GENERAL INTEREST — Quick Takes
Libya's NOC rival leaders reach unification deal
The chairman of Libya's National Oil Corp. and his counterpart appointed by the government in Bayda agreed to unify the state company under a single management in an attempt to end a conflict about who controls Libya's crude oil exports and oil revenues.
Mustafa Sanalla, head of NOC in Tripoli, will continue as chairman. The unified company will be based in Benghazi, said a statement on NOC's web site. Nagi el-Maghrabi will join NOC's board.
"There is only one NOC, and it serves all Libyans," said Sanalla. "This agreement will send a very strong signal to the Libyan people and to the international community that the Presidency Council is able to deliver consensus and reconciliation."
The agreement recognized the Presidency Council as Libya's highest executive authority and the House of Representatives as the highest legislative authority. NOC will submit periodic reports to committees established by both.
The two sides jointly agreed a unified budget for the rest of the current fiscal year, the news release said.
The agreement makes infrastructure a priority, especially in Benghazi. The parties indicated their desire that NOC's board should meet regularly in Benghazi in the interim if security permits. Libya split into separately governed regions in 2014, resulting in rival NOC administrations for the east and west.
El-Maghrabi told Bloomberg on July 3 that the agreement has yet to be approved by the two parliaments of Tubruk and Tripoli. Libya's oil production has fallen dramatically since Muammar Qaddafi was ousted from power in 2011.
Libya is a member of the Organization of Petroleum Exporting Countries.
Israel-Turkey link lifts offshore-gas hope
Rapprochement between Israel and Turkey lowers one of many hurdles to development of giant Leviathan natural gas field and other deepwater discoveries in the eastern Mediterranean (OGJ Online, Apr. 12, 2016).
The countries signed an agreement on June 28 that reestablishes ties severed in 2010 after the Israeli military killed 10 Turkish activists aboard the Mavi Marmara, part of a flotilla trying to breach Israel's naval blockade of Gaza.
The new agreement allows Turkey to invest in Gaza and to deliver aid to Palestinians there. Israel will create a "humanitarian fund" of $20 million for families of the Mavi Marmara victims. The Turkish aid shipments will pass through the Israeli port of Ashdod.
Turkey is a logical destination for pipeline deliveries of gas from East Mediterranean fields, further development of which depends on outlets for production exceeding Israeli needs.
But routing and financing of a pipeline would be difficult because of tensions among countries in the region. Turkey's strained relations with Cyprus also complicate prospects.
Within Israel, too, gas development remains controversial. Opposition political parties objected to the agreement with Turkey, some claiming it had been motivated by gas interests.
North American leaders seek methane cuts
Leaders of Canada, Mexico, and the US have agreed to pursue cuts in methane emissions from oil and gas operations of 40-45% by 2025.
Canadian Prime Minister Justin Trudeau, Mexican President Enrique Pena Nieto, and US President Barack Obama also said they'd try to have 50% of electric power generation come from "clean energy" by 2025.
In a statement from their June 29 summit in Ottawa, the leaders said they committed to "an ambitious and enduring North American climate, clean-energy, and environmental partnership that sets us firmly on the path to a more sustainable future."
The statement included methane among "short-lived climate pollutants."
To reduce methane emissions, it said, the leaders commit "to develop and implement federal regulations to reduce emissions from existing and new sources in the oil and gas sector as soon as possible" and "to develop and implement national methane reduction strategies for key sectors such as oil and gas, agriculture, and waste management, including food waste."
Senate to vote on new revenue-sharing bill
US Senate leaders indicate they'll support a vote later this year on legislation supported by industry groups changing how states share revenue from oil and gas produced on federal land.
A revenue-sharing bill was proposed at the end of June by Sens. Bill Cassidy (R-La), Energy and Natural Resources Chairman Lisa Murkowski (R-Alas.), Tim Scott (R-SC), Dan Sullivan (R-Alas.), Thom Tillis (R-NC), and David Vitter (R-La.).
