandstone. The comparable magnitude of seismic contrasts across inter- and intraeruptive phase boundaries hampers interpretation of the individual eruptive phases within the kimberlite complex, although the conformal nature of internal reflections with the interphase boundaries is useful in mapping these boundaries away from the drillholes. Multiple feeder vents at the base of the complex and their associated vertical faults are clearly identified by truncations of subhorizontal reflectivity. This study demonstrated how a network of relatively low-cost seismic profiles could potentially be useful in guiding detailed delineation drilling of kimberlite deposits.

アバディガス田これまでの道程―そして今後の展望

Abadi Gas Field was discovered by INPEX Corporation in 2000, singlehandedly. This discovery was made in a remote frontier area of Arafura Sea in Republic of Indonesia. The discovery was in 400-800m sea depth and more than 100km away from the nearest island, with Timor Trough existing in between. INPEX subsequently carried out 3D Seismic Surveys and multiple delineation drilling campaigns, which proved that this field is a giant gas field.This paper describes Geological philosophy based on which the tract was obtained. The geological framework of this area , based on 3D Seismic and exploratory / delineation drilling campaigns. The use of 3D Seismic data, innovative way to effectively calculate reserves distribution and partial perforation DST to evaluate vertical communication are addressed in some detail. The way forward for the development of this field is touched on.

Athabasca oil sands: reservoir characterization and its impact on thermal and mining opportunities

Abstract The heavy oil deposits of Canada are a large resource with an estimated 1.7×10 12 barrels of bitumen in place. The Lower Cretaceous McMurray Formation in the Athabasca area of northern Alberta contains about 900×10 9 barrels of bitumen in place. This resource can be developed through surface mining and thermal in situ techniques. This paper examines the size of this resource in a global context and highlights its position relative to the North American market. The regional geology of the Western Canada Sedimentary Basin and the Athabasca area will also be reviewed. Understanding the regional reservoir distribution of the McMurray Formation is critical to understanding oil sands opportunities. Fluvial estuarine point bar reservoirs are a large portion of the resource that can be developed. Examples will be shown from the type outcrop location, where the stratigraphy can be organized into a hierarchy that subdivides channel-fills into bedsets, storeys, bars and barsets. Inclined heterolithic strata (IHS) surfaces can be identified. Considerable resource delineation drilling has occurred in the basin. The regulator for the Athabasca area specifies minimum drilling densities before project approvals are granted. Regional 2D seismic lines and project-specific 3D and 4D seismic datasets have also been acquired, to reduce the reservoir uncertainty and improve resource definition in this complex depositional environment. These techniques provide a unique opportunity to analyse a complex depositional system with abundant well and core control, outcrop data and seismic information. To determine preliminary deposition environments, software techniques have been successfully used to interpret large datasets quickly. Laser imaging of mine faces has also been used to record stratigraphy and determine the mined volume of ore. The importance of detailed reservoir characterization studies and their impact on thermal in situ recovery mechanisms will also be discussed. Understanding reservoir facies distributions and lateral relationships affects any recovery process, but has an even greater significance in a heavy oil reservoir.

Exploration history and geology of the diamondiferous ultramafic Saptarshi intrusions, Madhya Pradesh, India

The Saptarshi Field comprises a suite of at least eight known diamondiferous pipes and dykes within Rio Tinto's Bunder Project on the Bundelkhand Craton of Madhya Pradesh, India. The discovery, made in 2004, followed regional scale area selection, gravel sampling, and subsequent ground geophysics, soil geochemistry and prospecting. The geology and petrography of the largest and most economically prospective pipe, Atri, suggests that near the surface it forms a large vent comprised of two distinct lobes filled predominantly with primary pyroclastic rocks. Atri is composed of relict olivine, phlogopite, apatite, minor spinel and Ti-oxides. The rock is altered; no primary olivine and little phlogopite remains, instead much of the rock is now composed of serpentine–chlorite–carbonate. Other occurrences within the Saptarshi Field include small pipes and altered dykes. Atri is one example of the diverse assemblage of potassic rocks found on the Indian subcontinent: many parallels may be drawn with the nearby diamondiferous Majhgawan pipe, including mineral chemistry and petrography. Atri has many characteristics in common with olivine lamproite, but many subtle deviations from type-lamproite are observed. We suggest that Atri represents a local expression of potassic magmatism unique to the Bundelkhand Craton of India and is the product of partial melting of modally diverse veins in ancient metasomatized lithospheric mantle. These rocks are not readily classified according to existing schemes devised for potassic rocks known from other petrological provinces. A practical and workable scheme has not been devised that recognizes the unique characteristics of the diversity of lamproite-like rocks. The authors tentatively classify Atri as a diamondiferous ultramafic intrusion with lamproitic affinities, recognizing its (obscured) primary mineralogy, its petrographic and textural characteristics and the important implications this classification has with respect to exploration. The ≈ 1100 Ma age of the Saptarshi intrusions imply that they are part of a larger igneous province, which includes the nearby Majhgawan and Hinota diamondiferous pipes. This age temporally relates to the lamproites of Western Australia. Rio Tinto completed an Order of Magnitude (OoM) scoping study comprising large diameter and slim-line delineation drilling, and surface bulk sampling on the Project in 2008.

