General Interest — Quick Takes
Shell settles EPA chemical reporting allegation
Shell Guam Inc. agreed to pay $30,590 to settle charges that it violated a federal environmental law by not submitting required toxic chemical reports, the US Environmental Protection Agency said on Oct. 5.
The Royal Dutch Shell PLC subsidiary agreed to pay a $7,950 fine as part of the settlement, and to donate $28,300 to the US territory's fire department for personal protective equipment, EPA said.
EPA said Shell Guam regularly uses polycylic aromatic compounds, naphthalene, and other toxic chemicals as components of fuel that it repackages at its facility. The company allegedly failed to submit toxic release inventory reports to EPA of the amounts of chemicals it processed in 2007, as required under the Emergency Planning and Community Right-to-Know Act.
Facilities that process more than 25,000 lb/year of the chemicals cited in this case must report releases of these chemicals annually to EPA and the state or territory in which the plant is located, the federal environmental regulator said.
EPA said it compiles toxic chemical information annually from the previous year to produce a publicly available toxics release inventory. It said this database estimates the amounts of each toxic chemical released into the environment; treated or recycled on-site; or transferred off-site for waste management, and also provides a trend analysis of toxic chemical releases.
EPA cites Frontier for impoundment violations
Frontier Refining Inc. illegally stored hazardous waste in a wastewater management pond at its Cheyenne, Wyo., facility, the US Environmental Protection Agency charged.
The waste was stored in a pond that was neither constructed nor operated properly to prevent and detect leaks, EPA said in an enforcement and compliance action that it filed on Oct. 1.
EPA said other violations of the federal Resource and Conservation Recovery Act that it found during a March inspection related to closing the pond and providing financial assurance for its proper closure.
EPA sought nearly $7 million in fines from Frontier for operating an unauthorized hazardous waste unit.
The order also requires the refiner to take the pond out of service, remove wastewater and sludge, determine whether the wastes leak into groundwater or soils, remove the existing pond structure and contaminated soils, and cap the area in accordance with RCRA requirements for closing a surface impoundment, EPA said.
Gazprom enters US gas trading, marketing market
Gazprom Marketing & Trading USA Inc. has begun trading and marketing of natural gas, marking the US entry by a unit of Russia's OAO Gazprom.
"We look forward to significant growth and profitability from our expanding geographical base," said Vitaly Vasiliev, chief executive officer of the UK's Gazprom Marketing & Trading Ltd.
Gazprom's US trading and marketing unit has acquired more than 350 MMcfd of physical gas supplies at several sites across the US for the next 3-7 years through long-term gas swaps.
The company also will market LNG exported to North America. This includes long-term agreements enabling it to buy LNG from the Sakhalin-2 LNG plant and regasify the LNG in Baja California, Mexico, to be transported by pipeline for sale in the southwestern US.
The company also plans to import LNG into the US from the giant Shtokman LNG development in the Arctic.
Exploration & Development — Quick Takes
BP reports Tebe oil discovery off Angola
A BP PLC subsidiary said test results show its Tebe oil discovery on ultradeepwater Block 31 off Angola has the reservoir capacity to flow more than 5,000 b/d "under production conditions."
The well was drilled in 1,752 m of water to 3,325 m TD in the southern portion of the block about 12 km southeast of the October 2005 Hebe discovery and 350 km northwest of Luanda, Angola's capital and largest city.
Company officials said Oct. 1 it is BP's 19th discovery on Block 31. BP Exploration (Angola) Ltd. is operator with 26.67% interest. Sonangol is concessionaire of Block 31, with Sonangol P&P holding 20%.
Other interest owners are Esso Exploration & Production Angola (Block 31) Ltd. 25%, Statoil Angola AS 13.33%, Marathon International Petroleum Angola Block 31 Ltd. 10%, and Total SA unit Tepa (Block 31) Ltd. 5%.
Consortium officials said development of their deepwater Pluto, Saturn, Venus, and Mars oil fields in the northeast sector of Block 31 is proceeding with first production targeted in 2012.
