GENERAL INTEREST — Quick Takes
BP, Macondo plaintiffs reach settlement
BP PLC has reached a settlement worth an estimated $7.8 billion with a group representing plaintiffs in economic loss and medical claims filed after the Apr. 20, 2010, blowout and fire on the Transocean Deepwater Horizon semisubmersible drilling rig in the Gulf of Mexico.
The settlement, subject to final written agreement, is with the Plaintiffs' Steering Committee acting on behalf of individuals and businesses claiming harm from the fatal blowout and consequent oil spill.
"The proposed settlement represents significant progress toward resolving issues from the Deepwater Horizon accident and contributing further to economic and environmental restoration efforts along the Gulf Coast," said Bob Dudley, BP Group chief executive officer, in a statement.
BP, operator of the deepwater Macondo blowout well, will pay the settlement from the $20 billion trust set up in response to the accident.
The economic-loss part of its settlement estimate includes $2.3 billion to help resolve economic loss claims by the seafood industry.
The proposed agreement to resolve medical claims involves payments based on a matrix for certain currently manifested physical conditions and a 21-year medical consultation program for qualifying plaintiffs. It has provisions for claims for physical problems appearing later.
Under the settlement, covered plaintiffs would release and dismiss their claims against BP.
Before the settlement, BP had made payments related to the Macondo tragedy of more than $8.1 billion to individuals, businesses, and government entities and of about $14 billion for operational responses.
Harvest negotiating to sell Venezuelan interests
Harvest Natural Resources Inc., Houston, has begun exclusive negotiations with a third party for a specified time period for the possible sale of Harvest's 32% interest in Petrodelta SA, its Venezuelan asset.
Petrodelta produced 11.39 million bbl of oil in 2011, up 33% on the year. Petrodelta has averaged 32,500 b/d of oil so far in 2012 compared with 31,205 b/d in calendar 2011.
The Venezuelan company sold 2.27 bcf of natural gas, up 3%. Petrodelta is operating three drilling rigs and one workover rig. Capital expenditures for development drilling and infrastructure are estimated to have been $137.5 million in 2011 compared with $98.7 million in 2010.
Petrodelta drilled and completed 15 successful development wells in calendar 2011 compared with 16 development wells in 2010.
Lundin to acquire Talisman's Brynhild stake
Lundin Petroleum AB has entered an agreement to acquire the 30% interest it doesn't own in Brynhild oil field under development in the North Sea offshore Norway (OGJ Online, Nov. 11, 2011).
Subject to approvals, the company will raise its interest in Production License 148 to 100% by acquiring the 30% interest held by Talisman Energy Norge AS.
Lundin Norway AS has received approval to develop the field with three subsea wells in about 80 m of water tied back to Shell's Pierce floating production, storage, and offloading vessel in the UK sector.
It expects production to start in 2012 and reach a plateau rate of 12,000 b/d of oil.
BLM to hold industry-government conference
The US Bureau of Land Management's Rawlins, Wyo., field office said it will hold its 2012 oil and gas industry-government conference on Mar. 14 at the Jeffrey Memorial Community Center in Rawlins.
The field office, which was designated a pilot office under the 2005 Energy Policy Act and hosts the conference annually, posted an agenda and other information online as it announced the conference on Mar. 1.
Scheduled presentations include: well information systems, communitization agreements, when a right-of-way is needed, transportation planning, greater sage grouse habitat management policy on BLM administered lands in Wyoming, and drilling operations onshore oil and gas orders.
The BLM field office said it expects industry and other agency presentations to cover preconstruction reclamation planning, pygmy rabbits and energy development, regulatory aspects of closing pits, the war on weeds, remote sensing, geospatial mapping/GIS, Migratory Treaty Act and Bald/Golden Eagle Act, and oil and gas filing and agreements.
It said in conjunction with the 2012 industry-government conference, the Monitoring Without Borders (wildlife meeting) will be held Mar. 13 at the Rawlins field office, and the Transportation Planning Meeting will be held Mar. 15 at the field office.
Exploration & Development — Quick Takes
Wintershall starts Dutch North Sea tight gas flow
A group led by Wintershall has started production from K18-Golf field, the company's first tight gas field in the Netherlands North Sea.
Wintershall initially plans to produce 35.3 MMcfd of gas from the Permian Rotliegend formation via one subsea well. A second production well next summer is set to maintain plateau between 35 and 50 MMcfd.
Located in a restricted military zone, K18-Golf had to be developed subsea and within a short time window. Gas is produced via subsea pipeline to the K15-FA platform 10 km north. The gas will be treated there to sales specification before being sent to Den Helder on the Dutch mainland via the Wintershall-operated WGT pipeline network.
The K18-G1 well was drilled 3,750 m vertically and then 1,400 m horizontally. This summer the company will spud the K18-G4 well in the northern part of the field.
