GENERAL INTEREST — Quick Takes
Swift Energy latest US producer to file Chapter 11
Swift Energy Co., a Houston independent focused on the Eagle Ford shale of South Texas, filed voluntary petitions on Dec. 31, 2015, for relief under Chapter 11 of the US Bankruptcy Code in US Bankruptcy Court for the District of Delaware. The action includes eight of its subsidiaries. The company says it has reached an agreement with holders of a majority of its senior notes to convert all senior notes to equity.
Swift also has arranged up to $75 million of debtor-in-possession (DIP) financing from a group of senior noteholders to provide additional liquidity to fund the business through the Chapter 11 process. The company expects to restructure, amend, or refinance its prepetition $330 million secured revolving credit facility as part of its plan of reorganization.
The agreement with the senior noteholders provides for the executive management team to retain their positions upon the completion of the Chapter 11 process.
Swift expects to continue operations during the pendency of the bankruptcy case, and anticipates making royalty payments and payments to working interest owners when due. The company adds that its employees should expect no change in their daily responsibilities and to be paid as usual.
"The company had to take action in response to the significant reduction in oil and gas prices that the entire industry has been facing." commented Terry E. Swift, president and chief executive officer, on the filing.
Way named Southwestern's president, CEO
Bill Way has been appointed president and chief executive officer of Southwestern Energy Co., Houston, succeeding Steve Mueller.
Way joined the company in October 2011 as executive vice-president and chief operating officer. As part of the company's succession plan, he was promoted to president in December 2014.
Prior to joining Southwestern, he was senior vice-president, Americas, for BG Group PLC with responsibility for exploration and production, midstream, and LNG operations in the US, Trinidad and Tobago, Chile, Bolivia, Canada, and Argentina.
ONRR issues regulation broadening revenue sharing
The US Department of Interior's Office of Natural Resources Revenue issued a final regulation that broadens revenue sharing with four US Gulf Coast states and their counties and parishes under the 2006 Gulf of Mexico Energy Security Act (GOMESA). The rule, which was to appear in the Dec. 30, 2016, Federal Register, is slated to become effective 30 days after.
Under this second phase of GOMESA, ONRR will disburse as much as $375 million/year to Alabama, Mississippi, Louisiana, and Texas and their eligible coastal political subdivisions, and as much as $125 million/year to the stateside Land and Water Conservation Fund (LWCF).
GOMESA provides for the federal government to share 37.5% of qualified oil and gas leasing revenue from certain US Outer Continental Shelf leases with the states and their coastal parishes and counties. The law also specifies that 12.5% of qualified revenue is provided to LWCF, and that the remaining 50% is sent to the US Treasury's General Fund.
Under Phase II, GOMESA expands the definition of qualified revenue to include the majority of existing leases issued in the Gulf of Mexico program area since Dec. 20, 2006, and any future federal leases issued on the Gulf of Mexico OCS. GOMESA Phase II revenue sharing will begin with the disbursement of fiscal 2017 qualified revenue in fiscal 2018, ONRR said.
Exploration & Development — Quick Takes
Valeura finds gas in Turkey's Thrace basin
Valeura Energy Inc.'s first exploration well on its wholly owned and operated Banarli license flowed at an initial restricted rate of 3.4 MMcfd on a 24-hr production test. Originally awarded in April 2014, the 118,598-acre license is near the center and deepest part of the basin (OGJ Online, Apr. 8, 2013).
Valeura, based in Calgary, announced in December 2015 that it drilled its first two exploration wells. The first well, Bati Gurgen-1, was drilled to a measured depth of 2,735 m into the top of the Teslimkoy member of the Mezardere formation and was cased to a measured depth of 2,729 m. Log analysis indicated 32 m of aggregate net gas pay at an average porosity of 19.6% in multiple stacked sands in the Danismen and Osmancik formations. The well also penetrated several overpressured, thinner, and tighter stacked sands in the Mezardere formation.