The structural/stratigraphic development of the Sishen South (Welgevonden) iron ore deposit, South Africa, as deduced from ground gravity data modelling

The Palaeoproterozoic Transvaal Supergroup in the northern Cape Province of South Africa hosts high grade (>60%Fe) hematitic and specularitic iron and manganese mineralisation. The mineralisation is primarily exposed along the western margin or in the central part of a major interference fold structure known as the Maremane dome. The bulk of South Africa's iron ore production is currently provided by two active mines, Kumba Resources megaton Sishen iron ore mine on the northern end of the dome, and the smaller Assmang Beeshoek mine on the southern closure. The undeveloped Sishen South deposit, which contains ∼400 Mt of high-grade hematite ore, is located ∼9 km towards the southwest of Postmasburg. It forms a linear extension of the Beeshoek mine and as such contains comparable laminated, breccia and conglomeratic iron mineralisation. The Transvaal Supergroup sediments were deposited in two distinct fault-controlled basins on the Archean Kaapvaal craton. Basement rocks in the western Griqualand West basin are formed by a carbonate platform sequence (Campbellrand Subgroup), which is overlain by a thick sequence of banded iron formation of the Asbesheuwels Subgroup. A major unconformity separates these rocks from the red-bed Gamagara Formation, which is correlated with the base of the Olifantshoek Supergroup. Diamictites and lavas of the Postmasburg Group have been thrust over these units from the west. The mineralisation process is related to regional scale supergene iron enrichment of Kuruman banded iron formations along the unconformity. During regional tectonism associated with the Kheis orogeny (2400–1700 Ma) the Maremane dome was uplifted, and the basal dolomite units thus exposed to erosion and karstification. The overlying banded iron formations collapsed into karst sinkhole structures where leaching of silica and enrichment of hematite occurred. Although the exact mechanism of the mineralising process remains unclear, karstification preserved components of the original concordant laminated and massive ores. These ores were subsequently eroded and deposited as conglomeratic and gritty ores down-dip of the Maremane dome in alluvial fan systems. A thin veneer of recent calcrete or Tertiary Kalahari clay beds masks the subsurface geology and most of the orebodies, thus ground geophysical gravity surveys proved excellent exploration tools to penetrate the surficial cover. These surveys were used extensively for delineation drilling and to deduce the subsurface geology and structural development of the area. Finally Sishen South orebodies were modelled with ModelVision software in an attempt to obtain an exploration template for the surrounding area.

The Geophysics of the Ernest Henry Cu-Au Deposit (N.W.) Qld

The Ernest Henry copper-gold deposit is located approximately 30 km NNE of Cloncurry in northwest Queensland. It contains an indicated resource of 122 Mt at 1.14% copper and 0.55 g/t gold. The deposit is hosted in Proterozoic rocks of the Mt Isa Inlier. The Proterozoic geology is overlain by 40 to 50m of flat lying Phanerozic sediments.The discovery of the deposit was the result of a geophysically and geologically driven exploration program that was guided by a simple empirical model for the deposit type. Magnetic methods were used to initially focus exploration. Transient electromagnetic (TEM) techniques were used to filter the magnetic target areas. The first drill hole into the deposit intersected economic copper and gold grades.After the discovery, downhole TEM surveys demonstrated that the initial surface TEM target was due to a supergene layer of mineralisation that in part included a section rich in native copper. It also demonstrated that the bulk of the primary mineralisation did not produce a TEM anomaly. The primary mineralisation is intimately associated with the matrix of a felsic to intermediate volcanic breccia. The matrix to the breccia is rich in magnetite and disseminated sulphide mineralisation. Ground magnetic, gravity and Induced Polarisation methods were used to help guide the delineation drilling of the deposit.

