GENERAL INTEREST — Quick Takes
Court rejects part of Leviathan framework
Plans to develop giant Leviathan natural gas field off Israel suffered another setback on Mar. 27 when the High Court of Justice rejected part of a regulatory framework supported by Prime Minister Benjamin Netanyahu (OGJ Online, Feb. 15, 2016).
The court said the agreement's "stability clause"-which guarantees the government won't make major regulatory changes for 10 years-required an alternative legal mechanism. It gave the government 12 months to solve the problem.
The court affirmed the rest of the regulatory framework al-lowing development of Leviathan field and expansion of nearby Tamar gas field to proceed. The framework received Cabinet approval last August but encountered antitrust resistance, which Netanyahu overrode after naming himself economy minister to secure the needed authority.
"The court's ruling, while recognizing that timely natural gas development is a matter of strategic national interest for Israel, is disappointing and represents another risk to Leviathan timing," said David L. Stover, president and chief executive officer of Noble Energy Inc., the Leviathan and Tamar operator.
"Development of a project of this magnitude, where large in-vestments are to be made over multiple years, requires Israel to provide a stable investment climate."
Noble estimates resources at 22 tcf in Leviathan field and 10 tcf in Tamar, which produces about 800 MMcfd. Both fields are in deep water.
Netanyahu called the court ruling "a grave threat to the development of Israel's gas reserves" and said it aggravated an image of Israel "as a country with exaggerated judicial involvement in which it is difficult to do business."
He said he hoped the main parts of the gas framework would survive, indicating he will push the government to resolve the stability-clause issue.
BP, Kuwait Petroleum sign framework agreement
BP PLC and Kuwait Petroleum Corp. (KPC) signed a broad framework agreement for possible opportunities inside and outside Kuwait covering oil, gas, trading, and petrochemicals.
The agreement was signed by BP Chief Executive Officer Bob Dudley and KPC Chief Executive Nizar Mohammad Al-Adsani.
"BP's commitment to Kuwait dates back to our participation in the discovery of the giant Burgan oil field in the 1930s and we are there today extending the life of the field," Dudley said.
The framework agreement includes opportunities for joint investment in future oil and gas exploration, and possible oil and gas trading deals, including LNG.
Investment in midstream and petrochemical projects globally will also be considered, including potentially using BP's proprietary paraxylene technology as part of KPC's petrochemicals projects.
In 2014, BP signed a technical services agreement with KPC subsidiary Kuwait Oil Co. (KOC) for enhanced oil recovery in Burgan field.
BP said it was the first oil company to be invited by the Ku-waiti government to assist in the redevelopment of Kuwait's oil industry after the 1990 Iraqi invasion and that it has helped manage fields there since 1992. The company is one of the founders of the original KOC, which discovered Burgan in 1938.
Covey Park Gas to acquire Louisiana assets
Covey Park Gas LLC, Dallas, has agreed to acquire acreage and natural gas production in the Haynesville and Bossier shales of Louisiana from subsidiaries of EP Energy Corp., Houston, for $420 million.
Covey Park Gas is a wholly owned subsidiary of Covey Park Energy LLC.
The deal covers 52,933 gross (34,167 net) acres with produc-tion in the fourth quarter of 2015 of 113 MMcfd of natural gas.
It will boost Covey Park's leaseholdings to 137,000 net acres in Texas and Louisiana, net production to 200 MMcfd of gas, and proved reserves to 2 tcf.
Exploration & Development — Quick Takes
BOEM issues final offshore leasing rule
The US Bureau of Ocean Energy Management issued a final offshore oil and gas leasing rule that it said would reorganize and reorder regulations for clarity, eliminate redundant or otherwise unnecessary text, and add new definitions and sections to standardize or clarify practices in all three BOEM US Outer Continental Shelf regional offices.
The rule updates and streamlines existing OCS regulations and reflects the reorganization and division of the former US Minerals Management Service into three separate agencies. It will become effective 60 days after its publication in the Mar. 30 Federal Register, the US Department of the Interior agency said.
It noted that the final rule does not include substantive changes to bonding requirements, which will be the subject of a future rulemaking as BOEM develops a risk management program. The rule does codify many existing policies and practices at the agency, and corrects some errors that occurred when MMS's responsibilities were moved into the newly formed US Bureau of Safety and Environmental Enforcement, US Office of Natural Resources Revenue, and BOEM in late 2010.
"The final rule reorganizes leasing requirements to more ef-fectively communicate the leasing process, policies and procedures as they evolved over the years, clarify requirements, and add statutory and departmental requirements instituted since the last major rewrite," BOEM said.
Cyprus opens third offshore licensing round
Cyprus has opened its third offshore licensing round, offering three blocks south of the island nation under production sharing terms (OGJ Online, Feb. 19, 2016).