The company perforated 13 m of conventional stacked sands in the Osmancik formation below 1,480 m to carry out the production test. In addition to 3.4 MMcf of gas produced during the test's 24-hr period, the well flowed 15 bbl of condensate, and minimal water through a 36/64-in. choke and a final flowing wellhead pressure of 1,307 psi. The company expects the Danismen formation will be completed within one or two months after Bati Gurgen-1 is on production to permit further performance monitoring of the Osmancik formation alone.
The Bati Gurgen-1 well is currently shut in and awaiting completion of the pipeline tie-in to the dehydration facility at the Gurgen-1 well, of which Valeura holds 40% working interest, about 3 km to the southeast on the joint-venture lands acquired from Thrace Basin Natural Gas (Turkiye) Corp. and Pinnacle Turkey Inc.
The company's second wholly owned exploration well, Yayli-1, was drilled to a measured depth of 2,914 m into the Teslimkoy member of the Mezardere formation and was cased to 2,910 m. Log analysis indicated 14 m of aggregate net gas pay at an average porosity of 15% in several stacked sands in the Osmancik 2 formation. The well also penetrated multiple overpressured, tighter-stacked sands in a series of interpreted coalesced basin floor fans in the Teslimkoy.
The company plans to complete and test the Teslimkoy at 2,850-2,875 m, but must first retrofit the wellhead to increase its pressure rating to 10,000 psi from 5,000 psi due a similar overpressure to the Bati Gurgen-1. Completion should take place by late January, the company said.
Provisions also are being made to tie in the Yayli-1 well to a junction at the Bati Gurgen-1 well. First gas from Banarli is targeted for the end of January.
Woodside makes gas discovery offshore Myanmar
Woodside Petroleum Ltd., Perth, has made a natural gas discovery offshore Myanmar with its first well, Shwe Yee Htun-1, known previously as Saung-1. Gas indications were found over a 129-m interval and Woodside has designated 15 m of this zone as net pay.
The well, in the Rakhine basin, was first drilled to its original planned depth of 4,810 m before being deepened to 5,306 m. Further analysis will evaluate the full potential, but Woodside has said the find de-risks a number of leads in the region.
The well is on the A-6 block where it is operator for local company MPRL and Total SA, a JV that Woodside entered in December 2012. The company has interests in six large offshore permits in Myanmar covering a total of 46,000 sq km.
The next well will be Tha Lim-1 on Block AD-7, operated by South Korea's Daewoo International.
Myanmar has been opened up for exploration following the political reforms of 2011 and subsequent lifting of European Union and US sanctions, enabling companies to reenter the region.
Drilling programs began in 2014. The country is estimated to contain 3.2 billion bbl of oil and 18 tcf of gas with potential for vastly greater amounts, thus attracting most of the world's major players.
Cairn tests oil offshore Senegal
Spudded in November 2015, Cairn's SNE-2 appraisal well was successfully tested in two intervals offshore Senegal on the Sangomar Block (OGJ Online, Dec. 10, 2015).
Drillstem tests over a 12-m interval flowed 8,000 bo/d through a 24/64-in. choke, the company said. A second 15-m interval flowed 1,000 bo/d through the same size choke; however, the company said this oil was low quality "heterolithic" pay.
Following this first successful appraisal well, Cairn expects to revise its resource estimates for SNE field, which lies 100 km offshore Senegal.
The tests confirm correlation of the principle reservoir units between SNE-1 and SNE-2 with the primary reservoirs occurring in the gas cap as predicted, the company said.
The company recovered 216 m of continuous core across the entire reservoir interval. Similar oil-down-to and oil-up-to depths were verified in SNE-2 (103 m gross) with those in SNE-1 (95 m gross).
The SNE-2 well was drilled in 1,200 m of water to a total depth of 2,800 m. It lies some 3 km to the south of Cairn's previous SNE-1 discovery well (OGJ Online, Nov. 19, 2014). The company is now planning its second appraisal well, SNE-3.
