GENERAL INTEREST — Quick Takes
UK government trims tax rate on oil, gas
The UK government has responded to calls for tax relief from the oil and gas industry by trimming the "supplemental charge" applicable to most production (OGJ Online, July 14, 2014).
In a major fiscal speech to Parliament, Chancellor George Osborne announced the supplemental charge rate would be cut to 30% from 32%. Producers pay the charge in addition to a 30% corporate tax on production begun since 1993. Field allowances reduce the supplemental charge on production from small and technically challenging fields.
Osborne said the government also would extend the "ring fenced expenditure supplement" to 10 years from 6 years for offshore fields. The supplement enhances the value of losses carried forward from one accounting period to the next for fields with revenue not covering expenditures. The "ring fence" isolates expenditures to specific fields so losses from one field can't lower tax liability of another.
The chancellor also announced a "cluster area allowance," which the trade group Oil & Gas UK said would encourage development of high-pressure, high-temperature fields.
Noting that investment in the UK North Sea set a record this year, Osborne said, "The lower oil price clearly presents a challenge to this vital industry."
The industry has warned that high investment levels reflect major projects now nearly complete and masks problems of falling production, limited exploration, and shrinking discovery size in a mature producing region.
Oil & Gas UK called the tax cut "an important first step."
Malcolm Webb, the group's chief executive, said, "We will certainly need further reductions in the overall rate of tax to ensure the long-term future of the industry."
Outgoing Md. governor moving ahead on fracing regs
Maryland Gov. Martin O'Malley plans to propose regulations that would allow hydraulic fracturing in western Maryland provided that natural gas companies adhere to certain restrictions to limit the risks of water contamination and air pollution.
O'Malley said the proposals will stem from more than 3 years of study by state agencies into whether Maryland should allow drilling in the Marcellus shale. On Nov. 25, the Maryland Department of the Environment and the Department of Natural Resources released a draft report recommending that drilling be allowed in Garrett and Allegany counties.
The amount of gas in western Maryland is believed to be small compared to Pennsylvania and West Virginia, where fracing is allowed. The Marcellus and the deeper Utica shale formations have not been explored in Maryland, the draft report said.
Meanwhile, Gov.-elect Larry Hogan is scheduled to take office Jan. 21, and any fracturing regulations would be implemented during his administration.
"We're committed to ensuring that Marylanders have access to the economic opportunities associated with [hydraulic fracturing] while also putting the most complete practices into place to ensure the highest level of protection for Maryland residents," O'Malley said.
WA to increase share of Browse basin gas fields
Western Australia's Parliament has approved legislation to increase the government's share of the Browse basin natural gas fields following reclassification of state offshore boundaries. The Petroleum Titles (Browse basin) Bill 2014 that ratifies the boundary changes was passed on Nov. 25.
The move has followed Geoscience Australia's (GA) classification of a number of outcrops on the North and South Scott reefs and on the Seringapatam reef 23 km further north, as islands. This makes them Western Australian territory and will mean significant changes to federal offshore coastal waters boundaries.
GA found in its recent survey that the newly discovered outcrops were above the high water mark on the Scott Reef group, which is a series of atoll-like reefs on the edge of the continental shelf in the Timor Sea.
The changes will mean that, should the gas fields in the region be developed, Western Australia will be able to claim an estimated 50-65% share of royalties, while the federal government's share drops to an estimated 35-50%. The original proportion within the old state water boundaries was 5-15%.
The fields within the new boundaries include the Woodside Petroleum Ltd.-operated Torosa gas-condensate field and the ConocoPhillips-operated Poseidon and Kronos gas-condensate fields.
Western Australia Mines and Petroleum Minister Bill Marmion said the Torosa field rezoning could result in an increase in the state's royalty collection by as much as $2.9 billion (Aus.). He added that it was too early, however, to speculate on the royalty potential of Poseidon and Kronos fields, but that it, too, could be significant.
Exploration & Development — Quick Takes
Petrobras makes gas find in Colombian Caribbean
Petroleo Brasileiro SA (Petrobras) has discovered a natural gas accumulation with the Orca-1 exploratory well drilled on the Tayrona block in the deepwater Caribbean Sea, 40 km offshore La Guajira, Colombia.
The gas accumulation was confirmed at 3,600 m, marking the first discovery in the history of exploratory research in the Colombian Caribbean deep waters, Petrobras says. Drilling concluded in September, reaching a total depth of 4,240 m in 674 m of water.
The company says it will continue with scheduled operations to evaluate the discovery.
The first agreement granted by Colombia's National Hydrocarbons Agency (ANH) for deepwater exploration in the Colombian Caribbean occurred in 2004, when Petrobras partnered with Colombia's state-owned Ecopetrol SA for Tayrona (OGJ Online, Aug. 6, 2004).