Blocks 6, 8, and 10 are near Block 12, a first-round license on which a group led by Noble Energy Inc. made the deepwater Aphrodite natural gas discovery. Total relinquished the Block 10 license last year and retained Block 11.
Applications must be submitted to the Ministry of Energy, Commerce, Industry, and Tourism within 120 days of the date of announcement of the round's opening, Mar. 24.
Eni awarded block near OCTP project offshore Ghana
Eni SPA has been awarded an exploration license for the Cape Three Points Block 4 in the Tano basin offshore Ghana.
Eni will serve as operator and hold 42.4691% interest in a joint venture also comprising Vitol Upstream Tano 33.9753%, Ghana National Petroleum Corp. 10%, Woodfields Up-stream Ghana 9.5556%, and GNPC Exploration & Production Co. 4%.
The block covers 1,127 sq km in 100-1,200 m of water, par-tially surrounding the Offshore Cape Three Points (OCTP) block also operated by Eni (OGJ Online, Oct. 6, 2009). The firm notes that if exploration is successful, the block will benefit from OCTP project currently under development.
The OCTP project involves the integration and synergic development of various oil and gas discoveries, namely Sankofa Main, Sankofa East, and Gye-Nyame. It envisages the develop-ment of subsea wells tied back to a floating production, storage, and offloading vessel that will be connected to shore via a gas transport line (OGJ Online, Jan. 28, 2015).
Oil production from OCTP is expected to start up in 2017 while the startup of gas production, which will supply the domestic market for power generation, is expected in 2018.
Eni, operating through subsidiary Eni Ghana, has been present in Ghana since 2009.
MOL reports another oil, gas discovery in Pakistan
MOL Group reported an 11th hydrocarbon discovery in Pakistan, which makes three discoveries made on Karak block in the country's Punjab Province.
The Halini-Deep-1 discovery well was drilled to 5,900 m. Subsequent to tests, the operator added the Samana Suk formation to the already known Lumshiwal, Hangu, and Lockhart reservoirs. The well flowed 1,425 bo/d and 1.18 MMcfd of natural gas. The Halini-Deep-1 discovery follows the Halini-X-1 and Kalbagh-1A discoveries that were also made on Karak block in 2011 and 2015, respectively (OGJ Online, Sept. 18, 2015).
The block is operated by Mari Petroleum Co. Ltd. with 60% working interest while fully owned subsidiary of MOL Group, MOL Pakistan Oil & Gas Co. BV, has 40% in the block. The operator expects the start of oil production by midyear.
Drilling & Production — Quick Takes
Deepwater spend to fall 35% through 2020
A recent report from Douglas-Westwood Ltd. forecasts deep-water expenditures to total $137 billion during 2016-20, which is a 35% decline from its previous forecast covering 2015-19.
"The prolonged low oil price has impacted the deepwater market, with operators considering alternative development options and delaying the sanctioning of new projects," said Mark Adeosum, report author at Douglas-Westwood.
At this time last year, 210 projects were slated for instal-lation within the subsequent 5 years. Douglas-Westwood now projects 118 projects for installation through 2020.
The report attributes expenditures predominantly driven by Africa and the Americas, which will account for a combined 87% of total deepwater investments.
Cowen: Subsea tree awards to drop again
As offshore oil and gas development wanes, project awards for subsea trees plummet.
Cowen & Co. predicts awards will fall to 113 subsea trees this year from 153 last year, 232 in 2014, and 551 in 2013, the top of the latest cycle. The investment firm expects the tally to rise to 175 subsea trees in 2017 but warns, "Low commodity prices may result in further project deferrals or cancellations."
Of the total projected for 2016, 56 awards will be for large projects-those involving five or more trees.
Large 2016 projects, with operator, location, and number of trees, are Vito, Shell, Gulf of Mexico, 15; Equus, Hess, Australia, 18; Coral South FLNG (Area 4), Eni, Mozambique, 6; Zohr Phase 1, Eni, Egypt, 5; and Hebron, ExxonMobil, Canada, 12.
Kuwait, Saudi Arabia to restart Khafji field
Kuwait and Saudi Arabia agreed to resume production at off-shore Khafji oil field although no restart date was immediately available, Kuwait News Agency (Kuna) reported, saying Anas al-Saleh, Kuwait's acting oil minister, told Kuwait's Parliament that maintenance was planned first at the field.
Production at Khafji was halted in October 2014 because of environmental concerns. The 300,000-b/d field lies in the Saudi-Kuwaiti neutral zone. Kuwait Gulf Oil Co. and Saudi Ar-amco Gulf Operations Co. jointly operate it. Neither company commented on restart reports.
The restart initially will involve "small quantities, which would be increased taking into consideration environmental concerns," before returning to normal levels, Kuna said.