Project partners are Cairn 40%, ConocoPhillips 35%, FAR 15%, and Senegal state oil concern Petrosen 10%.
Drilling & Production — Quick Takes
UK North Sea production rose in 2015 despite oil prices
Government statistics indicate UK North Sea oil and natural gas production rose for the first time in more than 15 years despite slumping oil prices, said Oil & Gas UK, whose members include oil and gas producers and contractors.
Deirdre Michie, OGUK chief executive, warned that industry will be hard pressed to sustain that rate of increasing production in 2016 and beyond. Brent crude oil prices dropped to about $36/bbl during late 2015.
"Government data for the first 10 months of 2015 shows that the total volume of oil and gas produced on the UK Continental Shelf was up 8.6% compared with 2014, with the production of liquids up 10.6% and gas up 6.1%," Michie said, citing figures from the UK Department of Energy and Climate Change.
"Output in November and December tends historically to be more stable, but even so, [OGUK] now expects yearend production for the full year of 2015 to be 7-8% higher than last year," Michie said Jan. 4.
During February 2015, OGUK forecast a marginal production increase for 2015. The unexpectedly high production growth was attributed to producers becoming more efficient and having invested more than $50 billion during the last 4 years, which resulted in new fields coming on stream.
"The upturn underlines the industry's commitment to the UKCS—which still holds great promise for the future and is vital for the country's security of supply," he said. "Times are really tough for this industry and for the people working in it. We will continue to see job losses as we move into 2016."
Gas production starts from Corrib field off Ireland
Royal Dutch Shell PLC reported that natural gas production has started from Corrib field in 350 m of water 83 km offshore northwestern Ireland. At peak production, Corrib is expected to reach 260 MMscfd of gas, or 45,000 boe/d. At peak levels, the potential exists to meet as much as 60% of Ireland's gas needs.
Six production wells are available in Corrib field, which has been developed as a subsea-to-shore tieback solution with a 20-in. pipeline leading from the subsea wellheads to landfall near the village of Glengad, and onwards through an onshore pipeline to the Bellanaboy Bridge Gas Terminal in northwest Mayo about 9 km inland. The gas is then transferred into Gas Networks Ireland's network for distribution to Irish markets.
The Corrib project is a joint venture of operator Shell E&P Ireland Ltd. 45%, Statoil Exploration Ireland Ltd. 36.5%, and Vermilion Energy Ireland Ltd. 18.5%.
Production from Delta House FPS hits 80,000 b/d
LLOG Exploration Co. LLC, Covington, La., and joint venture partner, Blackstone Energy Partners, announced the Delta House floating production system on Mississippi Canyon Block 254 achieved production of 80,000 b/d.
LLOG recently brought the ninth well on production several weeks ahead of schedule and two additional wells were expected to be brought on production to the FPS in 2016.
The FPS is designed for peaking capacity of 100,000 b/d and 240 MMcfd of gas with no redundancy of key rotating equipment. Delta House FPS was built, installed, and put on stream in 3 years. Production started in April 2015.
"The startup and ramp up of the Delta House FPS has gone exceptionally well," said Scott Gutterman, LLOG Exploration president and chief executive officer. "The FPS uptime has averaged in excess of 99% since production was initiated, which we believe is best in class for similarly sized facilities."
Co-owners are: American Midstream Partners LP, Ridgewood Energy, Red Willow offshore LLC, Calypso Exploration LLC, Deep Gulf Energy II LLC, and Houston Energy.
PROCESSING — Quick Takes
Axiall, Lotte finalize investment for petchem plants
Axiall Corp., Atlanta, and South Korea's Lotte Chemical Corp., Seoul, have reached a final investment decision (FID) to proceed with plans to build a 1 million tonne/year ethane-based cracker and associated monoethylene glycol (MEG) plant in Lake Charles, La. (OGJ Online, June 18, 2015; Feb. 11, 2014; Dec. 20, 2013).