Ecopetrol is a participating partner in 13 offshore blocks in the Colombian Caribbean. A drilling campaign is planned for this basin that will include two wells in 2015 and two or three additional wells in 2016.
Petrobras is operator of the block with 40% interest. Ecopetrol and Spain's Repsol SA each hold 30% (OGJ Online, Jan. 5, 2011).
InterOil confirms Raptor discovery in Papua New Guinea
InterOil Corp. has confirmed the presence of a "multihundred-meter hydrocarbon column" in excess of the 200-m gross gas interval previously encountered by the Raptor-1 well, 12 km west of Antelope field in Papua New Guinea.
Logs indicate a highly fractured reservoir system and mud loss during drilling supports the likely connectivity of the fracture network. Raptor encountered pay at 3,800 m, marking the deepest well drilled into the Kapau limestone reservoir, InterOil said.
InterOil in November notified the Papua New Guinea Department of Petroleum and Energy of the Raptor-1 discovery in PPL 475.
Raptor-1 is being suspended to allow planning for future appraisal work, slated to occur next year, including additional seismic, appraisal drilling, and a comprehensive testing program. The rig is being mobilized to spud Antelope-5.
The company says it continues to review and survey all options at its Wahoo-1 well in PPL 474, including well designs, mud weights, and mud types. The company suspended the well in July following significant safety concerns over high pressures (OGJ Online July 14, 2014). Drilling is expected to resume next year.
InterOil operates and holds 78.1114% interest in the well. Minority interests hold the remaining 21.8886%.
The company says it's now firmly into its appraisal program at Elk-Antelope and Triceratops. Antelope-4 appraisal drilling continues and Antelope-5 will spud when the rig arrives from Raptor-1.
Antelope-4 and Antelope-5 well costs are carried by Total SA, with InterOil having a net commitment of $4.6 million for the first $50 million gross expenditure on each well. Site preparation for Triceratops-3 is under way and expected to spud next year.
The Bobcat-1 well in PPL 476, about 30 km northwest of Elk-Antelope, has completed logging a 320-m interval of Kapau limestone with initial indications of hydrocarbons. The well is now undergoing testing.
Drilling & Production — Quick Takes
Chevron starts production from Jack-St. Malo fields
Chevron Corp. has reported the start of oil and natural gas production from Jack-St. Malo fields development project in the deepwater US Gulf of Mexico. The company expects total production from the fields to ramp up to 94,000 b/d of crude and 21 MMcfd of gas by 2020.
Discovered within 25 miles of each other in 2003 and 2004, respectively, Jack and St. Malo fields lie in 7,000 ft of water 280 miles south of New Orleans. Chevron estimates the combined total recoverable resources of the two fields to be more than 500 MMboe.
The Jack and St. Malo fields were co-developed with subsea completions flowing back to a single semisubmersible floating production unit sited between the fields. With a production capacity of 174,000 b/d and 42 MMcfd, it is the largest of its kind in the gulf, says Chevron.
Oil will be transported via pipeline to a platform on Green Canyon Block 19, then on to refineries along the Gulf Coast.
Chevron says that new technologies facilitated Jack-St. Malo development. These include large-diameter, high-pressure pipelines, the industry's largest seafloor boosting system, and the first application of deepwater ocean-bottom node seismic technology.
The deepwater seismic provided images of subsurface layers 30,000 ft below the ocean floor, the depth to which Jack-St. Malo wells were drilled.
Chevron holds a 50% working interest in Jack field, with partners Statoil ASA and Maersk Oil holding 25% each.
Chevron holds a 51% working interest in St. Malo field, with partners Petroleo Brasileiro SA 25%, Statoil 21.5%, ExxonMobil Corp. 1.25% and Eni SPA 1.25%.
Johan Sverdrup partners recommend Statoil as operator
Statoil ASA has been recommended by its partners as operator in all phases of Johan Sverdrup field, which lies on the Utsira High in the North Sea, 155 km due west of Stavanger.
The recommendation will be included in the unit operating agreement (UOA), planned for submission with the plan for development and operation (PDO) in February 2015.
The field development plan includes a field center that will carry out the most important functions while also allowing for the subsequent connection of various installations during the development's different phases, Statoil says. The partnership is targeting a recovery factor of at least 70%.
In August, Kvaerner ASA and KBR Inc. agreed to establish a joint venture to competitively bid on offshore platform topsides contracts for Johan Sverdrup field development (OGJ Online, Aug. 15, 2014). Kvaerner in June signed a letter of intent with Statoil for delivery of two jackets to Johan Sverdrup (OGJ Online, June 26, 2014).
