GENERAL INTEREST — Quick Takes
Senators lead call for crude exports to Mexico
US Sens. Lisa Murkowski (R-Alas.) and Heidi Heitkamp (D-ND) led a coalition asking US Sec. of Commerce Penny Pritzker in a Feb. 18 letter to encourage the administration to authorize crude oil exports to Mexico under the same conditions established for those to Canada.
They cited recent news reports that Mexico's Petroleos Mexicanos (Pemex) applied to swap Mexican heavy oil for light US crude. "We encourage [DOC] to approve any such applications it may receive from adjacent foreign states, such as Mexico."
Nineteen Senate Republicans also signed the letter. It noted that the 1975 Energy Policy and Conservation Act and other relevant statutes clearly authorize swaps and exchanges. "These potential transactions are in the national interest and, if applied for, should be authorized without delay," it said.
In a separate statement, Murkowski, who chairs the Energy and Natural Resources Committee, said US President Ronald Reagan authorized US crude exports to Canada 30 years ago, which contributed to lower consumer prices and greater domestic energy production. "Mexico deserves the same treatment," she said.
"Just as we have strong partnerships with our neighbors to the north in terms of petroleum and natural gas production, we need to be making concerted efforts to reduce barriers that hinder the growth of our existing relationship with Mexico," added Heitkamp, who is ranking minority member of the Banking, Housing, and Urban Affairs Committee's National Security and International Trade and Finance Subcommittee. "This way, we can keep working to develop resources in the Gulf of Mexico and make sure the exchange of energy data isn't upended by undue red-tape," she said.
BLM seeking comments on Pinedale Anticline report
The US Bureau of Land Management's Pinedale Anticline Project Office (PAPO) is seeking public comments on a 2014 acoustic noise report on sound levels at 19 Greater Sage Grouse leks-places where males gather to attract females during mating season-in western Wyoming's Pinedale Anticline natural gas field.
The bird, which the US Fish and Wildlife Service is considering for designation as a threatened species, uses elaborate visual and audio display behavior to attract a mate, and depends on audio communication during females and chicks during brood rearing, the Dec. 31, 2014, report said.
Anthropogenic noise from human activity, including oil and gas development and production, represents a potential threat, it indicated. The study's objective was to monitor noise levels at 19 Greater Sage Grouse lakes in the Pinedale Anticline Project Area south of the city of Pinedale.
Comments on the report will be accepted until Mar. 3 at PAPO in BLM's Pinedale field office. It will not respond directly, but will consider comments it receives for the final report, PAPO said on Feb. 17.
Magnum Hunter slashes budget by 75%
Magnum Hunter Resources Corp., Houston, plans a $100 million upstream capital expenditure budget for 2015, down from the $400 million the company planned for 2014.
Allocation of $70 million was approved for its Utica and Marcellus shale exploration and development drilling program in Ohio and West Virginia, $10 million for its properties in the Williston basin in North Dakota, and $20 million for leasehold acreage acquisitions in the Utica and Marcellus.
Magnum Hunter plans to further delineate its acreage positions in Monroe, Noble, and Washington counties in Ohio, and in Tyler and Ritchie counties in West Virginia. During the year, the company plans to bring on production three net horizontal wells in the Marcellus and eight net horizontal wells in the Utica.
A number of these wells have already been drilled and are in various stages of completion, meaning capital for these projects was previously expended in fiscal year 2014.
"This budget is 'flexible' in that we are limiting capital spending at this time to allow upstream service costs to catch up with the drop in benchmark commodity prices that has occurred over the past several months," commented Gary C. Evans, Magnum Hunter chairman and chief executive officer.
"Therefore, we expect that most of this capital will be spent during the second half of the year," he said. "We are in a very unique position of anticipating 100% production growth year-over-year with minimal capital expenditures."
Production volumes of 29,000-33,000 boe/d are expected for the year.
"Additionally, the focus on minimizing capital spending may change throughout the year as our Ohio shale play joint venture discussions with interested parties progress and we determine how this anticipated new capital will be spent on our Ohio leasehold acreage position and associated development activities," Evans explained.
Exploration & Development — Quick Takes
Victoria extends drilling, fracing ban
The new Victorian Labor government of premier Daniel Andrews has extended the coal seam gas exploration and hydraulic fracturing ban in the state and launched another parliamentary inquiry. The previous Liberal government imposed a moratorium on approvals for new CSG exploration licenses and fracing approvals for all existing mineral and petroleum licences in August 2012. This was subsequently extended till July 2015.