The Haven Oil Field: Development of a Tiny Marginal Field With Horizontal Wells

Summary The decrease in large discoveries highlights the need for the industry tofocus on safe, low-cost, high-efficiency development of smaller fields. Thispaper describes the development and economic success of one tiny oil field inthe North Sea with horizontal well technology and reuse of existing minimalfacilities. Emphasis is placed on how predevelopment reservoir simulationpredevelopment reservoir simulation studies influenced the design and drillingof wells. The reservoir model results were the basis for economic justificationof the project. The paper also compares actual reservoir performance withpredictions. performance with predictions. Introduction The Haven oil field awaited development for 8 years after its discoverybecause recovery of its reserves of 0.62 × 10-6 m3[3.9 million bbl] was risky andthe economics were marginal. Water coning, giving rise to early waterproduction, was expected from vertical wells. Also, initial volumetricestimates had to be reduced as a result of delineation drilling. Unocal Netherlands' successful redevelopment of the Helder field with horizontal wellsspurred the company to apply the technology to fields with similar productionproblems. This led to a reappraisal of problems. This led to a reappraisal ofprevious development plans for Haven. previous development plans for Haven. Themain advantages of horizontal wells in developing fields with thin oil columnsare the increased oil recovery resulting from an improved sweep efficiency, higher PI resulting in lower drawdowns, and lower water cuts because coning isreduced. The reservoir shape, high permeability, and thin oil column made the Haven oil field a prime candidate for horizontal well development. Thereservoir was modeled in 3D with implicit blackoil reservoir simulationsoftware to compare the expected performance of horizontal and vertical wells. The performance of horizontal and vertical wells. The results showed that morethan two conventional wells would be required to recover the same reserves astwo 450-m [1,476-ft] horizontal wells drilled along the crest of the structure. This meant a small two-slot wellhead facility could be installed instead of alarger six-slot platform, thereby reducing the investment required andincreasing the economic margin. Such a facility was available in the form ofthe Helder B satellite platform. which was about to be abandoned and platform.which was about to be abandoned and had been originally designed forrelocation. Justification and approval of this project were based on thereservoir model results. Field History and Description The Haven oil field is a very small accumulation located in Block Q/l of the Dutch North Sea, about 100 km [62 miles] north-west of Amsterdam (Fig. 1). Itlies 5.8 km [3.6 miles] north of the Helder field in 27 m [89 ft] of water. The field was discovered in 1980 by Well Q/1-8, which penetrated 16 m [52.5ft] of pay and tested at a rate of 525 m3/d [3,300 pay and tested at a rate of525 m3/d [3,300 BID] fluid. Water was produced almost immediately, and the cutrose to a maximum of 35% within 22 hours. Therefore, from the beginning it wasapparent that water coning would be a problem in any conventional developmentof such a thin oil column. Structural mapping problems were encountered in 1981when Well Q/1-15 was drilled to prove reserves 1.6 km [l mile] to thesoutheast, but penetrated the structure deeper than expected, 14 m [46 ft]below the oil/water contact (OWC). Two further delineation wells, Wells Q/1 -20and 21, were drilled from a central template in 1985 and 1986, with theintention of keeping them as future producers. Based on the results of thesewells, the original estimate of stock-tank oil initially in place was reducedby 50%, from about 3.8 to 1.9 × 106 m3 [24 to 12 MMSTB]. With the consequent dropin estimated reserves to only 0.62 × 106 m3 [3.9 MMSTB], the project becamemarginal. The structure is a long, narrow, low-relief anticline of friable, Lower Cretaceous Vlieland sand at a depth of 1600-m [5,250-ft] subsea (Fig. 2). Table 1 summarizes the reservoir and fluid properties. The oil column has amaximum thickness of 21 m [69 It] and is underlain by water over the entirearea of closure. This aquifer is common to all the Vlieland fields in Block Q/1. Vertical and horizontal permeabilities in the reservoir vary from 1.5 to 10darcies [1.51 to 9.9 m2], and there is little anisotropy. The sand is generallyhomogeneous and clean, but in the top 7 m [23 ft] of the northern part of thefield up to three shaly/silly sections of 1 to 2 m [3 to 6 ft] in thicknessexist. Development of the field was proposed in early 1986, using a four-pileunmanned platform and two vertical wells; however, the platform and twovertical wells; however, the subsequent fall in oil price caused the project tobe shelved. The main factors that led to the economic development of the Havenfield were the availability of two new technologies: the small tripod towerplatform (TTP) and horizontal drilling. JPT P. 496

Discovery and Delineation of the Point Arguello Field: Giant Reserves in a Fractured Reservoir: ABSTRACT

Chevron (as operator for its partners, Phillips, Union Pacific Resources, and Impkemix) discovered the Point Arguello oil field in 1981. The discovery well, the Chevron et al. P-0316-1, was drilled in federal waters 8.5 mi (13.7 km) south of Point Arguello, California. Delineation drilling (by both Chevron and Texaco) has confirmed the discovery of a giant oil field with estimated recoverable reserves in excess of 300 million bbl of oil. The oil field is located within a small depocenter at the southern edge of the offshore Santa Maria basin. This local depocenter may contain over 15,000 ft (4,600 m) of Neogene rocks. The Point Arguello accumulation is trapped in a large north-northwest-trending anticlinal complex and is part of an anticlinal trend of similar Monterey oil discoveries and producing fields within the offshore Santa Maria basin. The primary reservoir is the middle and upper Miocene Monterey Formation, and is composed of fractured cherts, porcellanites, siliceous mudstones, and dolostones. Calculated fracture permeabilities range up to 3 d. Crestal wells have indicated productivities, after acid, of approximately 6,000 BOPD. Three production platforms have been installed and onshore treatment facilities built.