It covers onshore and offshore production of oil and natural gas as well as of renewable energy.
The legislation aims to correct imbalances of a system under which coastal states now receive 0.07% of federal royalties while onshore states receive 50%.
"This legislation protects onshore energy-producing states' royalties and increases offshore states' share," according to a fact sheet.
The bill establishes 37.5% revenue-sharing for Alaska and Middle Atlantic states, beginning in 2027, subject caps that increase with time and disappear after 2067.
It maintains 37.5% revenue-sharing for states on the Gulf Coast but adjusts current limits, removing caps after 2055.
The bill also directs 12.5% of federal OCS revenue to specific uses in coastal states.
For onshore oil and gas production on federal land the bill restores 50% in revenue-sharing.
Cassidy said Senate Majority Leader Mitch McConnell tweeted, "Thanks to the Louisiana delegation, Senate is primed to take up the critical issue of resource production revenue sharing later this year."
Presidents of eight oil and gas industry groups wrote Cassidy a letter supporting the legislation.
Exploration & Development — Quick Takes
EnQuest makes oil find with Eagle prospect
EnQuest PLC encountered a 67-ft thick oil-bearing column in the Fulmar in its Eagle exploration well in the Greater Kittiwake Area (GKA) in the Central North Sea. The company did not encounter an oil-water contact, which it said represented potential upside volumes on the flank of the structure.
The company anticipates gross recoverable reserves to be similar to those in nearby Gadwall field, which was estimated to be 6.6 million bbl of oil and 4.4 bcf of natural gas in 2004 (OGJ Online, Oct. 1, 2004). Gadwall is part of GKA, acquired by EnQuest in 2014, and was returned to production by the company in second-half 2015. EnQuest holds 100% working interest in the Eagle well, which is being further evaluated.
GKA is located on UKCS blocks 21/12a (license P.073), 21/12d (P.1786), 21/17a (P.1415), 21/17c (P.1415), 21/18a (P.351), and 21/19 (P.238). The area includes the Kittiwake, Mallard, Gadwall, Goosander, and Grouse fields, all of which have been developed as subsea tie-backs to a steel platform located at Kittiwake.
ExxonMobil confirms oil discovery offshore Guyana
The Liza-2 well, drilled 120 miles offshore Guyana, encountered more than 190 ft of oil-bearing sandstone reservoirs in Upper Cretaceous formations, reported ExxonMobil Corp. unit Esso Exploration & Production Guyana Ltd.
The Liza-2 well was drilled to 17,963 ft in 5,551 ft of water about 2 miles from the operators first exploration well, Liza-1, on the 6.6 million acre Stabroek block.
ExxonMobil president Steve Greenlee said a production test of the Liza-2 well confirmed "the presence of high-quality oil from the same high-porosity sandstone reservoirs that we saw in the Liza-1 well completed in 2015."
The Liza-1 well, which was spudded on Mar. 5, 2015, drilled to 17,825 ft in 5,719 ft of water, and it encountered more than 295 ft of oil-bearing sandstone reservoirs (OGJ Online, May 20, 2015).
As early as 2012, the Guyana-Suriname basin began drawing interest from operators as a frontier region (OGJ Online, June 4, 2012). While Guyana has proven successful, Suriname has cooled considerably. Suriname's state-owned Staatsolie reported last year that it had received two bids for Block 58 in its 2015 offshore deepwater bid round. No IOCs, however, bid on Blocks 59 and 60 (OGJ Online, Feb. 26, 2015).
Potential recoverable resources for the Liza discovery are estimated at 800 million to 1.4 billion boe, ExxonMobil said.
Esso E&P is operator and holds 45% interest in the Stabroek block. Hess Guyana Exploration Ltd. holds 30% interest and CNOOC Nexen Petroleum Guyana Ltd. holds 25% interest.