The new moratorium will ban drilling and fracing until at least 2016. A previous inquiry recommended that the moratorium be lifted, but new Victorian Energy Minister Lily D'Ambrosio now says that report merely reflected how poorly the previous government dealt with the issue of CSG.
D'Ambrosio maintains that the inquiry dealt with the issue in a way that locked out the community and did not interrogate the science. She added that the new inquiry is about getting confidence back into the way government operates. She said she "wants to get to the bottom of people's anxieties and make sure the path forward on CSG is clear and guided by science."
The renewed bans have drawn scathing criticism from the industry, led by the Australian Petroleum Production and Exploration Association, which says the new government is not serious about welcoming investment.
APPEA says that conventional gas resources are declining and Victoria's unconventional gas resources need to be defined and developed.
APPEA says that restrictions, bans, delays, and inquiries do not represent the "immediate action" called for by the 2013 Victorian Gas Market Taskforce to facilitate new supplies for the largest natural gas consuming state in Australia.
"The decision raises serious questions about whether Victoria is a state that truly welcomes investment in developing onshore gas supplies, regional economic growth, job creation, and additional farming income that comes with it," said Paul Fennelly, APPEA chief operating officer, eastern Australia.
BG drills dry holes near Knarr field in North Sea
BG Group has concluded drilling of wildcat wells 34/3-4 S and 34/3-4 A in PL 373 S, both of which the company now classifies as dry following data sampling and acquisition. The wells lie 5 km east of Knarr field in the northern North Sea.
The purpose of well 34/3-4 S was to investigate a large channel system in reservoir rocks in the Pleistocene, BG said. The well encountered a 250-m thick channel system, about 50 m of which was of very good reservoir quality, it said. Traces of gas were encountered in two thin sandstone layers.
Drilled to a measured depth of 1,607 m and vertical depth of 1,584 m, 34/3-4 S was terminated in the Hordaland group in the Miocene.
The purpose of well 34/3-4 A was to prove petroleum in lower Jurassic reservoir rocks-the Cook formation. The well encountered 110 m of the Cook formation, 53 m of which was sandstone with good reservoir quality and traces of gas.
Drilled to a measured depth 4,535 m and vertical depth 4,321 m below the sea surface, 34/3-4 A was terminated in Amundsen formation in the Lower Jurassic. The wells lie in 406 m of water.
The exploration wells, drilled by the Transocean Searcher drilling facility, are the fifth and sixth in BG-operated PL 373 S (OGJ Online, Aug. 12, 2008). The rig will now move to drill wildcat well 34/3-5 S in the same license.
Inpex gets exploration bid for Beetaloo basin
Australia's Northern Territory government has selected Inpex Corp. for onshore oil and gas exploration in the Beetaloo basin, southeast of Darwin.
Inpex's bid for exploration permit 14-1 covers more than 4,000 sq km containing 50 blocks.
The grant is dependent on successful completion of the next phase of the application process, which includes advertising for objections, registration and completion of all legislative requirements, and negotiations to reach agreement with native title holders. Inpex said the process could take up to 2 years.
"This is a successful first step in which Inpex was assessed on work programs, expertise, and financial capacity," said Tony Pytte, Inpex director of Australia ventures. "While Inpex's primary focus remains the delivery of the flagship Ichthys LNG Project, this announcement opens the door to possible greater Inpex investment in the Northern Territory," Pytte said (OGJ Online, July 8, 2014).
The company tendered for the right to pursue exploration following the government's release of acreage in June and July 2014. The acreage became available as a direct result of the government's "use-it or lose-it" policy, which is aimed at stimulating exploration, said Adam Giles, chief minister of the Northern Territory.
Giles said it is the first petroleum exploration acreage release in the territory under the government's new competitive tender process.
Drilling & Production — Quick Takes
Another cut seen in Groningen gas output
Production from giant Groningen natural gas field in the Netherlands might be further curtailed in response to public concern about earthquakes (OGJ, Aug. 4, 2014, p. 32).
On Feb. 18, Dutch Economy Minister Henk Kamp said he'll set a new cap on Groningen output on July 1 and will act sooner "if we see good reasons," Reuters reported.
The Dutch Ministry of Economic Affairs said in January 2014 it would lower Groningen output because of seismic activity. In December it targeted a cut to 39.4 billion cu m this year from 42.5 billion cu m in 2014.
The move followed a recommendation by the State Supervision of Mines, based on data about seismic activity, that gas production be trimmed by 3.1 billion cu m this year in the southern part of the field. Kamp didn't specify how much further output might be trimmed.