Oil and Gas Developments in Eastern Canada in 1988

Exploration activity on Canada's east coast offshore region continued at a steady rate in 1988. A total of 10 wells were active: 1 exploratory well offshore Nova Scotia, and 5 exploratory wells and 4 delineation wells offshore Newfoundland. The highlights of 1988 were Mobil's discovery of a new gas and condensate pool south of Sable Island offshore Nova Scotia, and successful delineation drilling results offshore Newfoundland by Petro-Canada at Terra Nova and by Husky Oil Operations at Whiterose. Based on these successes, the estimates of discovered oil and gas resources for the region have been revised upwards to 235 million m3 (1.5 billion bbl) of oil and condensate and 309.4 billion m3 (10.9 tcf) of natural gas. A significant step was made toward development of the Hibernia oil and gas field with the signing of a Statement of Principles by the governments of Canada and of Newfoundland and Labrador with Mobil Oil Canada and its partners. Also Petro-Canada is undertaking a preliminary engineering study to evaluate alternative development scenarios for Terra Nova field. Studies are also in progress on possible schemes to develop the several natural gas discoveries and the 2 small oil discoveries in the Nova Scotia offshore. Legislation required to implement joint federal-provincial resource management offshore Nova Scotia has been passed by the Canadian Parliament and the provincial legislature and will likely be proclaimed in 1989. At that point, a new resource management board will assume responsibility for the Nova Scotia offshore. This arrangement is identical to that established in the Newfoundland offshore in 1987. The future looks bright for the East Coast given the stable resource management regime, the regular schedule of rights issuances, and the large remaining potential. Steps to development of the best of the discoveries will lead to an increase in the pace of exploration in the early 1990s. Activity in Ontario in 1988 was at its highest level since 1980, with drilling completed at a total of 188 wells for an aggregate length of nearly 107,000 m (350,000 ft). Activity was paced by a record amount of drilling of Ordovician targets, as interest in this very successful play continued to increase. Drilling of Ordovician targets was reported to be complete at 25 exploratory wells, 15 development wells, and 2 stratigraphic tests, resulting in 21 new oil producers and 4 gas producers. Oil production in Ontario increased dramatically in 1988, due entirely to production from new Ordovician reservoirs discovered since 1983. Production totaled approximately 190,570 m3 (1.2 million bbl) compared to 135,635 m3 (853,000 bbl) in 1987. Further production increases a e expected in 1989. Activity in Quebec in 1988 was concentrated in the Basse-Terres region near Trois Rivieres in the St. Lawrence lowlands, and on Anticosti Island. Five exploratory wells and 6 natural gas storage wells were drilled. Two of the exploratory wells resulted in discovery of an accumulation of natural gas in unconsolidated glacial sediments beneath Lake St. Pierre on the St. Lawrence River. There was no drilling activity in onshore portions of Prince Edward Island, Nova Scotia, New Brunswick, or Newfoundland in 1988.