Delek Group to drill Tamar-8 well offshore Israel
Delek Drilling LP and operator Noble Energy Mediterranean Ltd. have announced that the Tamar-8 development well will spud in this year's fourth quarter with 4 months planned for drilling, completion, and tie back. The well is 100 km west of Haifa off Israel in 1,670 m of water. Tamar-8 will target Miocene Tamar sands and is planned for a total depth of 5,050 m.
The partnership looks to increase redundancy in the existing Tamar productions system, and Tamar-8 will serve as part of its Tamar expansion project. The partnership also is planning on development of Tamar SW field.
Israel's Petroleum Commissioner of the Ministry of National Infrastructures, Energy, and Water Resources approved the current development plan (OGJ Online, June 2, 2016).
The well cost is an estimated $265 million, which includes $160 million for completion, and $105 million for construction of infrastructure for the Tamar project (tie back and subsea system). The partners have already invested $37 million for infrastructure development in Tamar SW, Delek said. Total net expense for the well will be $228 million.
Noble signed an agreement to divest 3% of its working interest in Tamar field to the Harel Group, a leading insurance provider and pension manager in Israel. The transaction value of $369 million is based on gross pretax Tamar valuation of $12 billion, Noble said. The transaction is expected to close in the third quarter. Harel partnered with private equity firm Israel Infrastructure Fund (IIF). The partners have an option to purchase an additional 1% working interest from Noble before closing.
Prior to the working interest sale, Noble operated Tamar field with 36% working interest. The company is carrying out an 11% sell down of its interest in Tamar field and anticipates the sale of the remaining 7-8% working interest with the next 36 months, at which point the operator will retain 25% working interest and operatorship in Tamar field.
Tamar has recoverable resources of 10 tcf of natural gas. In 2015, the field sold 252 MMcfd of natural gas, generating $318 million in net pretax income for the operator.
Additional partners on Tamar-8 include Delek Drilling 15.625%, Avner Oil & Gas Exploration LP 15.625%, Isramco Negev 2 LP 28.75%, and Dor Gas Exploration LP 4%.
Drilling & Production — Quick Takes
Vaalco reports well shut-in status offshore Gabon
Houston independent Vaalco Energy Inc. maintains its 2016 production guidance of 3,700-4,500 boe/d, noting that a malfunction with pumps on one well offshore Gabon is being resolved. Meanwhile, Vaalco renegotiated terms with Transocean Ltd. after releasing the Constellation II rig offshore Gabon.
Second-quarter production averaged 4,700 boe/d, up 4% from the first quarter, Vaalco said.
On June 23, electrical submersible pumps (ESPs) in the South Tchibala 2-H well failed offshore Gabon, resulting in the well being temporarily shut-in. Before the shut-in, South Tchibala 2-H produced 1,700 b/d of oil gross, or 415 b/d net to Vaalco.
Vaalco plans to move a hydraulic workover unit onto the Avouma platform to replace the ESPs. The well is expected to be back on stream by early fourth quarter. The independent selected a hydraulic unit because it was less expensive than using a jack up rig.
Net cost to Vaalco is expected to be $1.5 million. Separately, Vaalco will pay $5.1 million net for its interest for unused rig days in the Transocean contract for the Constellation II rig.
Terms call for Vaalco to pay the $5.1 million, plus Vaalco's share of demobilization charges, in seven equal monthly installments starting in July.
Steve Guidry, Vaalco's chief executive officer, said, "While low oil prices were the primary factor in our releasing the rig, the benefit of our drilling program through that point was further evidenced in the second quarter."
Vaalco has exploration, development, and production activities in Gabon, Equatorial Guinea, and Angola.
A floating production, storage, and offloading vessel is used for the Etame Marin block production offshore Gabon, which includes Southeast Etame and North Tchibala fields (OGJ Online, Aug. 29, 2016).
