GENERAL INTEREST — Quick Takes
Marathon settles federal CAA allegations
Marathon Petroleum Corp. agreed to pay a $2.9 million fine, retire 5.5 billion sulfur credits worth $200,000, and spend more than $2.8 million to install pollution controls on facilities in three states to resolve charges that it violated the Clean Air Act (CAA), the US Department of Justice and Environmental Protection Agency jointly announced.
The Findlay, Ohio-based independent refiner-marketer's failure to comply with certain CAA fuel-quality emissions standards and record keeping, sampling, and testing requirements may have resulted in excess vehicular air pollution, DOJ and EPA said on May 19.
Under a proposed consent decree filed in US District Court for northern Ohio, Marathon, which self-reported many of the violations to EPA, agreed to spend the $2.8 million to reduce volatile organic compound emissions on 14 fuel storage tanks at its distribution terminals in Indiana, Kentucky, and Ohio.
It also will install geodesic domes, fixed roofs, or secondary rim seals and deck fittings on 14 fuel storage tanks at several of its fuel distribution terminals to reduce emissions of VOC, DOJ and EPA said.
Marathon also will be required to use innovative detection technology as it implements the pollution mitigation projects, and an infrared gas-imaging camera to inspect the storage tanks for potential defects, DOJ and EPA said.
In their complaint, the two federal entities alleged that MPC:
• Produced about 356 million gal of reformulated gasoline at its Texas City, Tex., refinery during 2007 that did not meet CAA standards for reducing emissions of VOC.
• Produced more than 40 million gal of gasoline at the Texas City plant in 2009 that exceeded sulfur limits.
• Sold 12 million gal of gasoline with elevated ethanol levels.
• Sold 1 million gal of gasoline at its Tampa, Fla., terminal in 2013 that exceeded Reid Vapor Pressure volatility limits designed to help control ground level ozone during summer months.
• Did not comply with numerous fuel production sampling, testing, record-keeping, and reporting requirements which EPA discovered during inspections of Marathon refineries and laboratories in 2008 and 2009.
The proposed consent decree is subject to a 30-day comment period and the court's approval, DOJ and EPA said.
Utah will join lawsuit challenging BLM frac rules
Utah will ask to join Wyoming, North Dakota, and Colorado in a lawsuit challenging the US Bureau of Land Management's recently issued hydraulic fracturing regulations, Gov. Gary R. Herbert (R) reported. The new federal rule unlawfully interferes with state regulations that already address the process, the action contends (OGJ Online, Mar. 27, 2015).
"There is no question the practice of hydraulic fracturing should be regulated in order to ensure protection of the environment," Herbert said on May 18 during the annual business meeting of the Interstate Oil & Gas Conservation Commission, which he chairs.
"However, adoption of the proposed rule would create an inconsistent, costly, and inefficient regulatory system that provides no additional environmental protection or public safety than is offered by programs already enforced by the state," he maintained.
Herbert said BLM's new regulation, which the US Department of the Interior agency issued in March (OGJ Online, Mar. 20, 2015), is likely to add years to the permitting process and hamper the drilling of thousands of wells in the Beehive State.
He said that according to some estimates, BLM's fracing rule could cost $97,000-253,000/well, and cumulatively cost Utah $75-243 million/year.
"So far, there have been no instances of environmental damage in Utah related to the integrity of a well undergoing a [fracing] operation," Herbert said. "This is yet another unfortunate example of federal regulatory overreach."
Wintershall to exit Qatar
Wintershall Holding GMBH is leaving Qatar, effective May 25, because of lack of access to local infrastructure, the firm said.
A 2013 offshore gas discovery, Al Radeef, is on Block 4 North near North Field.
"During the development planning, it was always clear to us and our partners that an economic development of the discovery, including the processing of the gas, would only be possible if we have access to local infrastructure," said Wintershall's Martin Bachmann, responsible for exploration and production in Europe and the Middle East. "This access was not granted."
The company said further activities in the Middle East are not affected.
"The challenges in the region are increasing with local energy consumption growing rapidly," Bachmann said. "In order to maintain production in the long term, fields must be exploited more efficiently and technically more complex fields need to be developed."
Exploration & Development — Quick Takes
ExxonMobil's Liza-1 well strikes oil offshore Guyana
Esso Exploration & Production Guyana Ltd., a unit of ExxonMobil Corp., reported an oil discovery on Stabroek block 120 miles offshore Guyana.
The Liza-1 well, which was spudded on Mar. 5 and drilled to 17,825 ft in 5,719 ft of water, encountered more than 295 ft of oil-bearing sandstone reservoirs, Esso E&P said.
It is the first well drilled by the company on the 6.6-million acre Stabroek block, said Stephen M. Greenlee, president of ExxonMobil Exploration Co. Over the coming months, Esso E&P will work to determine the commercial viability of the discovered resource and evaluate other resource potential on the block, Greenlee said.