Current and Future Offshore Activities in Canada

Summary. The development of innovative exploratory drilling systems for Canada's harsh Arctic offshore areas over the past decade and future activity in these areas, including possible production concepts, are discussed. The results can be applied in other Arctic areas of the world, including offshore Alaska. This operating experience will advance drilling technology and serve as a basis for the design of Arctic offshore production and transportation systems. Unique technology has been developed and successfully used in the discovery of major accumulations of hydrocarbons. Continued technological advances are anticipated to have widespread Arctic applications in both exploratory and production operations. Introduction Drilling has been successfully conducted in most of Canada's offshore areas despite the extremely harsh environmental conditions. During the past decade, technology has advanced very significantly particularly in the Beaufort Sea and Canadian Arctic Islands. particularly in the Beaufort Sea and Canadian Arctic Islands. Operating experience gained during the exploratory drilling phase is being used in the conceptual design of production systems. Undoubtedly, there will also be an evolution of technology during the development and production phases as the vast frontier reserves are exploited. Canada's offshore frontier areas typically have high costs and lengthy time spans between discovery and production. These factors present major engineering challenges for the design of safe, cost-effective, and timely exploratory and development systems. Confidence in the reservoir extent and predicted performance may permit large-scale development projects, while performance may permit large-scale development projects, while uncertainties may result in a phased approach where possible. The latter is attractive because earlier revenue is generated. Giant discoveries in the Beaufort Sea may not be essential to trigger development and a transportation system, because a combination of several pools may justify limited tankers or a small-diameter pipeline. Similarly, in such areas as the Grand Banks, phased pipeline. Similarly, in such areas as the Grand Banks, phased development with floating production platforms may be feasible. Artificial islands, first started in 1972, are still being constructed but with improved designs and equipment. A step forward has been the use of subsea berms on which concrete or steel segmented caissons have been placed. Integrated-type steel caissons have also been adapted for placement on subsea berms. One is one-half of a crude oil tanker and a second is a purpose-built steel caisson first used in 1984. Four drillships were converted and/or strengthened for Arctic service in the Beaufort Sea, and three have drilled since 1976. The second-generation floating vessel for the area is the Kulluk conical drilling unit, which began drilling in 1983 and has extended the operating season. In the Canadian Arctic Islands, drilling off artificially thickened ice in water depths exceeding 1,200 ft [365 ml has proceeded successfully since it began in 1973. On Canada's east coast, use of dynamically positioned vessels and iceberg towing have permitted seasonal drilling in positioned vessels and iceberg towing have permitted seasonal drilling in ice-infested waters. Production of oil from Hibernia and gas from Venture will be possible early in the next decade. Production of oil from the possible early in the next decade. Production of oil from the Beaufort Sea is also possible in the early 1990's and from the Canadian Arctic Islands in about the mid-1990's. Systems for such production will be discussed. production will be discussed. The focus will continue to be on exploratory drilling and delineation drilling for several years in most areas. Conceptual and preliminary engineering design for development will accelerate as new discoveries are made and others delineated. Wildcat exploratory drilling will also continue to satisfy exploration agreements and will tap the vast potential reserves of Canada's offshore areas. Geologic Potential The hydrocarbon potential of Canada's offshore frontiers has been recognized for several decades. Permits to explore for oil and natural gas were granted in several areas during the 1960's, when offshore drilling began on the east coast. Drilling in the Mackenzie delta and Canadian Arctic Islands (Fig. 1) in the 1960's was a forerunner to drilling offshore in those regions in the early 1970's. Encouraging hydrocarbon reservoirs have been discovered in all frontier areas except the west coast and Hudson Bay. The search has been primarily for oil in an effort to achieve self-sufficiency, security of supply, and economic returns. Significant reserves of nonassociated natural gas have also been discovered offshore and may be produced in conjunction with solution gas from offshore oil production and with nearby land-based gas reserves when a transportation system is available and demand and economic conditions warrant such production. Estimates of the potential recoverable oil and gas reserves for the frontier areas have recently been published by the Canadian federal government's Geological Survey of Canada (GSC) and are shown in Table 1. JPT P. 717