Statoil says it plans to establish a production organization for the field in Stavanger, while drawing upon the expertise of its partners and the supplier industry.
Johan Sverdrup, which encompasses PL 265, 501, 501B, and 502, consists of 95% oil and 5% rich gas, with a resource estimate of 1.8-2.9 billion boe. Production is expected to start yearend 2019.
OMV brings Maari oil redevelopment on stream
The OMV AG-operated Maari oil field redevelopment has been brought on stream in New Zealand's offshore Taranaki basin.
The first of five wells, MR-8A, began production late in November draining a previously unreached compartment in Maari field. The well was a sidetrack from an abandoned injection well and drilled horizontally into the Moki formation to a total length of 3,824 m.
OMV expects the well to be able to produce as much as 4,500 b/d of oil.
The overall redevelopment aims to revitalize existing Maari field, which originally came on stream in February 2008. It has since declined from peak production rates of around 25,000 boe/d (OGJ Online, Oct. 12, 2010).
In April the Ensco-107 drilling rig was brought to the field to carry out abandonment, workover, and new drilling. The first well was drilled into the untapped Mangahewa formation before being suspended to implement a revised completion concept.
MR-8A is the second well in the campaign. The well is producing through existing facilities. Drilling on the other three wells in the redevelopment plan will continue into 2015 and be completed by midyear.
Maari field lies in 100 m of water and lies 80 km offshore the Taranaki coast of New Zealand's north island.
PROCESSING — Quick Takes
Flint Hills breaks ground on Texas refinery expansion
Flint Hills Resources, a unit of Koch Industries Inc., has started construction on a project designed to increase processing capabilities for US crude oil at its 230,000-b/d West refinery at Corpus Christi, Tex. (OGJ Online, Aug. 27, 2012).
At a cost of about $600 million, the West refinery expansion, named Project Eagle Ford (PEF), received final internal board approval in September and currently is scheduled to be completed in 36 months, Koch said.
In addition to equipping the refinery with an ability to process 100% US light US crude from nearby Eagle Ford shale play, PEF also will aid the Corpus Christi plant's efforts to reduce criteria air emissions through the inclusion of best available control technologies, said Valerie Pompa, vice-president of Flint Hills Resources Corpus Christi LLC.
The US Environmental Protection Agency and the Texas Commission on Environmental Quality issued requisite permits for the project in May following an accord Flint Hills reached with environmental groups in late-2013 to implement additional emissions-reduction measures and more-stringent monitoring at the West refinery (OGJ Online, May 29, 2014; OGJ Online, Dec. 12, 2013).
Formerly named the Domestic Crude Project, PEF involves the modification of equipment at the refinery's continuous catalytic regeneration hot oil heater as well as the inclusion of a new saturates gas plant and associated hot oil heater.
PEF also will include installation of a mid-plant cooling tower, equipment piping, process vessels, and two storage tanks at the site.
Once completed, PEF will boost the West refinery's crude oil processing capacity by about 7%.
Rosneft to increase ownership in German refinery
OAO Rosneft has agreed to purchase Total SA's 16.67% share in the 11.5-million tonne/year PCK Raffinerie GMBH refinery located along Druzhba pipeline in Schwedt, Germany, about 120 km northeast of Berlin.
The companies signed an agreement outlining the main terms and conditions of the deal on Nov. 28, Rosneft said.
Total and Rosneft also are exploring an offtake agreement to supply Total's retail and wholesale customers in the Berlin area supplied by the refinery via the pipeline, Rosneft said.
Once the deal is closed, Rosneft, together with its BP PLC-joint venture Ruhr Oel GMBH (ROG) (OGJ Online, May 6, 2011), will own close to 55% of the Schwedt refinery, said Rosneft Pres. Igor Sechin.
A date for when the deal might be finalized was not disclosed.
In addition to Total, current stakeholders in the Schwedt refinery include ROG 37.5%, Royal Dutch Shell PLC 37.5%, and Eni SPA 8.33%.
Williams targets start for Geismar ethylene sales
Williams Partners LP is in the final stages of commissioning and plans to begin ethylene sales from its newly expanded Geismar, La., olefins plant after a series of delays following a 2013 explosion at the site (OGJ Online, June 13, 2013).
Ethylene production sales from Geismar, which previously were scheduled to start in October, are slated to begin this month, the company said (OGJ Online, Aug. 5, 2014).
The delayed start-up stems from ongoing activities related to safety-related upgrades at the plant, said John Dearborn, Williams Partners' senior vice-president of NGL and petrochemical services.
"Some of these commissioning activities have taken longer than originally planned, but as we have stated throughout this process, safety is our No. 1 priority," Dearborn said.
