GENERAL INTEREST Quick Takes
Eni, OMV buying ADNOC Refining interests
Eni SPA and OMV AG will buy interests in ADNOC Refining at prices that Abu Dhabi National Oil Co. said establishes the enterprise value of its refining subsidiary, with its 922,000-b/d of refining capacity, at $19.3 billion.
Eni will acquire 20% interest for $3.3 billion after deduction of net debt and adjustments, making the enterprise value of its share $3.9 billion. OMV will pay an estimated $2.5 billion for 15% stake with an enterprise value of $2.9 billion.
ADNOC retains the remaining interest. The company signaled the sale of downstream interests in mid-2017, when it announced plans to expand partnerships across its oil and gas operations (OGJ Online, July 10, 2017).
ADNOC Refining operates the Ruwais East, Ruwais West, and Abu Dhabi refineries. The high-conversion Ruwais complex is integrated with petrochemical facilities able to produce 1.5 million tonnes/year of propylene.
The purchases will increase global refining capacities by 35% for Eni and by 40% for OMV.
ADNOC Refining plans to expand refining capacity at Ruwais, now a combined 817,000 b/d, with the addition of a 600,000-b/d refinery and to expand petrochemical capacity at the complex (OGJ Online, Sept. 19, 2018).
ADNOC, Eni, and OMV also agreed to form a trading joint venture, Abu Dhabi Global Markets, expecting to begin physical and derivative trading as early as 2020.
“The trading joint venture will help guide ADNOC Refining’s activity and operational decision-making, ensuring ADNOC secures the best possible value from its refining and trading activity,” ADNOC said in a press release. “The stated objective of the trading joint venture is to expand its global presence over time.”
E. Timor okays use of oil fund for Sunrise purchase
East Timor President Fransisco Guterres has approved a decree allowing use of the country’s petroleum fund for the $650-million acquisition of the Royal Dutch Shell PLC and ConocoPhillips’s interests in the Greater Sunrise gas-condensate fields in the Timor Sea.
Guterres had previously vetoed the proposal, saying at the time that it could allow the petroleum funds to be misused. He called for the proposal to be revised.
The proposal, however, has since been overwhelmingly endorsed by the East Timor Parliament and, under the country’s law, the president can veto a bill only once. He must then ratify it if the bill wins parliamentary approval.
The acquisitions became public last year. In October 2018 ConocoPhillips said it would sell its 30% interest in the fields for $350 million. Shell followed suit the following month when it announced East Timor’s agreement to buy the major’s 26.56% interest for $300 million.
The acquisitions were subject to approval by the East Timor Council of Ministers and Parliament.
This recent presidential approval removes a 20% cap on state participation in oil projects and enables Sunrise to bypass Parliamentary approvals in the future.
The fields straddle the maritime boundary between Australia and East Timor and a long-running dispute over the border delayed the project development for many years. The border dispute was settled between the two countries in 2018.
The Greater Sunrise gas project involves development of Sunrise and Troubadour gas fields, which were discovered by the Woodside Petroleum Ltd.-led joint venture in 1974. The fields are estimated to hold a total of 5 tcf of gas and 226 million bbl of condensate.
Woodside and former partners have consistently resisted East Timor’s calls for development of Greater Sunrise via a pipeline to an LNG plant on the country’s south coast, preferring a plant to be in Darwin on Australia’s north coast.
Woodside remains operator with 33.4%. The remaining 10% is held by Osaka Gas Co. Ltd.
Sawan to succeed Brown as Shell upstream director
Wael Sawan has been appointed upstream director of Royal Dutch Shell PLC, and will become a member of the executive committee, effective July 1. He currently serves as executive vice-president, deepwater. He joined Shell in 1997 and has held commercial and operational leadership roles across the upstream, integrated gas, and downstream businesses.
Sawan succeeds Andy Brown, who will remain available to assist with the transition until Sept. 30, at which time he will leave the company after 35 years of service.