Maari field partners confirm additional reserves
The OMV-led joint venture at Maari oil field in the Taranaki basin off New Zealand has confirmed additional produceable oil reserves are contained within a separate reservoir, designated M2A, about 50 m above the main Moki formation.
It lies in the main Maari mining licence PMP 38160.
The group has now completed a horizontal well into this reservoir that encountered 660 m of net pay zone. OMV estimates the in-situ oil reserves to be 30-40 million bbl, or about a quarter of the volume of the in-situ reserves figure placed on the Moki formation reservoir.
However an estimate of recoverable reserves in the new zone will not be available until production data from the M2A well has been obtained and a development plan established.
The joint venture wants to produce from the M2A well only intermittently when there is available spare capacity in the Maari production facilities.
At the moment, the field's five Moki production wells are producing at close to 40,000 b/d of oil, which is 10% more than the 35,000 b/d design capacity of the Raora floating production, storage, and offloading vessel now stationed in the field.
The field, which is New Zealand's largest oil field, has produced more than 3 million bbl since it came on stream in February.
OMV now plans to return to the Manaia-1 extended reach well, which has targeted and found hydrocarbons within the Mangahewa sandstone in a structure about 10 km southwest of Maari field. This well was suspended in mid-September so the M2A well could be drilled at Maari. The plan is to reenter the well to drill a horizontal section through the reservoir to determine the viability of the find. The Ensco 7 jack up drilling rig is being used for the program.
If Manaia is commercial, the production will be tied back to the Maari facilities.
Manaia-1 is an appraisal of the Mangahewa Sand reservoir found back in 1970 by the Shell-BP-Todd group with the Maui-4 vertical well which tested oil at 575 b/d, but was not commercial at that time. The structure now lies in the greater Maari exploration licence PEP 38413.
OMV is operator of both licences with 69% interest. New Zealand's Todd Energy has 16%, Sydney's Horizon Oil has 10%, and Cue Energy Resources, Melbourne, holds 5%.
Eni gains operatorship of Ghana licenses
Eni Ghana Exploration & Production Ltd. will operate the Offshore Cape Three Points (OCTP) and Offshore Cape Three Points South (OCTPS) exploration licenses in Ghana after acquiring a major interest from Vitol Upstream Ghana Ltd.
Eni will hold a 47.22% interest in both blocks while Vitol will take a 37.78% interest. State company Ghana National Petroleum Corp., meanwhile, will hold 15%. GNPC will have a back-in option for an additional 5% in OCTP and 10% in OCTPS.
The consortium this summer drilled the Sankofa-1 well on the OCTP block in 850 m of water. "The well encountered high-quality reservoir sands containing 36 m (net) of oil and gas. Both blocks lie in the prolific Tano-Cape Three Points oil basin, which has recently yielded some of the biggest offshore discoveries yet made in Africa," said Eni. The Sankofa is a significant hydrocarbon discovery that is 35 km east of Jubilee field, which will start production next year.
This deal marks the reentry of Eni in Ghana where it was present until the 1970s.
Eni has been present in Sub-Saharan Africa since the early 1960s. Its operated production in the area is 450,000 boe/d.
Southwestern Campos basin well finds oil
An exploratory well in the southwestern Campos basin has cut an oil column of more than 100 m with about 40 m of highly porous and permeable sandy reservoirs, said OGX Petroleo e Gas Participacoes SA, Rio de Janeiro.
The 1-OGX-1-RJS well, in 140 m of water 85 km off Rio de Janeiro in the BM-C-43 block, is still drilling toward deeper objectives using the Diamond Offshore Ocean Ambassador semisubmersible. OGX, which gave no depths or other details, holds 100% interest in the block.
The block is southwest of Maromba oil field, which Petroleo Brasileiro SA declared commercial in late 2006.
Drilling & Production — Quick Takes
Apache to tap Argentina unconventional gas
Argentina's secretary of energy has approved the first contract under an incentive program to encourage development of unconventional natural gas reservoirs.