ExxonMobil and other majors began taking an interest in the Guyana-Suriname region in 2012 (OGJ Online, June 4, 2012).
Esso E&P holds 45% interest in the prospect. Partners include Hess Guyana Exploration Ltd. 30% and CNOOC Nexen Petroleum Guyana Ltd. 25%.
MOL makes another discovery on TAL block
MOL Group has made a commercial discovery with its Mardan Khel-1 exploration well on TAL block in Pakistan's Khyber Pakhtunkhwa province. The company also has signed a farm-in agreement for Pakistan's DG Khan block, taking 30% non-operating interest from Pakistan Oil Fields Ltd (POFL).
Mardan Khel-1, which spudded on Sept. 17, 2014, and reached a target depth of 4,912 m on Feb. 17, tested four formations with each flowing high volumes of gas and condensate. The company says total production capacity of Tal facilities, currently 80,000 boe/d gas and 37,000 boe/d of liquids, is sufficient for integration of the new well.
MOL plans to carry out an appraisal plan including additional wells on the eastern and western portions of the structure. The discovery is the company's seventh on the block, occurring more than 4 years after the most recent one (OGJ Online, Feb. 22, 2011).
MOL Pakistan Oil & Gas Co. BV, a wholly owned subsidiary of MOL Group, operates TAL with 10% interest, partnering with Pakistan Oil & Gas Development Co. (OGDC) 30%, Pakistan Petroleum Ltd. (PPL) 30%, POFL 25%, and Government Holdings (Pvt.) Ltd. 5%. MOL is responsible for more than 70,000 boe/d in gross production from the block, which it has operated since 1999. The company holds interest in five Pakistani blocks.
Regarding DG Khan, the company describes it as a "promising gas and condensate exploration opportunity" in Punjab and Balochistan provinces. After MOL's farm-in, the block will be operated by POFL with 70% working interest. The consortium plans to acquire seismic data this year followed by drilling of one exploration well in 2017. The transaction is subject to the approval of the Pakistani government.
"Pakistan is a promising and prospective country with significant remaining undeveloped resources and reserves, and MOL Group remains committed to investing in Pakistan's oil and gas sector as our recent farm-in agreement and continued investment in the TAL block demonstrates," commented Alexander Dodds, executive vice-president of MOL Group E&P.
Rawicz field estimated to hold 50 bcf in 2P reserves
Rawicz gas field in Poland contains estimated gross proved plus probable reserves of 50.3 bcf based upon a five-well development plan, including the recently tested Rawicz-12 well, according to a competent persons report (CPR) from Ryder Scott Co.
Littleton, Colo.-based independent Palomar Natural Resources LLC and Dublin-based independent San Leon Energy PLC expect to move reserves to proved based upon a signed gas contract, which they say is under negotiation.
The companies earlier this year reported "highly positive" preliminary well test results for Rawicz-12.
The companies say they are in the advanced stages of the planning and design of several development scenarios focused on bringing gas online in early 2016. A development plan will be submitted to the Polish regulators, based on the CPR.
The current development plan is based upon building a scalable central processing facility to handle the gas production from adjacent prospects on the Rawicz concession, which Palomar estimates at more than 100 bcf. Poland's Ministry of Environment in 2012 merged the Rawicz and Winsko concessions in the Permian-SW Carboniferous basin and expanded the total concession area (OGJ Online, June 14, 2012).
Palomar operates the Rawicz project with 65% interest. San Leon has no up-front drilling costs for its 35% share of the first two wells.
John Buggenhagen, Palomar chief executive officer, said the firm has already mapped several other large, undrilled structures on its 3D seismic database at Rawicz that would bring potential to the area and justify "a larger, fast-paced development plan."
Drilling & Production — Quick Takes
Total starts production from Russian Arctic field
Total SA has started production of gas and condensate from onshore Termokarstovoye field in the Yamalo Nenets autonomous district in the Russian Arctic. The field will produce 6.6 million cu m of gas and 20,000 b/d of condensate, or a combined 65,000 boe/d, the company said.
Total's Arctic-adapted infrastructure in the field includes a gas gathering network, a gas treatment plant, a gas condensate de-ethanization plant, and export pipelines.
Total developed Termokarstovoye field under a joint venture with OAO Novatek, Russia's largest independent gas producer (OGJ Online, June 25, 2009). The JV company, Terneftegas, operates the field with Novatek holding 51% and Total 49%.
DEA farms out part of West Nile Delta project to BP
DEA Deutsche Erdoel AG has farmed out its stake in the West Nile Delta project in Egypt to its joint venture partner (and operator) BP PLC "in order to better balance its portfolio," the company reported.