McKinney named as SandRidge president, CEO
Paul D. McKinney has succeeded William M. Griffin as president and chief executive officer of SandRidge Energy Inc., Oklahoma City.
McKinney has 35 years of industry experience and most recently was president and chief operating officer of Yuma Energy Inc. Griffin will continue to serve on SandRidge’s board.
Exploration & DevelopmentQuick Takes
Ukraine to outline details of licensing rounds
The Ukraine plans a series of licensing rounds for oil and gas blocks as the nation seeks to end its dependence on imported gas. International oil companies are being invited to participate in upcoming auctions and production-sharing agreements.
The first round will be for 10 blocks covering 1,120 sq miles in six regions. The auctions are scheduled for Mar. 6.
Details were discussed at the Ukrainian Gas E&P Forum Jan. 29 at the Geological Society in London where speakers included representatives of Ukraine’s National Investment Council and the Association of Gas Producers of Ukraine.
The Ukrainian government plans to offer production-sharing agreements (PSAs) for 12 onshore blocks, covering more than 8,200 sq miles. PSA tenders are expected to be announced in February or early March, at which time bidders will have 3 months to submit their applications.
This is the first time since 2012 that Ukraine is offering oil and gas blocks to investors under PSAs.
OVL tests second strike on Colombian block
ONGC Videsh Ltd. (OVL) is testing an oil discovery on trend with its 2017 Mariposa-1 oil strike on Block CPO-5 in Colombia and plans further drilling (OGJ Online, May 5, 2017).
The operator, a wholly owned unit of India’s Oil & Natural Gas Corp., reported earlier this month that it had logged 284 ft of gross oil pay in the Lower Sands (LS-3) unit of the Cretaceous Une formation in its Indico-1 well. The well hit pay at 9,833 ft MD and bottomed in Paleozoic rocks at 10,602 ft MD.
Through perforations of a 40-ft interval in the upper part of the LS-3 unit, the well flowed 4,000 b/d of 35.9° gravity oil with 0.3-0.4% bs&w and negligible gas through a 40/64-in. choke. Top-hole pressure was 241 psi.
OVL continues testing the well, which is 6.5 km from the Mariposa discovery, with varying choke sizes.
It plans more exploratory wells and seismic surveys to assess what it calls an “important Cretaceous clastic corridor.”
OVL holds a 70% interest in the block. Petrodorado South America SA Sucursal of Colombia holds 30%.
Valeura Energy drills, logs Turkey appraisal well
Valeura Energy Inc., Calgary, has completed drilling and logging an appraisal well in the Thrace basin in northwestern Turkey.
The Inanli-1 well, which was spudded in October 2018 and drilled to a total depth of 4,885 m, reached an objective section at 3,270-4,885 m (1,615-m gross column) of high net-to-gross sandstone that is interpreted to contain over-pressured gas.
Based on drilling and wireline logging data, Inanli-1 encountered the top of the primary objective sands at 3,270 m at the base of the Mezardere formation, after which high net-to-gross sandstone was present almost continuously down to TD within the Kesan formation. The company said that more natural fracturing was encountered than in the Yamalik-1 well, including four stand-out intervals.
The well is being cased and will be left in a state ready for completion, fracturing, and production testing. Completion operations are planned to begin at the end of this year’s first quarter.
The KCA Deutag T-700 drilling rig will be released from the location in the coming days and will begin relocating to the next appraisal well location: Devepinar-1.
Sean Guest, president and chief executive officer, said, “We are encouraged by the results and look forward to now drilling Devepinar-1, 20 km west, to prove that the play is pervasive across the basin.”
Lukoil’s fourth Eridu well confirms model
Lukoil said testing of its fourth well in Eridu oil field on Block 10 in southern Iraq confirmed the geologic model (OGJ Online, Dec. 15, 2017).
The discovery well, Eridu 1, flowed on test during early 2017 at more than 8,000 b/d of oil from the Middle Cretaceous Mishrif formation (OGJ Online, Feb. 22, 2017).