Gasfield Development-Reservoir and Production Operations Planning

Summary Efficient development of natural-gas reservoirs requires the participation of many engineering planning and implementation disciplines. participation of many engineering planning and implementation disciplines. When development involves large, remote, offshore gas reservoirs with high H2S and CO2 content, planning and coordination problems increase rapidly. This paper discusses the time/planning relationships in the evaluation and definition phases of a generalized major gas project typical of resources currently being evaluated in many locations. Project development planning requires an extensive drilling appraisal program to define gas in place, gas productivity, and gas quality. With program to define gas in place, gas productivity, and gas quality. With this information, marketing potentials can be established, and the interrelated planning and design steps to define commercial feasibility can be undertaken. These steps include gas process optimization studies necessary for project definition and continued reservoir assessments, progressing into early multidimensional analyses. This effort assists in progressing into early multidimensional analyses. This effort assists in establishing well count, well spacing, and platform siting to yield production performance consistent with equipment constraints and delivery production performance consistent with equipment constraints and delivery requirements. This study does not discuss the execution phase of the project, but it does stress the importance of having a qualified, multidiscipline project organization to complete the evaluation and definition phases and to serve as the basis of the fully staffed project management team necessary to complete the detailed design and construction phases of the project. Introduction Many steps are involved in planning the development of a generalized major gas project. The following discussion is based on studies of several large projects from which a composite hypothetical reservoir was constructed to illustrate the problems typically encountered. This composite reservoir is analogous in many respects to larger structures in the Khuff formation in the Middle East. Although project activities overlap in timing and manpower requirements, overall development planning may be subdivided into six phases (also shown in Fig. 1): Phase 1-exploration and pre-evaluation; Phase 2-evaluation; Phase 3-definition; Phase 4-design; Phase 5-construction; and Phase 6-operations. Other groups may use different terms, but the activities are similar. This paper is concerned only with the first three phases. During the completion of these steps, a number of activities must be performed in parallel, including exploration drilling, resource evaluation, assessment of oceanographic and geotechnical factors affecting design, and environmental impact evaluation. Preliminary planning must be initiated to anticipate requirements for structures, developmental drilling, production/treating facilities, pipelines, terminals, and marketing. The ultimate objective is to generate an overall project plan applicable to a deep, high-pressure, sour-gas reservoir in an offshore environment. Pre-Evaluation Phase Pre-Evaluation Phase Minimum time is available for this evaluation. To assist in prompt, accurate reviews, the value of having well-organized project development planning and cost data cannot be overemphasized. The location of the discovery in a typical exploration contract area is shown in Fig. 2 in relation to a nearby shoreline. Some of the more significant steps to be taken in this period include the following.Preliminary assessment of potential recoverable reserves, development costs, and profitability of the prospect.Preparation of a delineation well-drilling program to defineadequately the gas reserves, gas producibility, and cost ofcarrying out such a program.Preparation of detailed study tasks for the evaluation anddefinition phases of the project, an estimate of the minimum timerequired to complete these tasks on the basis of completeddelineation well results, and the estimates of manpowerrequirements and costs for the studies.Management approval to undertake the additional delineation drilling and evaluation/definition study programs. Although the circumstances of each project are different, the minimum time required to develop the detailed planning and estimates in this pre-evaluation period is planning and estimates in this pre-evaluation period is usually about 3 months but can take longer. Evaluation Phase With the approval of the proposed project study plan, the most important ingredient in project planning is the assembly of a qualified project organization. JPT P. 217

Geology of the Point Arguello Discovery: ABSTRACT

Chevron as operator for its partners, Phillips, Champlin, and Impkemix, discovered the Point Arguello oil field in 1981. The discovery well, the Chevron et al P-0316-1, was drilled in federal waters 8.5 mi (13.7 km) south of Point Arguello, California. Delineation drilling has confirmed the presence of a giant oil field with estimated reserves in excess of 300 million bbl of oil. The oil field is located within a small depocenter at the southern edge of the offshore Santa Maria basin. This local depocenter may contain over 15,000 ft (4,750 m) of Neogene rocks. The Point Arguello accumulation is trapped in a large north-northwest-trending anticlinal complex. The main reservoir is in the middle and upper Miocene Monterey Formation composed of fractured cherts, porcellanites, siliceous mudstones, and dolostones. Calculated fracture permeabilities range up to 3 darcies. Crestal wells have indicated productivities, after acid, of approximately 6,000 BOPD. End_of_Article - Last_Page 659------------

Geology of the Point Arguello Discovery

Chevron (as operator for its partners, Phillips, Champlin, and Impkemix) discovered the Point Arguello oil field in 1981. The discovery well, the Chevron et al P-0316-1, was drilled in federal waters 8.5 mi (13.7 km) south of Point Arguello, California. Delineation drilling has confirmed the discovery of a giant oil field with estimated recoverable reserves in excess of 300 million bbl of oil. The oil field is located within a small depocenter at the southern edge of the offshore Santa Maria basin. This local depocenter may contain over 15,000 ft (4,600 m) of Neogene rocks. The Point Arguello accumulation is trapped in a large north-northwest-trending anticlinal complex. The primary reservoir is the middle and upper Miocene Monterey Formation, composed of fractured cherts, porcellanites, siliceous mudstones, and dolostones. Calculated fracture permeabilities range up to 3 darcys. Crestal wells have indicated productivities, after acid, of approximately 6,000 BOPD.

Williston Basin Seislog Study: ABSTRACT

This paper describes the results of Seislog® (trade name) processing and interpretation of an east-west line in the North Dakota region of the Williston basin. Seislog processing involves inversion of the seismic trace data to produce a set of synthetic sonic logs. These resulting traces, which incorporate low-frequency velocity information, are displayed in terms of depth and isotransit times. These values are contoured and colored, based on a standard stratigraphic color scheme. The section studied is located just north of a dual producing oil pool from zones in the Ordovician Red River and Devonian Duperow Formations. A sonic log from the Long Creek 1 discovery well was digitized and filtered to match the frequency content of the original seismic data. This allows direct comparison between units in the well and the pseudosonic log (Seislog) trace nearest the well. Porosity development and lithologic units within the lower Paleozoic stratigraphic section can be correlated readily between the well and Seislog traces. Anomalous velocity zones within the Duperow and Red River Formations can be observed and correlated to producing intervals in the nearby wells. These results emphasize the importance of displaying inversion products that incorporate low-frequency data in the search for hydrocarbons in the Williston basin. The accumulations in this region are local in extent and are difficult to pinpoint by using conventional seismic data or displays. Seislog processing and displays provide a tested method for identification and delineation of interval velocity anomalies in the Red River and Duperow stratigraphic sections. These techniques can significantly reduce risks in both exploration and delineation drilling of these types of targets. End_of_Article - Last_Page 290------------