The deal includes the sale of a portion of DEA's stake in the ongoing Phase 1 development of 5 tcf of gas resources. "With the remaining interest of 17.25% in both concessions, West Nile Delta will remain the largest project in DEA's portfolio," the company said. The closing of this agreement is subject to approval of Egyptian General Petroleum Corp.
The $12-billion West Nile Delta project, which is planned to start production in 2017, is expected to produce 1.2 bcfd, or about 25% of Egypt's current gas production.
The timing of the farm down coincides with the ramping up of the capital intensive phase of the West Nile Delta project development. Recently, a major project milestone has been achieved when the development drilling campaign started with the spudding of the first development well in Taurus-Libra field. This is the first of a total of 21 planned development wells in Taurus, Libra, Giza, Fayoum, and Raven fields, DEA said.
BP lets Thunder Horse expansion contract
BP Exploration & Production Inc. has let a contract to Technip covering pipeline systems for a southern expansion of ultradeepwater Thunder Horse oil and gas field on Mississippi Canyon Blocks 778 and 822 in the Gulf of Mexico.
The project includes a new drill center 2 miles from the Thunder Horse semisubmersible production, drilling, and quarters platform in 6,050 ft of water, 150 miles southeast of New Orleans. Four wells will tie in to the drill center. BP expects production from the project to start in 2017 and peak at 42,000 boe/d.
Under a lump-sum contract, Technip will handle design, engineering, fabrication, installation, precommissioning, and other services for two rigid production flowlines with four pipeline end terminations.
Production from the Thunder Horse platform, which has capacity to handle 250,000 b/d of oil and 200 MMscfd of natural gas, began in June 2008. The field produces from Upper Miocene turbidite sandstones.
According to US Bureau of Safety and Environmental Enforcement lease data, production from Thunder Horse and Thunder Horse North fields averaged 84,585 b/d of oil and 108.7 MMcfd of gas in the first 2 months of 2015.
BP next year will start up a water injection project expected to develop 65 million boe in the Pink reservoir and establish pressure support.
BP operates Thunder Horse with a 75% interest. ExxonMobil holds 25%.
PROCESSING — Quick Takes
CEPSA boosts gas turbine efficiency at Spanish refinery
Compania Espanola de Petroleos SA (CEPSA) has implemented gas turbine technology from GE to help meet Europe's more stringent environmental emissions standards without reducing efficiency or increasing operating costs at its 12 million-tonne/year Gibraltar-San Roque refinery near Cadiz in southern Spain.
The project, which marks the first use of GE's fuel-flexible High Hydrogen Fuel DLN1 technology at any commercial operation, has increased efficiency of the refinery's GE 6B DLN1 gas turbine by enabling it to use recycled refinery fuel gas (RFG) without needing additional water to generate power, GE said.
Since GE completed the conversion process more than a year ago, the gas turbine's use of waste RFG for power generation has allowed CEPSA to reduce purchases of gas, resulting in a 7% heat rate improvement at the refinery, as well as enabled a 90% reduction in nitrogen oxide emissions from the plant, GE said.
"GE Power Generation Services' solution helped us to increase plant efficiency and reduce our environmental footprint, supporting our goals to produce cleaner energy and meet the region's increasingly stringent emissions requirements," said Antonio Berlanga, operations manager for CEPSA.
In addition to reducing emissions and improving operational efficiency at the plant, the new technology also has contributed to a reduction in the Gibraltar-San Roque refinery's overall downtime for planned maintenance, Manuel Cardenas and Jay Bryant of GE Power Generation Services told OGJ.
"CEPSA's implementation of the technology has given the company a competitive advantage in [the European refining sector], a region still very much in overcapacity and where maximizing resources and cutting costs matter," Cardenas said.
Successful application of the new technology in refinery operations, however, is only the beginning.
"The CEPSA project really was a validation of the technology, but this same technology is not limited to downstream operations," Bryant said, adding that solutions to managing excess gas without increasing water consumption and exceeding emissions limits are just as important to project economics in the upstream.
GE currently is undertaking work to adapt and implement the DLN1 technology for a project in Canada's oil sands, Cardenas and Bryant said.
Lukoil starts production tests for KEGP
Russian's OAO Lukoil has started production tests of two gas treatment plants at the Northern Shady site and Kuvachi-Alat field in Uzbekistan's Bukhara region as part of the Kandym early gas project (KEGP), which is being implemented together with state holding company Uzbekneftegaz.
Earlier this year Lukoil let a contract for construction of the plants (OGJ Online, Feb. 13, 2015).
The treatment plants have a combined capacity of 2.2 billion cu m/year and will process gas from 34 wells to supply the Mubarek gas processing plant. Launching the new facilities will allow Lukoil to significantly increase its gas production in Uzbekistan, the company said.
More than 170 km of power lines, an electric substation, more than 180 km of high- and medium-pressure pipelines, 237 km of fiber optic lines, 150 km of roads, and 7 bridges have been built under the KEGP.