Lukoil said the fourth well flowed dry crude oil at commercial rates.
It plans “several” appraisal wells and further 2D and 3D seismic surveys on the 5,800-sq-km block, which is 150 km west of Basra and 120 km from West Qurna-2 oil field.
Lukoil holds 60% and is operator. Inpex Corp. holds 40%. The Iraqi party to the agreement is represented by state-owned Thiqar Oil Co.
SOCAR, KazMunayGas eye Caspian cooperation
Officials of the national oil companies of Azerbaijan and Kazakhstan have signed a memorandum of understanding covering joint exploration in the Caspian Sea and including refurbishment of a Kazakh jack up rig in Baku. State Oil Co. of Azerbaijan Republic will use the modernized Satti rig, owned by Kazakhstan’s KazMunayGas, for drilling in the Caspian.
Possible areas of cooperation identified in the MOU, signed in Baku, include a joint study of geological and geophysical data and logistics and trading of oil and oil products.
Drilling & ProductionQuick Takes
Equinor gains approval to extend life of Asgard A
Equinor and its partners will consider new drilling targets and wells linked to Asgard A in the Norwegian Sea, as well as additional measures to improve recovery following approval from the Norwegian Petroleum Directorate (NPD) to extend the technical lifetime for the facility until 2027—about 12 years longer than the original plan.
The facility plays an important role in recovering as much remaining liquid reserves as possible from Smorbukk and Smorbukk Sor, as most of the gas-injection wells in the fields are tied in to Asgard A and will rely on the gas injection from Asgard A through the 2020s, NPD said.
New drilling targets and wells linked to Asgard A will be considered in both the shorter and longer term. An improved recovery project involving “low wellhead pressure” has an expected start-up date in 2022.
Recovery of Trestakk as well as the Blabjorn discovery depends on an extended life of Asgard A (OGJ Online, Apr. 5, 2017). The facility’s technical lifetime was originally based on 20 years of operation and expires this year.
Partners for Asgard are Petoro AS 35.69%, operator Equinor 34.57%, Var Energi AS 14.82%, Total E&P Norge AS 7.68%, and ExxonMobil Exploration & Production Norway 7.24%.
Eni starts up more Vandumbu production off Angola
Eni SPA reported start-up of a new production well in Vandumbu field, about 350 km northwest of Luanda and 130 km west of Soyo, in the West Hub of Block 15/06, offshore Angola.
VAN-102 start-up, via the N’Goma floating production, storage, and offloading vessel, follows start-up of the second subsea multiphase boosting system (SMBS), and achieved a performance of about 13,000 bbl.
Vandumbu field started producing oil in November 2018, 3 months ahead of schedule. Ramp-up will be completed in this year’s first quarter with the start-up of the water injection well. With the start-up of another production well in Mpungi field, Block 15/06 production is expected to total about 170,000 boe/d, further extending the production plateau.
Eni, operator, and Sonangol P&P each hold 36.84% interest in Block 15/06. SSI Fifteen Ltd. holds 26.32%.
BPTT lets contract for Cassia compression project
BP Trinidad & Tobago LLC (BPTT) has let a contract to McDermott International Inc. for the engineering, procurement, and construction of the Cassia compression platform, 57 km southeast offshore Trinidad and Tobago.
McDermott will provide EPC, hook-up, and commissioning of the 8,100-tonne Cassia C topsides, a 3,400-tonne jacket, and a 720-tonne bridge to link Cassia C with the existing Cassia B platform that currently sits in 68 m of water.
The scope also includes brownfield modifications at Cassia B. The compression platform will be fabricated and constructed at McDermott’s fabrication facility in Altamira, Mexico. Trinidad Offshore Fabrication Co. will fabricate the jacket and the bridge landing frame.
Engineering services will be provided by McDermott’s offices in Houston, Chennai, and Dubai, with the project management team and procurement being performed from Houston.