Fort St. John - Stoddart Area An On-Going Petroleum Development Opportunity

Abstract Since the early 1950s, exploratory and development drilling has been continually rewarding within an 80 km radius of the city of Fort St. John, British Columbia. Although this drilling was originally gas-oriented, significant oil discoveries were made at Boundary Lake (Esso, 1957), Peejay (Sinclair Oil, 1959), Inga (Canadian Superior, 1965) and West Eagle (Scurry Rainbow, 1976). Scurry-Rainbow Oil Limited, now controlled by Home Oil Company Limited, has played an integral part in most of these field developments. Until the early 1970s there were a limited number of wells immediately north of Fort St. John with the exception of the Stoddart Belloy gas pool which was discovered in 1957. The possibility of oil regionally down dip was evidenced by production from the Uno Tex wells in Section 31-85-19W6M and oil shows at the Sun 8-l4-85-19W6M and Centrai Del Rio ll-29-84-18W6M wells (Fig. I). Although Triassic reservoirs have produced the majority of B.C.'s oil reserves to date, the Belloy (Permian) is now gaining importance as a major producing horizon (Table 1). Scurry-Rainbow's first well was drilled in 1971 on a farmout from Great Northern Oil Limited (6-3l-84-17W6M), exploring for what was hoped to be a regional extension of the Stoddart Belloy gas pool. Although the Belloy was tight at the location, a porous gas bearing Triassic North Pine sand was encountered, thus discovering the Cecil North Pine "A" gas pool. Further delineation drilling in 1972 confirmed the extent of the gas discovery, as well as proving the existence of an oil leg to the pool. ncouraged by the results of the North Pine drilling, Scurry- Rainbow and Placer CEGO Petroleum stepped out approximately mid-way between the originaI6-31-84-17W6M well and the Central Del Rio Belloy oil show at 11-29-84-18W6M, and discovered what is now known as the Eagle Belloy "B" pool in 1973 (6-27-84-18W6M). With attention then concentrated on extending the trend northwest back to the Uno Tex Stoddart wells discoveries were made at West Eagle, (Belloy "A" pool 1976) West Stoddart (Belloy "C" pool, 1977) and South Stoddart (Belloy "C" 1979). Undoubtedly, the most significant of these discoveries was the West Eagle field (6-36-84-19W6M). Subsequent to step-out drilling by other independent operators, early indications of the possible major size of the Belloy "A" pool sparked a flurry of lease acquisition of both Crown acreage and some of the only freehold acreage in British Columbia. Once most of the favourable acreage had been leased surrounding the discovery, development drilling began in earnest during 1977. By the end of 1980, sixty-seven wells had been drilled into the Belloy "A" pool. As the pool did not have either a natural water drive or a significant gas cap, reservoir pressures declined rapidly from 16742 kPa (2428 psi) in 1976 to 15 200 kPa (2204 psi) in 1980. The B.C. Petroleum Resources Division and the operators agreed that waterflood operations should commence as soon as possible. To that end, the pool was unitized with Scurry-Rainbow as operator and injection operations began prior to the end of 1980.

Geology of Point Arguello Discovery: ABSTRACT

Chevron as operator for its partners, Phillips, Champlin, and Impkemix, discovered the Point Arguello oil field in 1981. The discovery well, the Chevron et al P-0316-1, was drilled in federal waters 8.5 mi (13.7 km) south of Point Arguello, California. Delineation drilling has confirmed the presence of a giant oil field with estimated reserves in excess of 300 million bbl of oil. The oil field is located within a small depocenter at the southern edge of the offshore Santa Maria basin. This local depocenter may contain over 15,000 ft (4,750 m) of Neogene rocks. The Point Arguello accumulation is trapped in a large north-northwest-trending anticlinal complex. The main reservoir is in the middle and upper Miocene Monterey Formation composed of fractured cherts, porcellanites, siliceous mudstones, and dolostones. Calculated fracture permeabilities range up to 3 darcies. Crestal wells have indicated productivities, after acid, of approximately 6,000 BOPD. End_of_Article - Last_Page 659------------