KEGP is the initial stage of the large-scale Kandym group of fields surface facilities construction project under the Kandym-Khauzak-Shady-Kungrad production-sharing agreement. The Kandym group consists of six gas condensate fields: Kandym, Kuvachi-Alat, Akkum, Parsankul, Khoji, and West Khoji. The Northern Shady site (Dengizkul field) lies within the Khauzak-Shady project area, but its surface facilities are being constructed as part of KEGP.
TRANSPORTATION — Quick Takes
Plains All American line causes Pacific spill
Plains All American Pipeline LP's Coastal Line crude pipeline ruptured May 19 in Santa Barbara, Calif., spilling more than 500 bbl into the Pacific Ocean, according to Governor's Office of Emergency Services estimates.
The 150,000 b/d, 24-in. OD pipeline carries crude from ExxonMobil Corp.'s Las Flores Canyon crude processing plant to a pump station in Gaviota, Calif. The Las Flores Canyon plant is about 15 miles west of Santa Barbara. The pipeline leaked into a culvert which then transported the oil to the Pacific Ocean, creating a 4-mile slick. PAA shut down the pipeline and sealed the culvert. Officials evacuated Refugio State Beach.
"The spill has impacted ocean water and the shoreline," PAA said in a statement. "[PAA] deeply regrets this release has occurred and is making every effort to limit its environmental impact." The company deployed a 1,500-ft boom May 19 to help contain the oil and began skimming operations.
Las Flores Canyon removes water from crude produced offshore at Hondo, Pescado, and Sacate fields. Pipelines move the crude from the Hondo, Harmony, and Heritage platforms, in 842-1,200 ft of water, to Las Flores. Hondo started operations in 1981, with Harmony and Heritage following in 1993.
A 20-in. OD wet oil line and 12-in. OD natural gas line extend 7 miles from Heritage to Harmony, with a 20-in. OD line connecting Harmony to Las Flores Canyon, 10 miles away, and a 12-in. OD line returning produced water to the platform. Gas is moved from Harmony to Hondo (3 miles) and then piped via 12-in. line to Las Flores. Hondo sends its produced crude to Harmony.
Las Flores can produce 100,000 b/d of dry crude. It has 540,000 bbl of storage, with additional storage available at Gaviota.
ACP identifies alternate route segments
Atlantic Coast Pipeline LLC (ACP) has identified several alternate route segments as potentially having the least impact to environmental, historic, and cultural resources and is incorporating them into the proposed route of its 550-mile, 1.5-bcfd interstate natural gas transmission pipeline across three states. The alternate segments are in Augusta and Nelson counties, Va.
The company has begun contacting Virginia landowners of the alternate segments and other remaining segments that have not given permission to survey their properties, asking again for their permission so it can find the best route with the least impact. Landowners of about 83% of the entire route have given the company permission to survey.
ACP-a corporation formed by Dominion Transmission Inc., Duke Energy, Piedmont Natural Gas, and AGL Resources-proposed the pipeline to supply Marcellus and Utica shale gas to multiple public utilities in Virginia and North Carolina. The company will file a final proposed route with its formal US Federal Energy Regulatory Commission application later this summer.
The pipeline would have a 42-in. OD in West Virginia and Virginia, and a 36-in. OD in North Carolina. A lateral to Chesapeake-Hampton Roads, Va., would measure 20 in. Dominion plans three compressor stations for the pipeline, one at its West Virginia starting point, one in Buckingham County, Va., and one near the Virginia-North Carolina border (OGJ Online, Sept. 2, 2014).
Anadarko lets contract for Mozambique LNG project
Anadarko Petroleum Corp. has let a contract to CB&I, Chiyoda Corp., and Saipem SPA-together forming the CCS joint venture-for the initial development of an LNG project in Mozambique.
The scope of work includes two LNG trains, each with capacity of 6 million tonnes/year, an increase of 1 million tpy for each train over the original plan while maintaining an estimated cost that is consistent with the co-venturers' original projections, Anadarko says.
The scope also includes two 180,000-cu-m LNG storage tanks, condensate storage, multi-berth marine jetty, and associated utilities and infrastructure.
Anadarko says selection of the CCS JV is subject to negotiation and entry into a definitive agreement prior to Anadarko and its co-venturers in Mozambique's Offshore Area 1 taking a final investment decision.
"Selecting CCS JV for the development of the onshore Mozambique LNG park is a significant step toward reaching FID and demonstrates our continued commitment to advancing this important project toward first cargoes," said Al Walker, Anadarko chairman, president, and chief executive officer.
He added that the co-venturers have secured more than 8 million tpy in nonbinding long-term off-take agreements that are now progressing toward binding sales and purchase agreements, and obtained letters of intent from lenders for project financing at "a very material level."
