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Abstract In this paper, we present a mathematical programming approach to evaluate the conceptual study of regional integrated development for Alta-Gohta discoveries in the Barents Sea. Two alternative scenarios are investigated, the first considers to tieback Alta-Gohta to a field that is 60 km away, Johan Castberg, and the second to tieback the field to Goliat, another field at 100 km further. A sensitivity analysis in terms of CAPEX and OPEX is performed to assess the trade-off between selecting the host to be Johan Castberg or Goliat. The results indicate that the profitability and host selection for a tieback development plan of Alta-Gohta is highly dependent on the start time and the costs of the project. Introduction The planning of offshore field development is complex and time-consuming as it involves several disciplines such as drilling, infrastructure location, processing capacity, wells scheduling, production planning, among others. This paper addresses conceptual studies from DG1 (feasibility) to DG2 (concept selection) of regional integrated field development alternatives of real-world fields. In this work, the feasibility and profitability of two different business concepts are assessed through a mathematical-programming based approach. The Barents Sea is the largest sea area on the Norwegian Continental Shelf (NCS) and with the largest potential for finding oil and gas reservoirs. Field development in the Barents Sea is challenging due to stricter safety and environmental regulations, Arctic weather season limitations and a lack of mature facilities and infrastructure as only a few fields are currently in production there. The Snøhvit (gas) and Goliat (oil) fields came on stream in 2007 and 2016, respectively. The oil field Johan Castberg is another field in the area currently under development and has the first oil planned to 2023. Gohta and Alta, two nearby offshore oil discoveries in 2013 and 2014, respectively, are currently under consideration for being developed. Recently, the operator reported that a standalone development of Alta and Gohta is no longer considered to be commercially viable, Staalese (2020). The main reason is that the deployment of new host facilities in the Barents Sea is too costly, and the recent fall in oil prices.
Abstract The Alta field in the Barents Sea was discovered in 2014. The reservoir formation is primarily carbonate rocks with high formation water salinity. Extensive waterflooding processes have led to an approximately 200-m rise of water level. The complexities and uncertainties regarding imbibition, current free water level, and pseudo fluid contacts within the field translate into uncertainty in the hydrocarbon volume estimation. Initial, triple-combo-based petrophysical evaluations have already been updated using advanced log measurements, as reported in an earlier publication. The evaluation is now consolidated by using two new techniques relying on advanced spectroscopy logging and combination with dielectric dispersion logging. Their objective is to further reduce the uncertainty in water saturation associated with variable apparent water salinity. The present contribution proposes a workflow that relies on two novel techniques. The first technique is a direct quantitative measurement of formation chlorine concentration from nuclear spectroscopy, which helps resolve the formation's apparent water salinity and provides a way to calibrate formation matrix sigma. The second technique relies on the existing combined inversion of dielectric dispersion and formation sigma, including explicitly invasion effects. This second technique benefits from the first technique's insight to adjust sigma interpretation and provide bounds for possible salinity variations. The workflow provides robust flushed and unflushed zone salinities, here the most uncertain and variable parameter, combined with accurate estimations of virgin and residual hydrocarbon saturations. The quantification of dielectric textural parameters describing how the water is shaped inside the formation is also improved, contributing to the improvement of virgin zone hydrocarbon saturation estimation.
Lundin Energy has completed exploration well 7221/4-1, targeting the Polmak prospect in licenses PL609 and PL1027, in the southern Barents Sea. The well was meant to prove hydrocarbons in Triassic-aged sandstones within the Kobbe formation of the Polmak prospect. After finding indications of hydrocarbons in a 9-m interval in poor-quality reservoir in the targeted formation, the well was classified as dry. The well was drilled 30 km east of the Johan Castberg discovery, by the Seadrill-operated West Bollsta semisubmersible rig. Lundin Energy, operator of Polmak, holds a 47.51% working interest.