Petroleum potential in arctic North America and Greenland

Abstract Sedimentary deposition in Arctic North America and Greenland, in Phanerozoic time, occurred north of the Precambrian Canadian Shield and extended from the Wandel Sea in the east to the Chukchi Sea in the west. Seven geological provinces considered to be highly prospective for oil and gas exist within the region. Lower Paleozoic sediments may exceed 3000 m (10 000 ft) in the several separate basins in the Arctic Interior Platform of the Central Stable Region. To the north of the Arctic Interior Platform, lower Paleozoic sediments thicken into the Franklinian Geosyncline, the second geological province. Twelve thousand metres of lower and middle Paleozoic rocks are folded and faulted along a sinuous belt extending from the Wandel Sea in northeastern Greenland to Prince Patrick Island in the western Canadian Arctic Islands. Unconformably overlying the Franklinian Geosyncline are two successor basins, the third and fourth geological provinces considered in this report. The Sverdrup Basin in the Canadian Arctic Islands contains over 13 000 m (43 000 ft) of upper Paleozoic, Mesozoic and Tertiary sediments. The Wandel Sea Basin in and adjacent to northeastern Greenland, analogous to the Sverdrup Basin, contains a similar complement of upper Paleozoic, Mesozoic and Tertiary sediments. Onshore in Greenland, a composite thickness of 3000 m (10 000 ft) of sediments has been described and offshore, beneath the continental shelf, sediments in the basin may thicken to 10 000 m (33 000 ft). The Arctic Slope of Alaska, the fifth province, exhibits characteristics of a successor basin that has been rotated, translated or otherwise displaced from the Arctic Ocean Basin. Beneath a thickness of some 10 000 m (33 000 ft) of upper Paleozoic, Mesozoic and Tertiary strata is a folded and faulted lower and middle Paleozoic terrane similar to the Franklinian Geosyncline «Fold Belta. The southern margin of this province, now containing the Brooks Range, was folded and faulted during the Laramide Orogeny. A sixth province, the Arctic Coastal Plain, extends along the continent's northern margin from Alaska, to northern Greenland. Strata ranging in age from Jurassic through Pleistocene thicken abruptly from a featheredge to more than 12 000 m (39 000 ft) as they prograde into the Arctic Ocean Basin. The seventh major geologic province is the Baffin Bay Basin, which contains some 10 000 m (33 000 ft) of Mesozoic and Tertiary sediments. With the exception of the Wandel Sea Basin, each of the geological provinces has had its petroleum potential evaluated from well-data. The Arctic Slope of Alaska has hydrocarbon reserves in the order of 1.6 × 109 m3 (10.0 Bbbl) of oil and 750 × 109 m3 (26.5 Tcf) of natural gas. Recoverable reserves for the Beaufort Sea-Mackenzie Delta region of the Arctic Coastal Plain are tentatively considered to be 0.15 × 109 m3 (943 MMbbl). The potential natural gas reserves for the Beaufort Sea-Mackenzie Delta region are in the range of 0.25 × 1012 m3 (8.83 Tcf). The Sverdrup Basin has yet to have significant reserves of oil indicated but the potential reserves of natural gas range from a minimum of 0.45 × 1012 m3 (15.89 Tcf) up to what will probably prove to be more than 565 × 109m3 (20 Tcf) with effective delineation drilling. The Franklinian Geosyncline contains both oil and gas but no significant reserves have been developed. The Wandel Sea Basin, Baffin Bay Basin and Arctic Stable Platform have yet to produce indications of significant pooled hydrocarbons. The undiscovered resource potentials of the Arctic Slope and contiguous Arctic Coastal Plain of Alaska have been estimated to have median values of 3.0 × 109 m3 (18.9 Bbbl) of oil and 1.39 × 1012m3 (49.08 Tcf) of natural gas. The undiscovered resource potentials of the Beaufort Sea-Mackenzie Delta region of the Arctic Coastal Plain have expected values of 1.35 × 109m3 (8.45 Bbbl) of oil and 2.91 × 1012m3 (102.75 Tcf) of natural gas. The combined resource potential of the Arctic Interior Platform, Franklinian Geosyncline, Sverdrup Basin and Baffin Bay Basin have expected values of 0.82 × 109 m3 (5.16 Bbbl) of oil and 2.98 × 1012 m3 (105 Tcf) of natural gas. The resource potential of the Arctic Islands Coastal Plain has not yet been effectively evaluated because the greater portion of the region lies beneath constantly shifting pack-ice and data required for a meaningful assessment are not available. It is possible however, that the Coastal Plain in the Arctic Islands area may have resource potentials as great as any other previously assessed Arctic province. Formal estimates of the resource potentials of northern Greenland and the Wandel Sea Basin are not available but on the basis of comparable geology, values can be expected to be proportional to those of the Arctic Interior Platform, the Franklinian Geosyncline and the Sverdrup Basin, respectively.