The EPC contract follows the completion of a detailed engineering and long lead procurement services contract McDermott completed for Cassia C, as well as the completion of the EPC, installation, and commissioning contract of the Angelin project for BPTT (OGJ Online, June 7, 2017).
Cassia C is BPTT’s third Cassia platform, handling gas from its operations in the Columbus basin (OGJ Online, Aug. 14, 2017). Cassia C will receive 1.2 bscfd of hydrocarbon gas through new piping from Cassia B across the bridge. The gas will be compressed in three gas turbine driven compressors and returned to Cassia B for export. Liquids from Cassia C and Cassia B will be combined and boosted for export.
The contract was awarded in two phases, with an initial booking in fourth-quarter 2018 for early engineering and procurement work. The remainder of the award will be reflected in McDermott’s first-quarter 2019 backlog.
LLOG lets subsea contract for Stonefly development
LLOG Exploration Co. LLC, Covington, La., has let a contract to McDermott International Inc. for deepwater subsea pipeline tiebacks and structures from the Stonefly development to the Ram Powell platform 140 miles southeast of New Orleans.
Work includes project management, installation engineering, subsea structure and spoolbase stalk fabrication, and subsea installation of the subsea systems to support a two-well subsea tieback via a 60,000 ft, 6-in. pipeline in 3,300-4,100 ft of water. McDermott also will design, fabricate, and install a steel catenary riser, a pipeline end manifold, and two inline sleds.
The Stonefly development includes the Viosca Knoll 999 area where McDermott is slated to use its 50-acre spoolbase in Gulfport, Miss., for fabrication and reeled solutions. Installation of the subsea tiebacks and structures using the North Ocean 105 vessel is scheduled to begin in this year’s third quarter. Structure design and installation engineering began in January.
The Talos Energy-owned Ram Powell tension-leg platform lies in 3,200 ft of water on Viosca Knoll Block 956, and is capable of processing 60,000 b/d of oil and 200 MMcfd of gas.
PROCESSINGQuick Takes
CVR Refining lets contract for Wynnewood refinery
CVR Refining LP subsidiary Wynnewood Refining Co. LLC has let a contract to KBR Inc. to provide engineering and design services related to the service provider’s proprietary Solid Acid Alkylation Technology (K-SAAT) for the operator’s 74,500-b/d refinery in Wynnewood, Okla.
As part of the contract, KBR said it will deliver basic engineering and design services for its K-SAAT technology, which could lead to an opportunity to implement the technology as part of a revamp of the refinery’s existing hydrofluoric acid (HF) alkylation unit.
A timeframe for when Wynnewood Refining would proceed with implementation of the HF alkylation unit’s conversion to a different technology was not revealed.
CAP lets contract for Indonesian petchem complex
PT Chandra Asri Petrochemical Tbk. (CAP) subsidiary PT Chandra Asri Perkasa (CAP2) has let an additional contract to McDermott International Inc. to provide process technology for CAP2’s planned petrochemical complex in Indonesia.
As part of the contract for what will be CAP2’s second petrochemical complex in the region, McDermott will deliver detailed engineering of eight proprietary short residence time (SRT) ethylene cracking heaters for the steam cracker, which will produce 1.1 million tonnes/year of ethylene and 600,000 tpy of propylene using McDermott’s proprietary Lummus SRT pyrolysis heater technology, the service provider said.
Valued at $1-50 million and to be reflected in McDermott’s fourth-quarter 2018 backlog, this latest contract follows CAP2’s earlier award to McDermott to provide licensing and basic engineering of the proposed complex’s ethylene plant.
The complex also will feature a butadiene extraction unit equipped to produce 175,000 tpy of butadiene using BASF Corp.-Lummus butadiene extraction technology.
CAP2’s complex, which will join CAP’s existing petrochemical complex at Ciwandan, Cilegon, in Indonesia’s Banten province, comes as part of the operator’s program to boost local petrochemical production to help meet rising Indonesian demand.