GOM Lease Sale Generates $121 Million in High Bids; Shell Offshore Takes Top Spot Regionwide US Gulf of Mexico (GOM) Lease Sale 256 generated $120,868,274 in high bids for 93 tracts in federal waters. The sale on 18 November featured 14,862 unleased blocks covering 121,875 square miles. With $27,877,809 spanning 21 high bids, Shell Offshore Inc. took the top spot among 23 competing companies. A total of $135,558,336 was offered in 105 bids. Among the majors, Shell, Equinor, BP, and Chevron submitted some of the highest bids. Each company claimed high bids of over $17 million, signaling the GOM remains a priority in their portfolios. Last year was a record year for American offshore oil production at 596.9 million bbl, or 15% of domestic oil production, and $5.7 billion in direct revenues to the government. Offshore oil and gas supported 275,000 total domestic jobs and $60 billion total economic contributions in the US. “The sustained presence of large deposits of hydrocarbons in these waters will continue to draw the interest of industry for decades to come,” Deputy Secretary of the Interior Kate MacGregor said. Still, as Mfon Usoro, senior research analyst at Wood Mackenzie, noted, “Although bidding activity increased by 30% from the March 2020 sale, the high bid amount of $121 million still trends below the average high bid amount seen in previous regionwide lease sales, proving that companies are still being conservative with exploration spend.” Although the Bureau of Ocean Energy Management has proposed another regionwide GOM lease sale in March 2021, Usoro predicted that Lease Sale 256 “could potentially be one of the last lease sales.” “With the Biden administration set to inaugurate next year and possibly ban future lease sales, a massive land grab might have ensued,” he continued. “But companies are constrained by tight budgets due to the prevailing low oil price. Additionally, companies in the region have existing drilling inventory to sustain them in the near term. The best blocks with the highest potential reserves are likely already leased. As a result, we do not expect a potential ban on leasing to materially impact production in the region until the end of the decade.” This was the seventh offshore sale held under the 2017–2022 National Outer Continental Shelf Oil and Gas Leasing Program; two sales a year for 10 total regionwide lease sales are scheduled for the gulf. Nine Areas on Norwegian Continental Shelf Open for Bids The 25th licensing round on the Norwegian Continental Shelf, comprising eight areas in the Barents Sea and one in the Norwegian Sea, has been announced by the Norwegian Ministry of Petroleum and Energy. Known for being a country with some of the greenest credentials and policies in the world, Norway surprised observers in June by announcing plans for a licensing round that signaled further oil exploration in the Norwegian sector of the Arctic Sea. In this round, 136 blocks/parts of blocks will be available: 11 in the Norwegian Sea and 125 in the Barents Sea. The application deadline for companies is 23 February 2021. New production licenses will be awarded in Q2 2021. Johan Sverdrup Capacity Increased to Half Million B/D Following positive results in a November capacity test, the Johan Sverdrup field is set to increase daily production capacity. Capacity will rise from today’s 470,000 to around 500,000 B/D in the second increase since the field came on stream just over a year ago. The move will increase the field’s total production capacity by around 60,000 bbl more than the original basis when the field came on line. Overall, the field is estimated to have resources of 2.7 billion BOE. “The field has low operating costs, providing revenue for the companies and Norwegian society, even in periods with low prices,” said Jez Averty, Equinor’s senior vice president for operations south in development and production, Norway. The Johan Sverdrup field uses water injection to secure high recovery of reserves and maintain production at a high level. An increase in the water-injection capacity should further increase production capacity by mid-2021, according to Rune Nedregaard, vice president for Johan Sverdrup operations. Phase 2 production starting in Q4 2022 will raise the Johan Sverdrup full-field plateau production capacity from 690,000 to around 720,000 B/D. Equinor operates the field with 42.6% stake; other partners include Lundin Norway (20%), Petoro (17.36%), Aker BP (11.57%), and Total (8.44%). ConocoPhillips Makes Significant Gas Discovery Offshore Norway ConocoPhillips announced a new natural-gas condensate discovery in production license 1009, located 22 miles northwest of the Heidrun oil and gas field and 150 miles offshore Norway in the Norwegian Sea. The wildcat well 6507/4-1 (Warka) was drilled in 1,312 ft of water to a total depth of 16,355 ft. Preliminary estimates place the size of the discovery between 50 and 190 million BOE. Further appraisals will determine potential flow rates, the reservoir’s ultimate resource recovery, and plans for development. “The Warka discovery and potential future opportunities represent very low cost-of-supply resource additions that can extend our multi-decade success on the Norwegian Continental Shelf,” said Matt Fox, executive vice president and chief operating officer. The drilling operation, which was permitted to ConocoPhillips in August 2020, was performed by the Transocean-managed Leiv Eiriksson semisubmersible rig. ConocoPhillips Skandinavia AS is the main operator of the license with a 65% working interest; PGNiG Upstream Norway AS holds the remaining