Stone Energy cancels contract for Ensco 8503 rig
Stone Energy Corp., Lafayette, La., has agreed with Ensco PLC to cancel the contract for the Ensco 8503 dynamically positioned deepwater drilling rig that was operating in the deepwater Gulf of Mexico.
Stone will pay to Ensco $20 million, $5 million of which was a deposit previously provided to Ensco pursuant to the drilling services contract. The contract, effective since 2015, was at a day rate of $341,000 and scheduled to expire in August 2017 (OGJ Online, Oct. 7, 2014).
Separately, Stone entered into an interim gas gathering and processing agreement with Williams Co. Inc. at Mary field in Appalachia. The interim agreement provides near-term relief for Stone by permitting Stone to resume production at the field, thereby providing greater volume to Williams.
Volumes from Mary field are now at 45 MMcfed and are expected to rise to more than 60 MMcfed in July and more than 100 MMcfed in August. These volumes are in addition to the 20 MMcfed producing from Heather and Buddy fields.
Stone shut output from the field in September 2015 citing "unacceptable" operating margins caused by low commodity pricing and fees for transportation, processing, and gathering.
Johan Sverdrup riser platform construction begins
Statoil ASA said construction has begun at the Samsung Heavy Industries yard in South Korea on the riser platform for the Johan Sverdrup development in the North Sea (OGJ Online, June 6, 2016).
The riser platform will be 124 m long, 28 m wide, 42 m tall, and weigh 23,000 tonnes. It will be the largest of four Johan Sverdrup Phase 1 platforms and serve as the receiver of land-based power and the sender of oil and gas to land.
Statoil in January 2015 awarded Kvaerner ASA the contract for engineering and procurement management for the riser platform and the processing platform, construction of which was planned to start this month.
PROCESSING — Quick Takes
Uganda reported in refinery talks with SK
The government of Uganda has resumed negotiations with SK Engineering & Construction, Seoul, for construction of a grassroots refinery after ending talks with a Russian company, according to press reports.
Uganda's Ministry of Energy and Mineral Development last year selected a consortium led by RT-Global Resources, Moscow, for the main contract for construction of a 60,000 b/d refinery to be built in two phases near Lake Alberta. The project includes a 205-km products pipeline linking the refinery with a terminal near Kampala (OGJ Online, Feb. 17, 2015). RT-Global and SK were finalists in a long period of bid evaluation.
Construction of the country's first refinery would allow development of discoveries of waxy crude oil in the Albertine basin.
The ministry was quoted as saying it ended talks with RT-Global (Rostek) after the company added demands to a deal reached in May.
Long-term oil supplies secured for Litvinov refinery
Unipetrol RPA SRO, the marketing arm of Unipetrol AS, and parent company Polski Koncern Naftowy SA (PKN Orlen) have signed separate agreements with OJSC Rosneft Oil Co. and PJSC Tatneft to supply Russian crude oil through mid-2019 to subsidiary Ceska Rafinerska AS's 5.4 million-tpy refinery in Litvinov, Czech Republic.
Under the first contract, signed on June 30, Rosneft will ship 2.9-5 million tonnes/year of Russian Export Blend crude oil (REBCO) to the Czech Republic along its Druzhba pipeline from July 1, 2016, to June 30, 2019, Unipetrol said.
Alongside benefitting from more favorable contractual terms as a result of jointly purchasing crude with PKN Orlen, the long-term contract with Rosneft covers 65% of Unipetrol's total demand for REBCO, a major refining feedstock, said Marek Switajewski, Unipetrol's chairman and chief executive officer.
As part of a second contract also signed on June 30, Tatneft will supply a total 600,000 tonnes of REBCO from July 1, 2016, to June 30, 2017, Unipetrol said.
The medium, sour Russian crude will be valued according to prevailing market conditions at the time of its delivery using the differential price of Russian Urals to the Brent Dated Index.