Nederlandse Aardolie Maatschappij BV (NAM), the 50-50 joint venture of Royal Dutch Shell PLC and ExxonMobil Corp. that handles production from Groningen, estimates that, as of yearend 2012, the field had produced 2.02 trillion cu m of gas since its discovery in 1959 and still held 780 billion cu m recoverable.
Groningen anchors the Dutch position as Europe's second-largest producer and exporter of natural gas, behind Norway.
US rig count continues 11-week dive, loses 98 units
The US drilling rig count plunged 98 units to settle at 1,358 rigs working during the week ended Feb. 13, Baker Hughes Inc. reported.
That total is the lowest since Feb. 26, 2010, and 406 fewer units compared with this week a year ago. The count has now fallen 11 consecutive weeks, losing 562 units during that time, of which 519 were targeting oil (OGJ Online, Dec. 5, 2014).
During the week, land rigs plunged 99 units to 1,298, while rigs drilling in inland water edged down a unit to 8. Offshore rigs, meanwhile, increased 2 units to 52.
Oil rigs lost 84 units to 1,056. Gas rigs lost 14 units to 300. Rigs considered unclassified was unchanged at 2 units.
Horizontal drilling rigs fell 63 units to 1,025. Since Nov. 21, 2014, 347 units have gone offline. Directional drilling rigs fell 12 units to 123.
In the major oil- and gas-producing states, Texas, home to 44% of the country's rigs, yet again reported a precipitous decline. The Lone Star State gave up 56 units to settle at 598-its lowest total since Mar. 26, 2010. Since Nov. 21, Texas has lost 307 units.
Bakken, Three Forks production hits 1.2 million b/d
Preliminary oil and gas production figures for December 2014 show 1.16 million b/d in oil production from the Bakken and Three Forks formations and 63,992 b/d from legacy conventional pools, the North Dakota Department of Mineral Resources reported.
The December total of 1.2 million b/d compared with 1.19 million b/d total for November.
Lynn Helms, director of the Department of Mineral Resources, said drilling activity appeared to be focused on the core counties of Dunn, McKenzie, Mountrail, and Williams.
Operators have postponed some completions to avoid high initial production costs given low commodity prices and to achieve North Dakota's gas capture goals, Helms said. As of Dec. 31, an estimated 750 wells awaited completion services.
The rig count in the Williston basin has fallen rapidly, Helms said in a monthly Director's Cut note. Utilization rates for rigs capable of drilling deeper than 20,000 ft was about 70% in December and less than 50% for shallow-well rigs capable of drilling 7,000 ft or less.
PROCESSING — Quick Takes
Mangalore refinery reports steady operations
Operations are proceeding smoothly at Mangalore Refinery & Petrochemicals Ltd.'s (MRPL) refinery in Mangalore, India, following the recent completion of a modernization project designed to increase the capacity and flexibility of crude oil processing at the plant (OGJ Online, June 8, 2010).
With the third phase of the refinery's expansion and upgrade project now completed, units are running consistently on a sustained basis, while crude throughputs, distillate yields, and energy consumption continues to stabilize, said H. Kumar, the refinery's managing director.
Additionally, with all secondary units now fully operational, the refinery is in the process of maximizing crude throughputs to attain higher margins, Kumar said in a Feb. 13 filing to India's BSE Ltd. (formerly Bombay Stock Exchange).
MRPL, a subsidiary of Oil & Natural Gas Corp. Ltd., wrapped the long-delayed Phase 3 expansion and upgrading project in late 2014 after it completed start-up of the third train of a three-train sulfur recovery unit, a raw water treatment system, LPG mounded bullet storage tanks, and other related offsite facilities (OGJ Online, Nov. 13, 2014).
The Phase 3 expansion, which boosted the refinery's crude processing capacity to 15 million tonnes/year, also included the following units:
• A 2.2 million-tpy fluidized catalytic cracking (FCC) unit (OGJ Online, Aug. 27, 2014).
• A 650,000-tpy coker heavy gas oil hydrotreating unit (OGJ Online, May 15, 2014).
• A 3 million-tpy delayed coking unit (OGJ Online, Apr. 4, 2014).
Separately, an integrated 440,000-tpy polypropylene unit, which will use the Mangalore refinery's FCC production of LPG, light distillates, and propylene as feedstock, is scheduled to be commissioned by the end of February, MRPL said in its Feb. 13 filing.
A firm timeframe for when crude throughputs at Mangalore might reach the refinery's fully expanded processing capacity was not disclosed.
India, Kuwaiti firm sign deal for petchem complex
The government of India's Andhra Pradesh state has entered an agreement with Al Qebla Al Watya Inc., a subsidiary of Mohammed Abdulmohsin Al-Kharafi & Sons Co., Safat, to set up a large-scale refinery and petrochemical complex along the country's eastern coast.