Under the contract, Apache Corp., Houston, will drill as many as 48 wells in two Neuquen basin fields in the next 4 years and supply 50 MMcfd of gas at a price of $5/MMbtu. The contracts take effect in January 2011, but the power plant customer has indicated it may begin taking gas in mid-2010.
The expected reserves would not be developed without Argentina's Gas Plus program, said Jon Graham, president of Apache Argentina. Apache has submitted five more development projects in the same basin with different geological parameters for approval under Gas Plus.
At Anticlinal Campamento field in Neuquen Province, Apache will drill as many as 12 wells to tap dry gas in Jurassic Pre-Cuyo fractured volcanics and basement reservoirs as deep as 10,500 ft. Apache describes the reservoirs as unconventional and said it will apply multiple hydraulic fracs in the highly deviated lower part of the wells.
Meanwhile, Apache will drill as many as 36 wells in Estacion Fernandez Oro field in Rio Negro Province. These wells involve drilling to 12,500 ft true vertical depth with as much as 20° of deviation and conducting multiple fracs in tight Jurassic Lower Lajas sandstone. Expected recovery is rich gas and 50° gravity condensate.
Apache will provide measurement and production facilities for the Gas Plus volumes separate from the rest of the fields' production facilities.
Apache produced 193 MMcfd of gas in Argentina at an average $1.89/Mcf in the quarter ended June 30. That included sales to regulated residential and power generation markets and deregulated industrial markets.
Regulators recently approved price increases in the residential and power generation sectors, Apache said.
Oyong gas field off Indonesia comes on stream
Santos Group's Oyong natural gas field off Indonesia has been brought on stream as part of the field's Phase 2 development.
Gas is being transported from the field via a 60-km subsea pipeline to an onshore processing plant at Grati in East Java.
Oyong lies in the Sampang production-sharing contract area in the Straits of Madura and contains both oil and gas reserves in the Mundu formation carbonate reservoir of Pliocene age.
Discovery well Oyong-1 was drilled in 2001 and Phase 1 oil development began in September 2007.
Phase 2 has been to recover the field's estimated 103 bcf of gas reserves. Gas is contracted to PT Indonesia Power to use as an electric power generation fuel under a deal signed in 2003.
Santos Ltd., Adelaide, is operator with 40%. Cue Energy Ltd., Melbourne, has 15% and Singapore Sampan has 40%.
Apache, Santos let Reindeer field contract
Apache Energy Corp. and Santos Ltd.—partners in the Reindeer field-Devil Creek natural gas project in Western Australia—have let a $195 million (Aus.) contract to a joint venture of Malaysia's Sapura Crest Petroleum and Norway's Acergy for the installation of a suite of pipelines and offshore production facilities.
The work involves the transport and installation of 91 km of rigid pipeline including offshore pipeline and a shallow-water beach approach, subsea tie-in and stabilization works, as well as a wellhead platform at the Reindeer gas field comprised of a 1,700-tonne four-leg steel jacket and a 450 tonne topside processing module.
Engineering and preparatory work will begin immediately in Kuala Lumpur and Perth. Offshore installation is scheduled to begin late next year using the Sapura 3000 dynamic positioning heavy lift and pipelay vessel.
The Devil Creek gas plant is about 50 km south of Karratha and will supply as much as 220 TJ/day of sales gas into the Dampier-Bunbury trunkline. There will also be an associated production of up to 500 b/d of condensate stripped from the gas stream.
Work at Devil Creek began in September and the plant is scheduled to come on stream at the end of 2011.
SPE: Oil recovery takes collaboration
Recovering the world's remaining oil resources will require a collaborative effort of national oil companies, international oil companies, and service companies, according to Mohammed Al-Qahtani, executive director, petroleum engineering and development of Saudi Aramco.
Al-Qahtani made his comments Oct. 5 at the SPE Annual Conference & Exhibition in New Orleans.
