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Lukoil has begun wildcat drilling at an exploration well at the Shirotno-Rakushechnaya prospect structure, located north of the V.I. The well is at a water depth of 4.5 m and will be drilled to a target depth of 1650 m from Eurasia Drilling Co.'s (EDC) jackup rig Astra. The company said it also began studying the Khazri and Titonskaya features of a new block in the south part of the Caspian Sea, within the central Caspian license block in the East Sulaksky bank. It is drilling at the Khazri feature from EDC's jackup floating rig Neptune to the target depth of 5200 m; the sea is 45 m deep at the point of well. Lukoil is constructing the sixth well at a riser block platform at the Yury Korchagin field. The length of the borehole of this horizontally directed producing well is 5165 m, and daily target production is 348 mt.
Lukoil Starts Drilling Caspian Sea Prospects Lynnmarie P. Flowers, Technology Editor Lukoil has begun wildcat drilling at an exploration well at the Shirotno-Rakushechnaya prospect structure, located north of the V.I. Grayfer field in the Caspian Sea. The well is at a water depth of 4.5 m and will be drilled to a target depth of 1650 m from Eurasia Drilling Co.’s (EDC) jackup rig Astra. The company said it also began studying the Khazri and Titonskaya features of a new block in the south part of the Caspian Sea, within the central Caspian license block in the East Sulaksky bank. It is drilling at the Khazri feature from EDC’s jackup floating rig Neptune to the target depth of 5200 m; the sea is 45 m deep at the point of well. Lukoil is constructing the sixth well at a riser block platform at the Yury Korchagin field. The length of the borehole of this horizontally directed producing well is 5165 m, and daily target production is 348 mt. The drilling is being done by EDC’s jackup rig Mercury. Since it began developing the Russian sector of the Caspian Sea in 1999, Lukoil has discovered 10 fields in the sector and has produced 7 billion BOE of recoverable hydrocarbon reserves. Petrobras Starts Production in Atapu Pre-Salt Petrobras started production of oil and natural gas from the shared deposit of Atapu, through platform P-70, in the eastern portion of the Santos Basin pre-salt, near the Búzios field offshore Brazil. The platform is the fifth floating, production, storage, and offloading (FPSO) of the series of replicants; it can process up to 150,000 B/D and treat up to 6 million m of natural gas. The unit will operate in a depth of 2300 m, with an interconnection of up to eight producing and eight injection wells. Petrobras holds 89.257% of the rights to the deposit in partnership with Shell Brasil Petróleo (4.258%), Total E&P do Brasil Ltda (3.832%), Petrogal Brasil (1.703%) and PPSA, representing the Union (0.950%). With continued developments on the Iara, Mero, and Lapa projects, Brazil’s group production should reach 150,000 B/D by 2025, Total’s President of Exploration and Production Arnaud Breuillac said. Egypt: Twelve Deals Worth $1 Billion Egypt has completed 12 petroleum agreements worth at least $1 billion in addition to a $19-million signature bonus for drilling 21 wells, said Tarek E-Molla, Egypt’s Minister of Petroleum and Mineral Resources. These bills include eight projects for the Egyptian Natural Gas Holding Co. in the Mediterranean; Ganoub El Wadi Petroleum Holding Co.’s three projects in Blocks 1, 3, and 4 in the Red Sea; and Egyptian General Petroleum Corp.’s project in East Abu Sennan in the western desert. The agreements were made with several American, British, French, Emirati, and Kuwaiti companies including Chevron, Edison, BP, Total, Shell, Nobel, Kufpec, and Mubadala. Majors Partner To Develop Norwegian Shelf Aker BP, Equinor, and LOTOS Explo-ration and Production Norge AS have reached agreement on commercial terms to jointly develop the Krafla and Fulla region and the north of Alvheim area (NOA) on the Norwegian Continental Shelf. Total investments are forecast to exceed $5.2 billion. The area comprises several licenses and complex reservoirs that contain oil and gas discoveries with recoverable resources exceeding 500 million BOE. Equinor is the operator of the Krafla license and Aker BP operates the NOA and Fulla licenses. The parties are preparing to submit plans for development and operation of these fields in 2022. Their proposal calls for a processing platform in the south operated by Aker BP, an unmanned processing platform in the north operated by Equinor, and various satellite platforms and tiebacks. CNOOC Makes Discovery in South China Sea CNOOC Ltd, a branch of the China National Offshore Oil Corp., said in late June it had made a discovery at Huizhou 26-6 in the eastern South China Sea. The company said the discovery marked a “breakthrough” in the Paleo-gene and buried-hill complex oil and gas reservoir in the Pearl River Mouth Basin. This is its first time to achieve commercial and “highly productive” oil and gas flow in buried-hill exploration in the eastern South China Sea. CNOOC expects the field to become the first mid-to-large sized condensate oil and gas field in the shallow-water area of the basin. The field was tested to produce around 2,020 B/D and 15.36 MMcf/D. CNOOC encountered oil and gas pay zones with a total thickness of approximately 1,385 ft. In March, CNOOC made a “large-sized” discovery in Bohai Bay. Kenli 6-1 encountered oil pay zones with a total thickness of approximately 65 ft and produced around 1,178 B/D. Energean, Edison Slice $284 Million From E&P Deal Italy’s Edison has cut $284 million from the sale of its E&P business to Energean after excluding Algerian and Norwegian assets from the deal. Last year, Mediterranean-focused Energean agreed to buy Italy-based Edison’s oil and gas operations for up to $850 million, but the parties later revised the deal. In April, Edison’s Algerian assets, worth $155 million, were excluded from the scope of its sale to Energean, citing a lack of authorization from Algeria’s Ministry of Energy. Then in mid-May, Neptune Energy terminated its agreement to acquire Edison’s UK and Norwegian subsidiaries from Energean. The acquisition had been contingent on the closing of Energean’s acquisition of Edison, which is expected by the end of this year. Neptune would have paid up to $280 million