Based on the good results of this first tight gas project, Wintershall will focus on the development of more tight gas fields in the Dutch offshore.
Wintershall has a 41.7% interest in K18-Golf. EBN BV has 40%, Nederlandse Aardolie Mij. 15.9%, Tullow Oil PLC 2.2%, and Oranje-Nassau Energie 0.2%. Wintershall was awarded the Block K18 concession in 1983 and discovered the field in 2005.
Statoil group confirms Skrugard oil, gas discovery
A group led by Statoil ASA has confirmed its Skrugard oil and gas discovery in the Barents Sea, which will become the northernmost field development on the Norwegian Continental Shelf.
The 7220/5-1 appraisal well encountered a 26-m gas column overlying a 48-m oil column, and both column thicknesses and reservoir properties were as expected, Statoil said. The well met the objectives of confirming the previous volume estimate for the Skrugard discovery and collecting reservoir and overburden data for field development planning.
The results confirm the previous volume estimate for the Skrugard discovery and the total resource estimate for the Skrugard and nearby Havis structures in the range of 400-600 million bbl of recoverable oil.
Several concepts are under consideration, and developing the fields will transform the Barents Sea into a core area for Statoil, the company said.
The 7220/5-1 appraisal well is about 3 km north of the 7220/8-1 discovery well on the Skrugard structure and 6 km northeast of Havis discovery. Third well on Production License 532, awarded in 2009 in connection with the 20th licensing round, the 7220/5-1 well is drilled to a vertical depth of 1,740 m below sea level in 388 m of water.
Statoil is operator of PL532 with a 50% stake. Eni Norge AS has 30% and Petoro AS has 20%.
Afren tests light oil find off southeast Nigeria
A combine of Afren PLC and Amni International Petroleum Development Company Ltd. of Nigeria has tested a light oil discovery on OML 112 off southeastern Nigeria 45 km southeast of Port Harcourt.
Afren ran three drillstem tests at the Okoro East discovery well, on an undrilled structure 2 km east of the companies' producing Okoro field, in Tertiary sands equivalent to those that produce at Okoro. The tests confirmed high-quality, 38-40° gravity oil in reservoirs with 30-35% average porosity and permeabilities of several darcies.
The Transocean Adriatic IX jack up drilled the well to 8,751 ft measured depth, 8,016 ft true vertical depth. The well encountered 549 ft true vertical thickness of net oil pay and 41 ft of net gas pay in excellent quality reservoir sands, Afren said. Drilled on a prospect mapped on good quality 3D seismic data, the well also targeted a deeper horst block structure, a play concept not previously explored on the block.
"The discovery of significant pay in the previously unexplored deeper zones opens up further prospectivity at similar levels on the main Okoro field and elsewhere on the block," Afren said.
Pressure data helped with the company's structural understanding of the field and support the predrill mean volumetric estimates of 47 million bbl of oil in place in the Okoro reservoirs and 110 million bbl in place in the deeper reservoirs.
Based on test data, the company expects future horizontal production wells at Okoro East will be capable of 4,500-7,000 b/d/well.
Afren will drill two production wells using the free wellhead slots on the Okoro platform in the second half of 2012, to be tied back to the Armada Perkasa FPSO, and as many as eight production wells under a full-field, stand-alone development scenario.
Drilling & Production — Quick Takes
Groups to jointly develop fields offshore Norway
Lundin Norway AS and partners have reached agreement with Det norske Oljeselskap (DNO) ASA to coordinate development of Luno and Draupne oil and gas fields in the North Sea offshore Norway.
Lundin has submitted a development plan that includes a processing platform on a steel jacket in about 110 m of water connected by pipeline to the Grane platform 35 km north (OGJ Online, Jan. 19, 2012). It plans to drill 15 wells with a jack up rig.
Under the coordinated development scheme, partly processed fluids from Draupne field will be transported from a new platform there to the Lundin platform 8 km away for stabilization and export.
Lundin expects Luno production to start in 2015 and peak at 90,000 b/d. The Luno platform will be designed for more than 120,000 b/d of oil and as much as 175 MMcfd of gas to accommodate Draupne output, expected to start in 2016.
Under a tariff arrangement, Draupne interests will be ensured capacity on the Luno platform of 52,000 boe/d starting in October 2016, increasing gradually to 75,000 boe/d.
DNO plans to submit a development plan for Draupne field in the fourth quarter this year. Aker Solutions is conducting pre-front end engineering and design. DNO has signed a contract with Maersk for a new jack up rig to drill production and injection wells, subject to development approval.
DNO discovered Draupne field in 2008 with well 16/1-9, which struck oil and gas in a 44-m thick Middle Jurassic sandstone. Based on production tests of a second well drilled in 2010, the company believes wells in the field can average 12,000 b/d each of light, good quality oil. The total oil and gas column in Draupne is about 150 m, of which 90 m is gas. Draupne includes the smaller Hanz and West Cable discoveries.