The parties signed a memorandum of understanding for the proposed development on Feb. 13, Chief Minister of Andhra Pradesh Sri Nara Chandrababu Naidu said in a series of posts to his Twitter account.
The MOU envisages development of both a refinery and petrochemical complex on the state's central coast for the purpose of ensuring energy security, as well as for developing other downstream and ancillary industries, according to a separate release from the government of Andhra Pradesh.
As part of the agreement, the state government said it will extend all necessary support to help expedite the project's development.
Details regarding either a firm timeline for the project or the potential units and capacities of the planned processing complex were not disclosed.
This latest MOU follows a previous agreement signed between the eastern coastal state's government and Al Qebla Al Watya, which entered an MOU in 2011 to develop a 400,000-b/d refinery in Andhra Pradesh to be built in two phases in Andhra Pradesh's proposed Petroleum, Chemicals, and Petrochemicals Investment Region in the Visag-Kakinada zone, according to a Dec. 15, 2011, release from the state government.
The first phase of the 2011 project was to have a crude processing capacity of 100,000 b/d and require an investment of about $2 billion, the state government said at the time.
TRANSPORTATION — Quick Takes
Alaska LNG project partners file resource reports
A series of draft environmental and socioeconomic reports for the Alaska LNG project have been submitted to the US Federal Energy Regulatory Commission, which is responsible for conducting the environmental review of the project.
These reports also launch the prefile public engagement process and provide preliminary baseline data about the project area and its potential impacts.
"These draft documents, known as resource reports, allow Alaska stakeholders to engage early in the regulatory process, so potential environmental and socioeconomic issues and opportunities can be proactively identified and managed," said Steve Butt, project executive for the Alaska LNG project.
The Alaska LNG project is currently in the preliminary front-end engineering and design phase, which is expected to extend into 2016 with a gross spend of more than $500 million.
The Alaska LNG project participants are Alaska Gasline Development Corporation (AGDC) and affiliates of ExxonMobil Corp., BP PLC, ConocoPhillips, and TransCanada Corp. The US Department of Energy issued a Free-Trade Agreement export authorization to the project in November 2014.
"As the Alaska LNG project design and scope become more defined, specific project impacts and their proposed mitigation measures will be included in second drafts of the resource reports, which are expected to be submitted to FERC in the next 12 to 18 months," the partners said.
Bear Head LNG exempted from 2012 Canadian act
Liquefied Natural Gas Ltd.'s wholly owned subsidiary Bear Head LNG Corp. received notice from the Canadian Environment Assessment Agency (CEAA) that its proposed LNG liquefaction plant and export terminal in Nova Scotia would not need to adhere to the Canadian Environmental Assessment Act of 2012 (CEAA 2012).
Project design will be substantially the same as that which was previously proposed, submitted, and approved by CEAA for the site and since some construction for LNG had already taken place on the site, CEAA deemed that CEAA 2012 does not apply to the project's LNG component. Previous construction was for an Anadarko Petroleum Corp.-led import terminal (OGJ Online, Aug. 24, 2005).
The proposed installed natural gas-fired electric power generation also is not considered to trigger CEAA 2012 since the project will not use gas to generate electricity, Bear Head said.
Bear Head described CEAA's decisions as a major step forward in obtaining all regulatory approvals by the middle of this year. Bear Head last year applied for a National Energy Board export license (OGJ Online, Nov. 7, 2014).
APLNG receives first gas at Curtis Island
The Origin Energy Ltd.-led Australia Pacific LNG (APLNG) has reached a major milestone with first gas arriving at the group's LNG plant on Curtis Island near Gladstone on the central east coast of Queensland.
The arrival of gas into the LNG facility marks the completion of commissioning of the 530-km high-pressure gas pipeline from the group's coal seam gas (CSG) fields in the Surat basin to Curtis Island.
The announcement follows BG Group's first loading and departure of LNG from its plant on Jan. 5. The BG plant, also on Curtis Island, is supplied by CSG from Surat and Bowen basin fields.
For Origin and its major partner ConocoPhillips, completion of the pipeline and arrival of gas means the APLNG group can begin commissioning of the electric power generation facilities at its LNG plant.
Commissioning of the LNG plant also includes verification and testing of each system of processing Train 1 and the two LNG storage tanks.
APLNG's upstream component is about 90% complete with 1,019 development wells drilled, 666 of these commissioned. The downstream component is about 87% complete.
The final Train 2 module has now been set on its foundations.
APLNG is on track to start LNG deliveries by midyear.