Separately, Saudi Arabia and Kuwait are expected to attend an Apr. 17 meeting in Qatar of major oil producers, members of the Organization of Petroleum Exporting Countries, as well as non-OPEC members, to discuss a proposed production freeze at January levels.
Aramco commissions offshore Hasbah gas field
Saudi Aramco has commissioned offshore Hasbah natural gas field, part of the two-field Al Wasit gas project.
Production is to reach a combined 2.5 bscfd from Hasbah and nearby Arabiyah fields, processed at the onshore Wasit gas processing plant. The fields are in about 50 km of water, 150 km northeast of Jubail.
Tecnoconsult Engineering Construction SRL, which is assisting Saipem SPA with engineering, procurement, installation, and commissioning, said Hasbah will have seven well-head platforms connected by 12-in. flowlines to a tie-in platform.
Arabiyah, southeast of Hasbah, will have eight wellhead platforms, connected like those at Hasbah by 12-in. flowlines to a tie-in platform.
Twin 36-in. trunklines will carry production from the fields to the Wasit gas plant, which has 240,000 b/d of NGL extrac-tion capacity.
The project also includes an intermediate injection platform on the trunklines in 25 m of water and pipelines for monoeth-ylene glycol.
ONGC approves $5-billion offshore development plan
The board of India's Oil & Natural Gas Corp. Ltd. approved a $5-billion offshore oil and natural gas development plan for the Krishna-Godavari basin off the country's east coast.
ONGC plans 35 wells in Clusters 2A and 2B on deepwater block KG-DWN-98/2 (OGJ Online, Jan. 7, 2008). Twelve of the wells will be used for water injection.
First gas is expected by June 2019 and first oil by March 2020. ONGC expects a peak production rate in Cluster 2A of 77,305 b/d and 3.81 million cu m/day of associated gas through 15 producers. In Cluster 2B, peak gas production is expected to be 12.75 million cu m/day from eight wells.
The plan includes a gas processing platform with bridge-connected living quarters; a floating production, storage, and offloading vessel; about 430 km of subsea pipelines; and an onshore gas terminal.
PROCESSING — Quick Takes
CPCC reaches FID on Cedar Bayou plant expansion
Chevron Phillips Chemical Co. LP (CPCC) has reached final investment decision to expand the low-viscosity polyalphaole-fins (PAO) capacity at its Cedar Bayou petrochemical complex in Baytown, Tex.
The expansion will boost PAO capacity at the site by 10,000 tonnes/year, or about 20%, to 58,000 tpy from its current ca-pacity of 48,000 tpy, CPCC said.
Designed to enable CPCC to meet the increasing demand for high-performance lubricants in automotive and industrial applications as demand for higher energy efficiency and high-quality basestocks continues to grow, the PAO expansion also will improve process safety and overall unit efficiencies while reducing waste generation for the Cedar Bayou's PAO unit, the company said.
Additional feedstocks for planned expansion project will be supplied by CPCC's recent 100,000-tpy expansion of normal alpha olefins capacity at Cedar Bayou (OGJ Online, Dec. 11, 2014; Apr. 8, 2014).
Construction on the project will begin in April, with the expanded plant scheduled for startup by mid-2017, CPCC said.
FID on the PAO project at Cedar Bayou follows CPCC's November 2014 announcement that it had undertaken a study for the pro-posed expansion, which at the time, was targeted for completion in 2016 (OGJ Online, Nov. 7, 2014).
MEGlobal plans MEG plant at Oyster Creek complex
Dubai-based MEGlobal International FZE, a subsidiary of Ku-wait's first international petrochemical joint venture Equate Petrochemical Co., said it will build its first US monoethylene glycol (MEG) manufacturing plant at Dow Chemical Co.'s Oyster Creek petrochemical complex in Freeport, Tex.
The grassroots MEG plant, which will receive ethylene feed-stock from Dow's currently expanding Oyster Creek ethylene production site under a long-term supply agreement (OGJ Online, June 26, 2014; Oct. 29, 2012), is scheduled to be commissioned in mid-2019, MEGlobal said.
The plant comes as part of MEGlobal's program to create greater flexibility to satisfy grown demand for ethylene glycol products in the US and Asia Pacific markets, as well as strategy to expand the company's global footprint, said Mohammad Husain, Equate Petrochemical's president and chief executive officer.
Equate Petrochemical is an international JV of Kuwait's state-owned Petrochemical Industries Co., 42.5%; Dow, 42.5%; Boubyan Petrochemical Co., 9%; and Qurain Petrochemical In-dustries Co., 6%.
As part of the already completed long-term supply agreement between MEGlobal and Dow, ethylene supplies for the MEG plant will come directly from Dow's 1.5 million-tonne/year Oyster Creek ethylene cracker, on which construction continues to progress, Dow said.
To date, the cracker is more than 40% completed and remains on track for startup in second-quarter 2017, said Dow, which also said it plans to complete ethane feedstock flexibility for an ethylene cracker at its operations in Louisiana by this year's second half.