Luno is on Production License 338, operated by Lundin with a 50% interest with partners Wintershall Norge ASA 30% and RWE Dea Norge AS 20%. Draupne is on PL001B, Hanz on PL028B, and West Cable on PL242. Interests are the same in all three: DNO, operator, 35%, Statoil 50%, and Bayerngas Norway 15%.
Petrobras starts Santos presalt 6-month well test
Petroleo Brasileiro SA (Petrobras) has hooked up the RJS-647 presalt well for a 6-month test in the Iracema area of the BM-S-11 concession in the Santos basin offshore Brazil.
The Cidada de Sao Vicente floating production, storage, and offloading vessel is connected to the well in 2,212 m of water where it will operate for 6 months gathering technical information to support development of a final production system expected to be in operation by the end of 2014 using the 150,000 b/d-capacity Cidade de Mangaratiba FPSO.
Test rates are expected to be about 10,000 b/d of oil, constrained by facilities. Petrobras has 65% interest in the block. BG Group has 25%, and Petrogal Brasil SA has 10%.
Comments open on Frontier oil sands project
Alberta's Energy Resources Conservation Board has opened applications for the Frontier Oil Sands Mines Project for comment after the operator agreed to a deal that would give it 100% interest in the development about 100 km north of Fort McMurray.
The operator, Teck Resources Ltd., Vancouver, BC, filed applications to build the project last November (OGJ Online, Nov. 29, 2011). In January, it agreed to acquire SilverBirch Energy Corp., Calgary, with which it shares the Frontier project with 50% interests each. The SilverBirch acquisition, subject to approvals, is expected to close by Apr. 16.
The project includes an area called Equinox to the south. It's designed for as many as four production lines with total capacity of more than 277,000 b/d of deasphalted bitumen. The first two lines would have combined capacity of 159,000 b/d. Ultimate recovery over 30 years is estimated at 2.8 billion bbl.
The Teck-SilverBirch deal, involving a net cash outlay by Teck of $435 million (Can.), will result in creation of a company called SilverWillow Energy Corp. in Calgary to hold SilverBirch assets other than the Frontier and Equinox project.
Those assets are exploration leases in the Athabasca oil sands including an area called Audet for which Sproule Unconventional Ltd. has estimated discovered bitumen initially in place at 1.69 billion bbl.
PROCESSING — Quick Takes
Inquiry continues into HF release at Citgo refinery
The US Chemical Safety Board (CSB) dispatched a team of investigators on Mar. 6 to the site of a July 19, 2009, hydrocarbon gas release involving hydrofluoric acid (HF) at Citgo Petroleum Corp.'s Corpus Christi, Tex., refinery. Citgo was able to capture the estimated 21 tons of HF that were released from the plant's alkylation unit and subsequently satisfied recommendations CSB issued the following December, the board noted.
It is continuing its inquiry because of HF's toxic nature and the need to keep it contained or to mitigate consequences of its release, CSB Chairman Rafael Moure-Eraso said. "Approximately 50 of the nation's refineries still use HF in their alkylation units, requiring great care in its handling," he indicated.
The released hydrocarbons in the 2009 incident ignited and became a fire that burned for several days and critically injured one employee, CSB said. Citgo reported to the Texas Commission on Environmental Quality that 21 tons of HF released from alkylation pipes and equipment were captured by a water mitigation system, the federal agency said.
But investigators quickly determined that Citgo nearly exhausted the stored supplies for the water mitigation during the first day, causing the 163,000-b/d refinery to begin pumping salt water as a backup, it added. Multiple failures occurred during the salt water transfer including ruptures of barge-to-shore transfer hoses and water pump engine failures, it said.
The board said its December 2009 urgent safety recommendations called on Citgo to immediately improve the plant's water mitigation and perform third-party safety audits of its HF units there and at its Lemont, Ill., refinery. Citgo met the recommendations' requirements and CSB closed them as acceptable actions in 2011, it said.
CRRM settles pollution allegations at Coffeyville
Coffeyville Resources Refining & Marketing (CRRM) agreed to pay a fine of more than $970,000 and invest more than $4.25 million on new pollution controls and $6.5 million in operating costs to resolve allegations that it violated federal air pollution regulations at its Coffeyville, Kan., refinery, the US Department of Justice and Environmental Protection Agency jointly announced on Mar. 6.
DOJ and EPA said the division of Houston-based CVR Energy Inc. will be required, under the settlement, to install new and upgrade existing pollution controls, establish more stringent emissions limits, and implement more aggressive leak detection and repair practices.