Petro Rabigh's refinery due new units
Rabigh Refining & Petrochemical Co. (Petro Rabigh), a joint venture of Saudi Aramco and Sumitomo Chemical Co., has let a contract to KT-Kinetics Technology SPA, a subsidiary of Maire Tecnimont SPA, Milan, to complete a clean fuels project at Petro Rabigh's 400,000-b/d refinery and chemicals complex in the port city of Rabigh on the Red Sea.
KT-Kinetics Technology will provide engineering, procurement, and construction services for the project, which will include a 17,000-b/d naphtha hydrotreater, a 220 tonne/day sulfur recovery unit, as well as related interconnecting works, Maire Tecnimont said.
Due for mechanical completion in first-quarter 2019, the project is scheduled for startup during third-quarter 2019, Maire Tecnimont and Petro Rabigh said.
Maire Tecnimont valued the EPC contract at about $148 million.
First announced on Oct. 4, 2015, the clean fuels project comes as part the Petro Rabigh Phase II development, a goal of which is to increase the complex's compliance with regional environmental regulations, Petro Rabigh said.
Petro Rabigh completed mechanical works for the Rabigh Phase 2 ethane cracker expansion in March, which lifted ethane gas processing capacity by 30 MMcfd to 125 MMcfd (OGJ Online, Apr. 26, 2016).
Once fully commissioned, Rabigh Phase 2 project will be able to produce more than 1.3 million tpy of paraxylene as well as a diverse slate of other petrochemical products, including ethylene propylene diene monomer rubber; thermoplastic olefin; methyl methacrylate; and poly methyl methacrylate.
TRANSPORTATION — Quick Takes
Tangguh LNG firms reach FID for expansion project
Partners in the Tangguh production-sharing contract have taken a final investment decision (FID) for development of the Tangguh LNG expansion project in the Papua Barat province of Indonesia.
The BP PLC-led project will add a third LNG train, which will add 3.8 million tonnes/year of production capacity to the existing facility, bringing total plant capacity to 11.4 million tpy. The project also includes two offshore platforms, 13 production wells, an expanded LNG loading facility, and supporting systems.
This FID follows Indonesia's approval of the Plan of Development II in late 2012, and an environmental and social impact assessment in 2014 (OGJ Online, Nov. 5, 2012; Aug. 4, 2014). Front-end engineering and design contracts were let to two consortia in 2014 (OGJ Online, Oct. 22, 2014).
Awards for the project's key engineering, procurement, and construction contracts are expected in the third quarter with construction to begin thereafter. Operation is expected in 2020.
BP notes that 75% of Train 3's annual LNG production has been sold to the Indonesian state electricity company PT PLN (Persero). The remaining volumes are under contract to Kansai Electric Power Co. in Japan.
The Tangguh LNG project is operated by BP Berau Ltd. on behalf of the other PSC partners as contractor to SKK Migas. BP Berau and its affiliates in Indonesia hold 37.16% interest.
PHMSA seeks comments on regulating CO2 pipelines
The US Pipeline & Hazardous Materials Safety Administration is seeking comments on a report it developed, "Background for Regulating the Transportation of Carbon Dioxide in a Gaseous State," as part of its effort to develop minimum requirements for safely transporting CO2, the US Department of Transportation agency announced.
The report evaluates present and potential future CO2 gaseous pipelines and outlines PHMSA's approach for establishing regulations, it said in a June 27 Federal Register notice. The agency is seeking to better understand where CO2 pipelines, which it does not regulate currently, are located so it can establish requirements as mandated under the 2011 Pipeline Safety Reauthorization Act.
After carefully reviewing the available information with regard to gaseous carbon dioxide pipelines, PHMSA has been unable to identify specific gaseous CO2 pipelines or pipeline operators which would potentially be subject to future regulation under Section 15 of the 2011 law, the agency said.
It said it is seeking comments to better understand the possible effects of the regulatory scenarios presented within the report, information considered within the report, conclusions that could be drawn from the report, information missing from the report, and to better understand the locations and extent of existing or planned gaseous CO2 pipelines.