Al-Qahtani said the world still had considerable amounts of oil to recover. His estimate was that about 4.7 trillion bbl remained to be produced. This includes about 2 trillion bbl from reserves additions and exploration, 1.5 trillion bbl from nonconventional resources, and 1.2 trillion from new technology, he said.
In addition, he noted that the world would need an additional 90 million b/d to offset declines in existing oil fields to reach a 125 million b/d level by 2030. Current world production is about 80 million b/d.
SPE: Chemistry scoring index proposed
A chemistry scoring index may help address the recent controversy on assessing the hazards of chemicals used in stimulating wells, according to Ron Hyden, strategic business manager for Halliburton's production enhancement product service line in Houston.
Hyden made his remarks Oct. 5 at the SPE Annual Conference & Exhibition in New Orleans.
He said Halliburton has developed an index that currently a third party is assessing. Upon finalizing the index, Halliburton plans to release it for use in the industry, Hyden said.
The index addresses the ability of chemicals to be health, physical, and environment hazards.
Concerns related to heath include chemical toxicity and whether the chemicals are carcinogens and mutagens as well as if they affect reproduction and organs. Another health concern is whether the chemicals are corrosive or irritant substances.
Physical hazards relate to chemical properties such as explosiveness, flammability, oxidization, and corrosiveness.
Environment hazards include whether the chemicals produce acute-chronic aquatic toxicity, hazardous air pollution, and water pollution, as well as if the chemicals bioaccumulate, biodegrade, and are sustainable.
The index expresses the constituent concentration and health, safety, and environmental effect as a numerical aggregated score, Hyden said. He noted that the aggregated score allows companies to select chemical formulations that have the lowest score for their application.
SPE: Pemex aspires for 60% Cantarell recovery
Pemex Exporation & Production is studying new ways for recovering more oil from the tight reservoir matrix of Cantarell field off Mexico.
Speaking Oct. 7 at the SPE Annual Conference & Exhibition in New Orleans, Carlos Morales Gil, Pemex E&P director general, said carbon dioxide injection might provide the means to produce additional oil from the field that originally contained about 35 billion bbl of oil in place, making it the third largest oil field in the world. Steam injection is another possibility for improving recovery of the field's 22° gravity oil, he said.
Gil said Pemex now targets a 60% oil recovery from the field. To date, Pemex has produced about 12.2 billion bbl and has obtained a 41% recovery for the Akal portion of the field, he noted.
The Chac 1 well, drilled from June 1974 to July 1976, discovered the field. First production started in 1979 and Pemex maintained about a 1 million bo/d production level until 1996. An infill drilling program, additional platforms, and a 1.2 bcfd nitrogen injection scheme increased production in the field to more than 2 million bo/d in 2001. Since then, production has declined and currently is about 600,000 bo/d, Gil said.
One obstacle for carbon dioxide injection is to find a large source of carbon dioxide. Gil said that the field would need a carbon dioxide supply of about 1.2 bcfd, the same as the nitrogen injection rate.
Processing — Quick Takes
Sunoco idles Eagle Point refinery in New Jersey
Another US independent refiner is slashing operations in response to low refining margins.
Sunoco Inc., Philadelphia, is idling its 150,000-b/d Eagle Point refinery at Westville, NJ, citing "a recessionary economy, weak demand for refined products, and increased global refining capacity."
The refinery is interconnected with Sunoco's refineries at Philadelphia and Marcus Hook, Pa., which form a complex with crude capacity totaling 655,000 b/d.
Sunoco said Eagle Point is the least integrated of the three refineries. The closure will enable the company to increase capacity utilization at the other two facilities and to keep total output by the complex essentially unchanged.
Another independent refiner that has made deep cuts in its operations is Valero Energy Corp., which has shut major units at its Delaware City, Del., and Corpus Christi, Tex., refineries and shut down its refinery in Aruba (OGJ, Sept. 14, 2009, Newsletter).
Sunoco said it will keep the Eagle Point refinery closed until market conditions improve or until it implements other options, which might include using the facility to produce alternative fuels.