The refiner allegedly violated federal Clean Air Act regulations by making modifications at the 115,000 b/d plant without first obtaining preconstruction permits and installing required pollution control equipment, according to DOJ and EPA.
They said that the plant's management also allegedly violated the federal Comprehensive Environmental Response, Compensation, and Liability Act and the Emergency Planning and Community Right-to-Know Act when it failed to promptly notify state and local emergency responders of hydrogen sulfide and sulfur dioxide releases.
DOJ and EPA said once fully implemented, the pollution controls required under the settlement will reduce an estimated 200 tons/year of NOx emissions and more than 110 tons/year of SO2 emissions. It also will reduce emissions of volatile organic compounds (VOCs), particulate matter, carbon monoxide, and other air pollutants, they indicated.
They said CRRM also agreed to perform a more than $1.2 million voluntary environmental project at the refinery that will lower VOC and hydrogen sulfide emissions, reduce the frequency of future acid gas flaring incidents, and conserve 15 million gal/year of water that previously would have come from the Verdigris River.
DOJ and EPA said the State of Kansas has joined in the settlement and will receive part of the fine. A consent decree, which was lodged in the US District Court for Kansas, is subject to a 30-day comment period and court approval, they noted.
TRANSPORTATION — Quick Takes
MarkWest JV to build Utica gas gathering system
MarkWest Utica EMG LLC, a joint venture of MarkWest Energy Partners LP and Energy & Minerals Group, signed a letter of intent with Gulfport Energy Corp. to provide gathering, processing, fractionation, and marketing services in the liquids-rich southern corridor of the Utica shale.
MarkWest Utica will develop a natural gas gathering system with Gulfport and other producers, primarily in Harrison, Guernsey, and Belmont counties in Ohio. The companies expect the gathering system to come online later this year.
MarkWest Utica will process the gas at its 200-MMcfd Harrison County processing complex, expected to enter service mid-2013, and will provide NGL fractionation and marketing services at the Harrison County fractionator, where NGL purity products will be marketed by truck, rail, and pipeline.
MarkWest last month announced two new processing plants in Harrison and Monroe counties and the 100,000 b/d fractionation, storage, and marketing facility in Harrison County (OGJ Online, Feb. 1, 2012).
NiSource Gas Transmission & Storage's Midstream Services last week announced plans to build a roughly 90-mile, large-diameter natural gas gathering system extending through Ohio's Columbiana, Carroll, Jefferson, Harrison, Belmont, and Monroe counties (OGJ Online, Mar. 2, 2012).
Spectra announces Marcellus-to-Georgia pipeline
Spectra Energy Corp. is holding a nonbinding open season for its 230-mile Renaissance Gas Transmission project, a new pipeline system linking Marcellus, Utica, and Appalachian shale natural gas production to markets in Georgia, Alabama, and Tennessee. The 1.25-bcfd Renaissance project will start at an interconnect with Spectra's Texas Eastern Transmission LP pipeline. In addition to production from the northeastern shales, Texas Eastern offers additional supply options through its access to Gulf of Mexico and Gulf Coast region supplies.
A new 200-MMcfd Utica shale gas gathering system announced last week by NiSource Gas Transmission and Storage's Midstream Services included an interconnect with Texas Eastern (OGJ Online, Mar. 2, 2012).
Spectra also announced a nonbinding letter of intent with AGL Resources to explore a joint business arrangement and transportation service options for local distribution companies owned by AGL Resources operating near the proposed pipeline.
The nonbinding open season will end Mar. 30. Spectra expects Renaissance to enter service in 2015.
UGI, Inergy to jointly develop Marcellus line
Inergy Midstream LP, UGI Energy Services Inc., and WGL Holdings Inc. unit Capitol Energy Ventures Corp. plan to market and develop an interstate natural gas pipeline known as Commonwealth Pipeline. The proposed 200-mile, 30-in. OD system will transport at least 800 MMcfd of Marcellus shale gas production and is expected to be in service during 2015.
Commonwealth Pipeline will extend from the southern terminus of Inergy Midstream's Marc I pipeline in Lycoming County, Pa., due south through central and eastern Pennsylvania to across southeastern Pennsylvania, including Philadelphia, and the Baltimore and Washington, DC, metropolitan areas. The firms expect the line to interconnect with a number of interstate pipelines along its route.
Inergy expects UGI and Capitol to execute precedent agreements to become anchor shippers on the line, with the companies owning equal interests in the firm formed to own the line. Inergy Midstream will construct and operate the pipeline, expected to cost $1 billion split equally between the three firms.
UGI last year announced plans to extend its Auburn Gathering System 30 miles from its terminus in Wyoming County, Pa., to Luzerne County, Pa., including a connection to Transcontinental Gas Pipeline. UGI expects the extension to enter service third-quarter 2013 (OGJ Online, Oct. 21, 2011).
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