stake. Lundin Energy Completes Barents Sea Exploration Well, Comes Up Dry Lundin Energy has completed exploration well 7221/4-1, targeting the Polmak prospect in licenses PL609 and PL1027, in the southern Barents Sea. The well was meant to prove hydrocarbons in Triassic-aged sandstones within the Kobbe formation of the Polmak prospect. After finding indications of hydrocarbons in a 9-m interval in poor-quality reservoir in the targeted formation, the well was classified as dry. The well was drilled 30 km east of the Johan Castberg discovery, by the Seadrill-operated West Bollsta semisubmersible rig. Lundin Energy, operator of Polmak, holds a 47.51% working interest. Partners are Wintershall DEA Norge AS (25%), Inpex Norge AS (10%), DNO Norge AS (10%), and Idemitsu Petroleum Norge AS (7.5%). Polmak is the first of Lundin’s three high-impact exploration prospects drilled this quarter in the Barents Sea; the wells target gross unrisked prospective resources of over 800 million bbl of oil. The West Bollsta rig will now proceed to drill the Lundin Energy-operated Bask prospect in PL533B. Well 7219/11-1 will target Paleocene-aged sandstones, estimated to hold gross unrisked prospective resources of 250 million bbl of oil. Tullow Sells Remaining Stake in Ugandan Oil Field Tullow Oil has completed the 10 November sale of its assets in Uganda to French giant Total for $500 million. Tullow will also receive $75 million when a final investment decision is taken on the development project, calculated to hold 1.7 billion bbl of crude oil. Contingent payments are payable after production begins if Brent crude prices rise above $62/bbl. The completion of this transaction marks Tullow’s exit from its licenses in Uganda after 16 years of operations in the Lake Albert basin. The deal is designed to strengthen Tullow’s balance sheet, as tumbling crude prices combined with exploration setbacks have created problems for the company. In September, the company reported that it had lost $1.3 billion in the first 6 months of 2020 as falling oil prices forced it to write down the value of its assets. The deal cut Tullow’s net debt to $2.4 billion; it has $1 billion in cash.
ABSTRACT Fabrication and installation of offshore steel structures in the Arctic region will face some major challenges. Many of these challenges are well known and brought from the North Sea and the Norwegian offshore fields. Exploration in the Norwegian territory of the Arctic has taken place in the southwestern Barents Sea, i.e., in the area free of ice. So far, Snøhvit and Goliat fields have complete installations, Johan Castberg is now under planning. Therefore, there will be a gradual approach towards temperatures lower than −20°C (the lowest temperature in the current NORSOK standard is −14°C), which may represent a major challenge for the materials and structural integrity. The design temperature for Goliat is −20°C, while Johan Castberg will possibly be somewhat lower. Due to the continuous decrease in temperature the further north the field is, welded structures need focus concerning their low temperature properties. Although the initial base metal toughness may be excellent, a severe toughness deterioration occurs normally as result of fabrication welding. The present investigation summarizes results achieved in the steel part of the Norwegian project "Arctic Materials" concerning the low temperature fatigue properties in terms of crack growth, fracture toughness of steel weldments, the toughness scatter and its treatment, constraint corrections, effect of residual stresses and finally, the stress-strain behavior. The results are currently the basis for establishment of design guidelines for steel structures for the Arctic region. INTRODUCTION In Norway, research projects on materials behavior at low temperatures have been in progress since 2008 due to an expected increased oil and gas activity in the Barents Sea (e.g., Akselsen et al, 2011; Østby et al, 2011; Mohseni et al, 2012; Welsch et al, 2012; Østby et al, 2012a, 2012b; Jørgensen et al, 2013; Mohseni et al, 2013; Østby et al, 2013; Akselsen and Østby, 2014; Haugen et al, 2014; Mohseni et al, 2014; Wiklund et al, 2014; Hjeltereie, 2015; Kane et al, 2015). In the southwest area of the Barents Sea, north-northwest of the city of Hammerfest, the Snøhvit and Goliat fields are completed and in production. While Snøhvit consists of subsea production units only, the Goliat topside structure fabrication had design temperature of −20°C. This is below the minimum temperature set in existing NORSOK standards (NORSOK, 2008, 2011, 2014), which covers temperatures down to −14°C. Lower minimum design temperatures require project specific evaluations. The operator ENI accounted for this during fabrication and installation. At present, the Johan Castberg oilfield, is located about 100 kilometers north of the Snohvit-field, is under planning. Havis oilfield is another one, to be developed together with Johan Castberg due to the short distance between the two. Several other promising discoveries, e.g., the Gotha/Alta fields and many more, make the situation quite attractive. When moving further north, the temperature falls below −20°C, which means that the low temperature behavior of the structural steel becomes critical. Thus, the situation calls upon the importance of available adequate standards and guidelines for selection and design of steels for structural application in these areas. Such guidelines are now under development in the ongoing Norwegian project (Horn and Hauge, 2011, Horn et al, 2012; Østby et al, 2013; Horn et al, 2016, 2017).