Separately, Dow confirmed it has undertaken a planned outage to repair an exchanger at its newly commissioned 750,000-tpy propane dehydrogenation unit (PDH) at the Oyster Creek site (OGJ Online, Mar. 9, 2016).
Ineos plans restart of Grangemouth ethylene unit
Ineos AG, Rolle, Switzerland, has completed operational trials for the planned restart of a previously shuttered second manufacturing unit at its gas-cracking operations in Grangemouth, Scotland.
Mothballed in 2008 amid its inability to operate at full ca-pacity, Train 2 of the Grangemouth ethylene cracker has undergone a series of rigorous recommissioning trials to prepare for the arrival of price-advantaged US shale ethane supplies due to arrive via tanker at its new Grangemouth import terminal during this year's second half, Ineos said.
The US shale-sourced ethane will be used as supplementary feed to enable the Grangemouth ethylene plant to run at in-creased rates at a time when North Sea supplies are dwindling, the company said.
Combined, Grangemouth's two crackers have a total ethylene production capacity of 1 million tonnes/year.
"With the successful completion of the Train 2 trial, we are now in great shape to receive shale gas from the US and to finally run the Grangemouth plant at full rates," said Gordon Milne, operations director for Ineos Grangemouth.
The company did not disclose a firm timeline for Train 2's official restart.
Announcement of Train 2's recommissioning follows Ineos' £450-million investment to build an import terminal and stor-age tank to store and process ethane from shale gas as part of a survival plan for its 210,000-b/d Grangemouth refinery which involves transforming the plant into a shale gas-based operation in order for it to become a profitable business again (OGJ Online, July 17, 2014).
Ineos previously entered deals to secure US shale gas sup-plies for its European cracking operations with Consol Energy Inc., Pittsburgh, Range Resources-Appalachia LLC, and Enter-prise Products Partners LP (OGJ Online, June 12, 2014).
Most recently, the company entered a deal for the long-term supply of US ethane supplies beginning in mid-2017 to ExxonMobil Chemical Ltd.'s 830,000-tpy Fife ethylene plant (FEP) at Mossmorran on Scotland's eastern coast near Braefoot Bay, about 25 miles north of Edinburgh (OGJ Online, Nov. 9, 2015).
Part of Ineos' strategy to bring US shale gas economics to Europe, the company's overall ethane supply project includes:
• Contracts to acquire gas from the Marcellus shale in west-ern Pennsylvania.
• Connection to the 300-mile Mariner East pipeline to bring gas to the Marcus Hook deepwater terminal near Philadelphia.
• Design and commissioning of eight Dragon-class ships for transatlantic gas shipments.
• Construction of an import terminal, including a 60,000-cu m ethane storage tank with liquid gas storage capacity of 33,000 tonnes, as well as docks and a pipeline network for gas reception.
TRANSPORTATION — Quick Takes
Woodside-led venture postpones Browse LNG project
The Woodside Petroleum Ltd.-led Browse LNG joint venture has decided to indefinitely defer the development following the completion of the front-end engineering and design (FEED) process (OGJ Online, Dec. 10, 2015).
The decision has come after consideration of the current economic and market environment.
Woodside noted that since starting the FEED process, it has been focused on delivering targeted cost savings and value enhancements. Significant progress had been made to improve the project's value, but it was offset by the very challenging and unfavorable external environment.
Nevertheless, Woodside CEO Peter Coleman said the company remains committed to "the earliest commercial development of the Browse resources and to floating LNG as the preferred development concept." He also did not discount the possibility of a completely different development option, such as piping gas to the Burrup Peninsula facilities currently serving the North West Shelf fields. Coleman added that the economic environment is not supportive of a major LNG investment at the moment.
The announcement comes as no surprise to industry watchers who point out that deferral of Browse is the biggest local casualty of the plunge in oil prices.
It also is a blow to the Western Australian resources sector with Premier Colin Barnett admitting that it would have been very difficult for the JV to commit "probably north of $50 billion (Aus.)" to develop Browse LNG when the price of petroleum, including gas, is low. Barnett hoped the project would get its opportunity when prices recover in a few years' time.
Coleman said the Browse delay gave Woodside headroom to pursue acquisition of assets that were beginning to come onto the depressed market. He signalled that they would take priority over returning capital to shareholders. Coleman added, however, that new petroleum supply projects like Browse would have to get moving within 2-3 years to meet the forecast demand.
The Browse project has been deferred several times, including April 2013 when the joint venture cancelled plans for a large onshore LNG plant at James Price Point in the Kimberley that would have cost in excess of $80 billion (Aus.) (OGJ Online, Apr. 12, 2013). Billions of dollars have already been spent in trying to commercialize the Browse gas fields, which were originally discovered in the 1970s.