In June the company bought a 100 million gal/year ethanol plant at Volney, NY, from bankrupt Northeast Biofuels LP for $8.5 million (OGJ Online, June 18, 2009).
At Eagle Point it will furlough about 400 employees, who will have the option of returning to work if the refinery resumes operation. It will offer the workers a voluntary severance package.
Product storage and handling work will continue at the site, and the Sunoco Logistics Partners LP products rack will remain open.
Sunoco's 170,000-b/d Toledo, Ohio, refinery is unaffected by the move.
Sunoco estimated that idling the Eagle Point refinery will reduce pretax expenses by $250 million/year. It expects to incur pretax charges of $475-550 million, mostly noncash, from asset impairment and idling costs.
The company already had in place an effort to cut costs by $300 million/year by the end of 2009. In its announcement of the Eagle Point closure, it said it would cut its dividend in half to save about $70 million/year.
Murphy Oil acquires ethanol plant
A subsidiary of Murphy Oil Corp. has purchased a corn-based ethanol plant in Hankinson, ND, for $92 million.
Additionally, an estimated $15 million in working capital will be invested into the facility, Murphy Oil said. The plant's production capacity was 110 million gal/year before it was idled in October 2008.
David M. Wood, Murphy Oil president and chief executive officer, said the acquisition will supplement Murphy Oil's growing fuels business.
"It also marks our initial entry into the manufacture of bio-fuels," Wood said. He cited current ethanol mandates and the company's subsequent blending needs as the reason for Murphy to want "a presence in the supply chain."
Wood said he expects to see ethanol production "shortly," noting that the plant is near a feedstock supply and has accessible rail service for carrying the finished product.
Transportation — Quick Takes
LNG project weathers Indonesian earthquake
Operator BP PLC said that its Tangguh LNG project, which lies in the Bintuni Bay area, is operating normally despite a 6.1-magnitude earthquake that hit West Papua, Indonesia, on Oct 4.
"The earthquake in Manokwari was not felt at the LNG project location. The operation is running normally," said BP Indonesia country head Nico Kanter.
Indonesia's Geophysics, Climatology, and Meteorology Agency said the epicenter of the quake was 123 km northwest of Manokwari, West Papua, at a depth of 56 km.
The announcement follows reports last week that piped supplies of Indonesian gas from South Sumatra to Singapore—which account for more than a third of the city-state's needs—were not disrupted by a 7.6-magnitude earthquake in West Sumatra on Sept. 30.
The report followed checks by the Singapore importer, Gas Supply Pte. Ltd. (GSPL), with ConocoPhilips, the field operator.
GSPL, a subsidiary of Temasek Holdings, imports 350 MMscfd of gas from Grissik, South Sumatra, representing 37% of total Singapore imports of 940 MMscfd currently.
Enbridge, Chevron to bring Big Foot oil ashore
Enbridge Inc. has signed a letter of intent with Chevron USA Inc., Statoil Gulf of Mexico LLC, and Marubeni Oil & Gas (USA) Inc. to construct and operate a 40-mile, 20-in. OD oil pipeline from the proposed Big Foot ultradeepwater development in the Gulf of Mexico.
Enbridge has already announced plans to construct the Walker Ridge Gathering System, providing natural gas transportation for the proposed Chevron-operated Jack, St. Malo, and Big Foot fields.
The Big Foot Oil Pipeline will reach depths of up to 5,900 ft, transporting as much as 100,000 b/d to a subsea connection on existing deepwater pipeline infrastructure.
Chevron initiated front-end engineering and design in March of a hub to develop Jack and St. Malo fields. The production facility would have capacity of 120,000-150,000 boe/d. Chevron estimates combined recoverable liquids reserves of the two fields at more than 500 million bbl (OGJ Online, Aug. 1, 2009).
Enbridge estimates the cost of the Big Foot Oil Pipeline, about 170 miles south of the Louisiana coast, at about $250 million. Combined with the Walker Ridge Gathering System project,
More Oil & Gas Journal Current Issue Articles
More Oil & Gas Journal Archives Issue Articles