Frye, C.C. (Hudson&Apos;S Bay Oil & Gas Co. Ltd., Calgary, Alta.) | Becker, H.W. (Hudson&Apos;S Bay Oil & Gas Co. Ltd., Calgary, Alta.) | Masuda, A. (Hudson&Apos;S Bay Oil & Gas Co. Ltd., Calgary, Alta.) | Deugau, A.V. (Hudson&Apos;S Bay Oil & Gas Co. Ltd., Calgary, Alta.)
Abstract Natural gas containing 25.65 per cent hydrogen sulfide and 4.75 per cent carbon dioxide is gathered from eight wells and transported 26 miles at a flow rate of 160 MMcf/D and at operating pressures of from 2,200 to 1,800 psig. Dry desiccant dehydrators at each wellsite maintain the dew point of the gas below 17F. Telemetering facilities permit control of field operations from a central instrument console. Corrosion control measures, design considerations and material specifications pertaining to these special conditions are discussed. INTRODUCTION Natural gas containing 25.65 per cent H2S and 4.75 per cent CO2 is produced from the Pine Creek field, Alta. It is dehydrated at wellheads, gathered at 2,200 psig and transported 26 miles to the Windfall field where it is delivered to the inlet of, injection compressors at 1,800 psig. The daily average volume of gas transported is 160 MMcf. The project is believed to be unique in its combination of percentage of hydrogen sulfide, operating pressure and transportation distance. This paper describes the project and presents details of some of the design features, corrosion control program and centralized automatic operational control. The Pine Creek field project is one phase of a joint operation of two fields - the other being the Windfall field. The two fields lie about 30 miles north of Edson, Alta. and 20 miles west of Whitecourt, Alta., respectively, as shown on the map (Fig. 1). They are owned by the same interests and operated according to a plan for maximum economic recovery of products. The Windfall Leduc D-3 reservoir contains a rich condensate-bearing gas containing 15.5 per cent H2S. The gas from the Pine Creek field contains only very small quantities of butane and heavier products. The Windfall reservoir is being cycled to obtain maximum condensate recovery using gas from the Pine Creek field as the displacing fluid, while producing the residue sales gas for both fields from the Windfall field. The Pine Creek field development and gas-gathering facilities are shown on the map (Fig. 2). The producing formation is the Leduc D-3 reef at a depth of 11,300 ft. The original reservoir pressure was 4,590 psia at 7,400 ft subsea and the temperature is 245F. Eight wells are equipped with dry desiccant dehydrators with the following capacity ratings: three at 35 MMcf/D; three at 20 MMcf/D; and two at 10 MMcf/D. WELLHEAD EQUIPMENT Dry desiccant dehydrators were designed to reduce the water content of the saturated wellhead stream to 2.5 lb of water/MMcf at 2,000 psig. This specification was necessary to prevent hydrates and corrosion forming in the pipeline which will operate at temperatures as low as 20F. A typical flow diagram is shown in Fig. 3, and Fig. 4 is a photograph of one of the wellhead installations. Some of the design details given below are subject to modification in the field.