LACC LLC, a subsidiary of Axiall and Lotte Chemical USA Corp.'s 50–50 joint venture Eagle US 2 LLC, will invest $1.9 billion to build the steam cracker adjacent to Axiall's Lake Charles chlor-alkali manufacturing plants to take advantage of existing infrastructure, competitive US shale feedstock resources, and ethylene distribution infrastructure, according to a series of releases from the JV and Louisiana Economic Development (LED).
Adjacent to the new steam cracker, Lotte separately will invest an additional $1.1 billion to build and operate the US' largest MEG plant, from which 600,000 tpy of MEG will be exported to customers in Europe and Asia, according to Soo Young Huh, Lotte Chemical's president and chief executive.
To secure the combined projects, the state of Louisiana offered the companies a competitive incentive package that includes a $4.55-million modernization tax credit for the ethane cracker, as well as economic development award program incentives of $700,000 for the cracker and $1.47 million for the MEG plant, which will pay for site infrastructure improvements, LED said.
With site preparation already under way and full construction due to begin during second-quarter 2016, the grassroots cracker and MEG plant are scheduled for startup in early 2019.
LACC also confirmed it has let an additional contract to CB&I, Houston, to provide engineering, procurement, fabrication, and construction (EPC) for the ethane cracker, which will use the service company's proprietary highly selective SRT cracking heaters as well as its recovery section design.
CB&I's scope of work under the $1.3 billion EPC contract also includes supply of spheres and fabricated pipe spools.
HollyFrontier wraps yearend planned refinery work
US refiner HollyFrontier Corp., Dallas, has concluded planned maintenance activities scheduled during fourth-quarter 2015 for its refineries in El Dorado, Kan.; Cheyenne, Wyo.; and Tulsa.
As of Dec. 28, 2015, all yearend maintenance projects under way at the three refineries were completed, the company said.
At its 133,000 b/d (135,000-b/sd) El Dorado and 49,400-b/d (52,000-b/sd) Cheyenne refineries, the scope of planned maintenance included work on distillate hydrotreating units, while maintenance at the 85,500-b/d (90,000-b/sd) Tulsa West branch of the combined 157,225-b/d (165,500-b/sd) Tulsa refinery involved scheduled work at crude distillation and lubricants units, HollyFrontier said.
The company said it also completed repairs to the Tulsa refinery's fluid catalytic cracking unit (FCCU) during fourth-quarter 2015 after an unplanned shutdown of the unit that occurred earlier in the quarter.
While HollyFrontier disclosed no further details regarding the FCCU's unexpected outage, the company did confirm its restart of the unit following the unidentified repair work.
The firm also apprised investors of reduced crude throughputs during fourth-quarter 2015 at its 109,250-b/d (115,000-b/sd) Artesia, NM, refinery as a result of crude availability constraints caused by extreme regional weather conditions.
The planned and unplanned maintenance events at the El Dorado, Cheyenne, and Tulsa refineries, alongside the inclement weather issues impacting the Artesia operations, are expected to nominally reduce the refiner's average overall crude throughputs for fourth-quarter 2015 to 395,000-405,000 b/d, HollyFrontier said.
The company previously anticipated total crude throughputs for the fourth quarter to average 410,000-415,000 b/d, according to its latest guidance to investors issued on Dec. 1, 2015.
Overall crude throughputs during third-quarter 2015 averaged about 460,000 b/d vs. the company's original guidance range for the quarter of 440,000-445,000 b/d, George J. Damiris, HollyFrontier's newly appointed chief executive officer and president (OGJ Online, Dec. 7, 2015), told investors in a Nov. 5, 2015, earnings call.
China, Taiwan JV break ground on ethylene complex
Fujian Petrochemical Co. Ltd. (FPCL) and a consortium of Taiwanese companies have started construction of an integrated petrochemical complex at Zhangzhou Gulei Petrochemical Base (ZGPB), in Zhangzhou, Fujian Province, southeastern China.