for the North Sea producing, development, and exploration assets; it will pay Energean $5 million for cancelling the deal. Edison will retain control of Edison Norge, which controls the group’s upstream activities in Norway. The company’s E&P portfolio includes producing assets in Egypt, Italy, Algeria, the UK North Sea, and Croatia, as well as development assets in Egypt, Italy, and Norway. Energean will still acquire Edison’s UK North Sea subsidiaries, which include interests in the large Glengorm and Isabella gas-condensate discoveries. Energean said it still plans to complete the sale of Edison E&P’s UK and Norwegian subsidiaries to Neptune for $250 million plus contingent consideration of up to $30 million “as soon as reasonably practicable.” Energean has access to more than $1 billion in credit and debt to complete the development of the Karish and Tanin gas fields offshore Israel, where production is due to start early in 2021. Petrobras Sets New Production Records Offshore Brazil Brazilian oil and gas company Petrobras has reached a production record on Búzios field located in the Santos Basin pre-salt offshore Brazil. Petrobras reported that on 27 June, platforms P74, P75, P76, and P77 - installed on the Búzios field - had reached new production records of 664,000 B/D and 822,000 BOED. Petrobras says its 13 refineries in Brazil increased oil processing in May but are still operating below pre-COVID levels, rising to 1.645 million B/D from a 20-year low in April. In January, hydrocarbons output in Brazil topped 4 million BOED for the first time ever, as Petrobras reached plateau at four floating production, storage, and offloading vessels at the Búzios field. The field was discovered in 2010 and started production in April 2018 through the P74 FPSO; the rest of the units were subsequently added to the field. Saudi Aramco Suspends Contract With Seadrill Rig Saudi Aramco has suspended the contract for the Seadrill co-owned jackup drilling rig for up to 1 year. The 2013-built AOD II, an independent leg cantilever jackup, has an $89,900 a day contract with Saudi Aramco in Saudi Arabia. The 3-year contract was signed in April 2020. The rig is owned by Asia Offshore Drilling Ltd., which is co-owned by Seadrill and the Thai offshore services provider Mermaid Maritime. Mermaid said the suspension was due to the drop in crude oil prices and adverse impacts to the oil and gas industry, the offshore drilling services sector, and the “ultimate customer” - which likely is Saudi Aramco. The suspension, which had started on completion of the last well in progress, will be at a zero day rate and will extend the term of the contract for a period equal to the suspension, Mermaid said. Saudi Aramco has also suspended jackup contracts for Shelf Drilling’s High Island IV rig, and Noble Energy’s Noble Scott Marks. Petronas Hires Maersk Rig for Suriname Drilling Malaysian oil company Petronas has hired Maersk Drilling’s rig Maersk Developer for a one-well exploration campaign off the coast of Suriname. The campaign will take place in Block 52 which covers an area of 1,834 sq mi in the Suriname-Guyana basin. Maersk Drilling said the contract is expected to start in Q3 or Q4 2020, with an estimated duration of 75 days. The value of the contract is approximately $20.4 million, including integrated drilling services, mobilization, and demobilization fees. The contract includes an additional one-well option. In May, Petronas completed the farm-down of 50% of its participating interest in Block 52 offshore Suriname to ExxonMobil Exploration and Production Suriname. The Maersk Developer is a DSS-21 column-stabilized dynamically positioned semisubmersible rig, able to operate in water depths up to 10,000 ft. It is currently warm-stacked in Aruba following its latest contract offshore Trinidad and Tobago.
Abstract Rakushechnoe-8 is one of the exploration wells drilled in the Northern Caspian Sea. The understanding of the geometry and performance of the propped fracture completion in the Apt formation was considered critical for the economical development of this offshore oilfield. Because of this, and the potential risk of fracture breaking into the water zone below, no resources were spared and robust engineering methods were applied for the first time in Russian offshore operations to determine the formation productivity without and with a hydraulic fracture completion in place. This case history will detail how a planned joint engineered approach provided critical information for the reservoir and production teams to determine the formations potentials, ensuring at the same time reliable and safe offshore operations. After a detailed feasibility and engineering study, a local supply vessel was converted into a stimulation vessel to meet the maritime regulation requirements and projected needs of the Russian Federation. As part of the Project Readiness Assessment, the 4000-HHP strong frac equipment was mock-assembled on the dock, tested, and all the hazards evaluated before sailing. The joint engineering team prepared a rigorous plan for multi source data collection before, during, and after treatment operations. The plan included running dipole cased hole acoustic measurements before and after the frac treatment, bottomhole pressure gauges, a complete mini-frac test, multiple post mini-frac temperature logging runs, production logging runs, and well testing and sampling operations before and after the frac. Finally, a novel vertical seismic profile and micro-seismic measurement was employed to further understand the hydraulic fracture behavior in the Apt formation. The data analyzed before the main fracture treatment enabled safe placement of all 49 tons of 16/20 mesh Intermediate Strength Proppant (ISP) through the drillstem test string obtaining a Cfd = 2.7 deemed optimal for the formation. Post frac measurements and semi numerical modeling indicated that the mechanical model created before the mini frac required some additional modifications and that the propped fracture remained within the target zone. The acoustic and microseismic post frac measurements and well-test results correlated with the expected fracture effective half-lengths and conductivity, confirming that the preparation and execution involved with attaining accurate measurements provided significant value.