CAP, itself a subsidiary of PT Barito Pacific Tbk., Jakarta, previously let a contract to McDermott (formerly CB&I) to supply materials for the planned revamp of existing furnaces at the naphtha cracker of its 860,000-tpy Ciwandan ethylene plant to expand capacity to 900,000 tpy by first-quarter 2020.
TRANSPORTATIONQuick Takes
ExxonMobil advances Wink to Webster crude line
ExxonMobil Corp., Plains All American Pipeline LP, and Lotus Midstream LLC have formed the Wink to Webster Pipeline LLC joint venture and ordered nearly 650 miles of US-sourced 36-in. line pipe to construct a common-carrier pipeline to transport more than 1 million b/d of crude oil and condensate from multiple locations in the Permian basin to the Texas Gulf Coast.
The pipeline will have origin points at Wink and Midland, Tex., to multiple locations including Webster and Baytown, Tex., with connectivity to Texas City and Beaumont, Tex.
Plains will lead project construction and has already initiated preconstruction work. The partners said existing pipeline corridors would be used when possible to limit potential community and environmental disruptions.
The project, underpinned by a sizable volume of long-term commitments, is targeted to begin operations in first-half 2021.
WBI Energy to construct Bakken gas project
MDU Resources Group Inc. subsidiary WBI Energy Inc., Bismark, ND, plans to construct 67 miles of pipeline, compression, and ancillary facilities to transport natural gas in the Bakken region.
The North Bakken Expansion Project, as designed, would provide 200 MMcfd of gas transportation capacity starting near Tioga, ND, and extending to a new connection with Northern Border Pipeline in McKenzie County, ND.
Cost to construct the 20-in. pipeline and two associated compressor facilities is $220 million. Dependent on regulatory and environmental permitting and finalization of transportation agreements with customers, construction is expected to begin in early 2021 and be completed late that year.
An open season resulted in long-term transportation commitments from gas production, gathering, and processing companies.
WBI Energy will begin the prefiling process using the US Federal Energy Regulatory Commission’s National Environmental Policy Act by late in this year’s first quarter. The final project design, route, and cost will be based on customer demand and final agreements, as well as the engagement of other project stakeholders through the prefiling process. If warranted by customer demand, the project could be expanded to provide transportation capacity of as much as 375 MMcfd.
AGIG to expand Tubridgi onshore gas storage facility
The Australian Gas Infrastructure Group (AGIG) has reported plans for a further expansion to its Tubridgi gas storage facility in northwest Western Australia.
The group has followed its $74-million (Aus.) redevelopment and commissioning of the Tubridgi facility in 2017 with a final investment decision in the last week to complete a seismic survey and expansion of the injection and withdrawal capacity to 90 terajoules/day and 60 terajoules/day, respectively.
Tubridgi is a shallow depleted gas field with an aerial extent of 35 sq km originally operated by Doral Resources Ltd. on the coast of Western Australia about 25 km southwest of Onslow. It produced between 1991 and 2004 into the domestic grid via an 85-km spur line into the Dampier-Bunbury trunk line.
Initial plans following the field’s depletion in 2004 were to convert the field into a 42 petajoule storage facility with injection and withdrawal rates of 50 terajoules/day.
The new expansion comes in response to the strong demand in the Western Australian gas market for storage services, according to Andrew Staniford, AGIG’s chief customer officer.
The seismic survey will be state of the art, producing 3D mapping of the reservoir that lies 550 m underground. The plan is to define the maximum storage volume and derisk any additional wells that may be installed in the future.
The debottlenecking to increase injection and withdrawal capacity has been assessed following a year of operational data and technical input from the in-house engineering team.
The facility, the largest gas storage in Western Australia, is now owned and operated by AGIG, which is an amalgam of Australian Gas Networks, Dampier to Bunbury Pipeline, and Multinet Gas Networks that banded together in 2017.
AGIG has 34,000 km of distribution networks throughout Australia and more than 3,500 km of gas transmission pipelines.