A groundbreaking ceremony for the grassroots petrochemical complex took place on Dec. 14, according to a release from state-owned China Petroleum & Chemical Corp. (Sinopec), which holds 50% interest in FPCL.
Referred to as the Zhangzhou Gulei refinery integration project, the jointly owned Chinese-Taiwanese complex will include a 1 million-tonne/year ethylene complex, 16 planned chemical plants, as well as related terminals and electrical utilities.
Designed to demonstrate the mutual advantages available to the two countries as a result of increased industrial cooperation across the Taiwan Strait, the project is scheduled for startup in 2018, Sinopec said.
Earlier in the year, China's National Development & Reform Commission (NDRC) approved overall development of ZGPB, which alongside total planned production capacities of more than 1.2 million tpy for ethylene and 1 million tpy for aromatics, also will include more than 15 million tpy of crude oil refining capacity, according to an Apr. 22 release from NDRC.
In addition to integrated refining and petrochemical operations, ZGPB will host installations for the storage and transport of raw and finished products, including a warehouse, tank farm, port, and terminals, NDRC said.
A local branch of NDRC also recently approved Sinochem Quanzhou Petrochemical Co. Ltd., a wholly owned subsidiary of Sinochem Group, to expand its still relatively new 12 million-tpy refining complex (OGJ Online, July 10, 2014) at nearby Quanzhou, in southern Fujian Province, the Fujian Provincial Development and Reform Commission (FPDRC) said in a Dec. 4 release.
Due to be commissioned in 2018, the multibillion-dollar expansion will lift crude processing capacity at Quanzhou to 15 million tpy and includes construction of a grassroots 1 million-tpy ethylene plant, as well as additional specialty chemical units and associated utilities, according to FPDRC.
TRANSPORTATION — Quick Takes
CNPC signs pipeline agreements with Russia, Kyrgyzstan
China National Petroleum Corp. and JSC Gazprom signed an agreement Dec. 17 in Beijing for design and construction of the cross-border section of the Russia-China gas pipeline.
Gazprom said "special attention" will be paid to the crossing under the Amur River. The Russian section is known as the Power of Siberia gas pipeline and the Chinese section is known as the Eastern Route.
CNPC said the entire pipeline project is expected to be completed and operational by the end of 2018. Construction of the Chinese section began in June 2015, while construction of the Russian section began in September 2014 (OGJ Online, June 30, 2015; Oct. 14, 2014).
CNPC also signed an investment agreement on Dec. 16 for construction of the 215-km Kyrgyzstan section of Line D of the Central Asia-China gas pipeline (OGJ Online, Mar. 11, 2014).
The company said technical standards and specifications will be determined for design and construction, "and the Kyrgyz Government will provide support to ensure the smooth progress of the project."
Australian funds buying Maui gas pipeline
A group led by Shell has agreed to sell the Maui Pipeline, a natural gas transmission system in New Zealand, to two infrastructure funds managed by First State Investments of Australia.
The 307-km transmission line carries gas from a production station south of New Plymouth to the Huntly Power Station south of Auckland in North Island. It receives gas from 12 shippers at six production stations. Slightly more than half the gas, which in 2013 totaled 135 PJ, goes to the power station and two methanol plants owned by Methanex.
The buyers, Global Diversified Infrastructure Fund and Colonial First State Active Infrastructure Income Fund, agreed to pay $335 million (NZ) for the pipeline. The seller is Maui Mining Cos., owned 83.75% by Shell, 10% by OMV NZ, and 6.25% by Todd Energy.
First State Investments, known in Australia as Colonial First State Global Asset Management, recently agreed to purchase 100% of Vector Gas Ltd., which owns the Vector gas transmission network and distribution assets in New Zealand, from Vector Ltd. The Maui pipeline and Vector transmission system have 13 interconnection points.
Shell said the sale did not relate to its announcement last month that its interests in New Zealand are under review. "The future of the Maui pipeline has been under consideration for a long time" by the ownership group, it said. The New Zealand interests under review are profitable but represent a small part of Shell's global business, the company said.