Additional safety modifications made during the plant's expansion and rebuild increased capital spending for the project by $20 million, Williams Partners said in August.
In late October, the company confirmed that commissioning and start-up processes were under way at Geismar, but operations personnel still were directing dry-out activities at the plant (OGJ Online, Oct. 29, 2014).
The 600 million-lb/year Geismar expansion project was designed to boost the plant's ethylene production capacity to 1.95 billion lb/year from 1.35 billion lb/year, with Williams Partners' share of the total capacity amounting to 1.7 billion lb/year.
TRANSPORTATION — Quick Takes
After scuttling South Stream, Russia plans line to Turkey
Russia has decided against the construction of the 930-km South Stream natural gas pipeline across the Black Sea from Russia to Bulgaria, citing delays on the part of the European Union in taking the steps necessary to move forward. Press reports have Gazprom Chief Executive Alexei Miller as confirming the decision originally announced by Russian President Vladimir Putin.
Miller and Mehmet Konuk, chairman of Botas Petroleum Pipeline Corp., signed a memorandum of understanding Dec. 1 on instead building an offshore gas pipeline from the Russkaya compressor station (also South Stream's starting point) under construction in the Krasnodar Territory across the Black Sea to Turkey. Putin and Turkish President Recep Erdogan witnessed the signing.
Turkey in July had approved South Stream's environmental impact assessment, including pipelay for the 63-billion cu m/year project's four parallel strings in its exclusive economic zone starting first-quarter 2015 (OGJ Online, July 25, 2014).
The new pipeline would have the same 63 bcm/year overall capacity, with 14 bcm/year to be used in Turkey and the balance shipped to a border crossing with Greece, the location of which has yet to be decided. The 448-Mw Russkaya station will provide as much as 28.45 MPa of pressure, enough to have shipped gas on South Stream to Bulgaria without intermediate compression.
Meanwhile, Saipem, a unit of Italy's Eni SPA, released a statement saying that it had not yet received any formal notice of termination of its contract with South Stream Transport BV. Pipelay for South Stream Line 2 using the Saipem 7000 was due to start in mid-2015, with first gas flow from Line 1 following later that year (OGJ Online, May 12, 2014).
"Operational activities therefore continue to progress," Saipem said, adding, "The potential interruption of work and any possible cancellation of the project are subject to the terms of contract."
Turkey is Gazprom's second-largest natural gas sales market behind Germany. Gazprom shipped 26.7 bcm to Turkey last year via the Blue Stream and Trans-Balkan pipelines.
Pipeline leak dampens Atlantic LNG production
Atlantic LNG (ALNG) reported a 35% reduction in LNG production because of insufficient natural gas supply from Trinidad and Tobago's National Gas Co. (NGC).
ALNG said it was notified by NGC that a leak was discovered on their 56-in. Cross Island Pipeline (CIP). The CIP line is owned and operated by NGC and is one of three sources of gas supply to the ALNG facility.
The company said it remained in close contact with NGC to receive status updates as they become available and will continue to carefully monitor the situation.
The news comes at a time when ALNG has already been suffering from lower production due to ongoing gas curtailment in Trinidad and Tobago. ALNG Pres. Nigel Darlow complained that the company has been forced to operate below its nameplate capacity for the last 2 years.
Darlow said although ALNG sold LNG to more countries than any other global LNG producer, it also was starting to see its prices hurt due to falling oil prices.
"I think it is going to have a depressing or dampening effect on gas or LNG prices and I think we are already seeing that," he said. "The LNG pricing has come off fairly significantly and a large part of that is because there are a lot of LNG contracts that are effectively oil indexed. So with the declining oil price you have seen a reduction in the LNG pricing."
Magnolia LNG lets EPC contract to SK E&C USA
Magnolia LNG LLC parent-company Liquefied Natural Gas Ltd. agreed to an engineering, procurement, and construction contract with SK E&C USA covering installation of Magnolia's initial 4 million-tonne/year (tpy) liquefaction capacity, two 160,000-cu m storage tanks, a jetty and related ship-loading equipment, and all required approvals and licenses for the full 8 million-tpy project.
Initial liquefaction capacity will come from two 2 million-tpy trains, with similarly scaled Trains 3 and 4 to follow. All trains will use LNG Ltd.'s proprietary optimized single mixed refrigerant process technology.
LNG Ltd. estimates capital costs of the contracted work at $1.986 billion of a total project cost of $3.5 billion. SK prepared the turnkey EPC cost estimate as part of technical services agreement it reached with LNG Ltd. earlier this year (OGJ Online, Apr. 15, 2014). Construction will begin once all approvals and licenses are received; first LNG scheduled for 2018.