GENERAL INTEREST — Quick Takes
Halliburton, Baker Hughes agree to merge
Two of the largest oil-field services companies have agreed to merge.
Halliburton Co. and Baker Hughes Inc. signed a definitive agreement for the stock-and-cash acquisition by Halliburton of all outstanding Baker Hughes shares. Equity value of the deal is $34.6 billion, based on Halliburton's closing price on Nov. 12.
At completion, Baker Hughes stockholders will own about 36% of the combined company.
Dave Lesar, Halliburton chairman and chief executive officer, said the deal is expected to "yield annual cost synergies of nearly $2 billion."
The combined company had pro forma 2013 revenue of $51.8 billion.
Halliburton agreed to divest businesses generating as much as $7.5 billion/year in revenue if required by regulators and will pay a fee of $3.5 billion if the transaction fails to win antitrust approval.
Apache to sell noncore assets for $1.4 billion
Houston independent Apache Corp. has agreed to sell noncore southern Louisiana and certain Anadarko basin assets in two separate deals for a combined $1.4 billion. Both transactions, effective Oct. 1, are expected to close during the fourth quarter.
The southern Louisiana assets comprise working interest in 90,000 net acres, which the company says are characterized by high decline rates and short reserve lives. During the third quarter, the acreage produced 21,000 boe/d net to Apache, of which 62% was gas and natural gas liquids. Apache will retain its 275,000 mineral acres in southern Louisiana.
The Anadarko basin assets comprise 115,000 net acres in a portion of the firm's Stiles Ranch field in Wheeler County, Tex., and in its Mocane-Laverne and Verden fields in western Oklahoma. During the third quarter, net production from the properties averaged 26,000 boe/d, of which 83% was gas and NGLs.
"We continue to focus on growing liquids production from our deep inventory of North American resource locations," said G. Steven Farris, Apache's chairman, chief executive officer, and president. "Proceeds from today's announced asset sales will be used primarily to fund our 2014 leasehold acquisition program, which has added significant acreage within our primary focus areas."
Additional asset sales made this year by the company include interest in the deepwater Gulf of Mexico (OGJ Online, June 30, 2014); properties in the Deep basin area of western Alberta and British Columbia (OGJ Online, Mar. 31, 2014); and all of its Argentina operations (OGJ Online, Feb. 12, 2014).
Apache also reported plans to exit its holdings in the Wheatstone LNG project in Western Australia and Kitimat LNG project in Bish Cove, BC, in a move consistent with the company's "ongoing repositioning for profitable and repeatable North American onshore growth (OGJ Online, Aug. 1, 2014)."
The company forecasts 2015 North American onshore liquids growth of 12-16% when adjusted for this year's asset sales. On a barrel of oil equivalent basis, the company projects 2015 North American onshore production growth of 8-12%. The forecast assumes a preliminary North American onshore exploration and production capital budget of $4 billion.
Apache presented a 5-year compounded annual production growth outlook for onshore North American liquids of 12-16% and 8-12% on a boe basis.
AFPM: Oregon's proposed LCFS unconstitutional
Oregon's proposed low-carbon fuel standards (LCFS) program is unconstitutional, the American Fuel & Petrochemical Manufacturers said in comments submitted in response to the state's Department of Environmental Quality's (DEQ) Clean Fuels Program Phase 2 rulemaking and proposed rule changes.
"It discriminates against out-of-state gasoline and diesel fuel providers in order to promote the development of an in-state biofuels program, and imposes more stringent requirements on out-of-state ethanol producers," explained AFPM General Counsel Richard Moskowitz.
The national association that represents refiners and petrochemical manufacturers argued that if Oregon adopts the proposals, it would:
• Establish a fuel standard that is expressly preempted by the Clean Air Act (CAA).
• Discriminate against out-of-state and foreign commerce in violation of the US Constitution's Commerce Clause.
• Raise serious policy questions that Oregon's DEQ has not addressed, and that undermine the state legislature's objective to reduce greenhouse gas emissions.
Oregon's proposed LCFS program also would hit consumers in the pocketbook, Moskowitz said. "Numerous LCFS studies show that such programs will drive up fuel costs substantially," he said. "It's simply what happens when you have a government mandate that tries to force the use of fuels that either don't exist, or that consumers don't want, or, in this case, both."
Exploration & Development — Quick Takes
Talisman, Ecopetrol make heavy oil find in Colombia
A unit of Talisman Energy Inc., Calgary, and Colombia's Ecopetrol SA gauged a heavy oil discovery with the Nueva Esperanza-1 exploratory well (A2b), which was drilled on Block CPO-9, in Meta, Colombia.
The well was spudded on July 18 and reached total depth at 12,056 ft on Sept. 26. During an initial 8-day flow test using an electro-submersible pumping system, 309 ft of perforations in the T2 formation stabilized at a flow rate of 910 b/d of 8° gravity crude oil with less than 2% water cut during the last day of flow.
Talisman and Ecopetrol are jointly analyzing the results and will file an application with the Colombian authorities to place the well on long-term test. Approval has been granted to drill two down-dip appraisal wells, the first of which, Nueva Esperanza-2, started drilling on Nov. 16.
Nueva Esperanza-1 is the second oil discovery made by Talisman and Ecopetrol on Block CPO-9, following the discovery of hydrocarbons in the Akacias structure in 2010 (OGJ Online, Dec. 1, 2010). In accordance with Colombian regulations, the partners declared commerciality of Akacias field in December 2013 and currently await receipt of a development license.
The Nueva Esperanza structure is adjacent to, and along the same structural trend as, Akacias field. Additional exploration wells along the continuation of this trend are planned.
Ecopetrol is operator of Block CPO-9 with 55% interest and Talisman (Colombia) Oil & Gas Ltd. has 45% interest in the license.
Statoil halts Kwanza exploration program
Statoil AS canceled its Stena Carron rig contract effective Nov. 21 after fulfilling work commitments in company-operated Blocks 38 and 39 of the presalt Kwanza basin offshore Angola.
Initial well results from the area were "disappointing," Statoil says, and more time is needed to evaluate the results and mature new prospects before determining future activities. The company, however, notes that it still sees remaining prospectivity in the basin and on Statoil acreage.
The Dilolo and Jacare wells, the first two operated by Statoil in the play, have been drilled safely and efficiently, and the company has met its drilling commitments on the two blocks, Statoil says. The Jacare well on Block 38 has been plugged and abandoned.
Statoil is participating in eight commitment wells across five blocks in the Kwanza basin. Four wells have been completed; one well is ongoing on Block 40 operated by Total SA.
The costs of terminating the operations and associated services, including the Stena Carron drillship contract, will be expensed in the fourth quarter at $350 million. Statoil in 2013 signed a 3-year, $700 million contract with Stena Drilling for the drillship (OGJ Online, Mar. 19, 2013).
Statoil's guidance for this year's organic exploration expenditures remains at $3.5 billion, which includes the Jacare well cost in Block 38 to be expensed in this year's fourth quarter. The signature bonus on Block 38 is expected to be impaired.
Earlier this year the company farmed out interest in Blocks 38 and 39 to WRG Angola Block 39 Ltd. and Colombia's state-owned Ecopetrol SA (OGJ Online, Apr. 3, 2014; July 3, 2014). Statoil also gave up 5% interest in Eni SPA-operated Block 15/06(OGJ Online, May 12, 2014).
Statoil exits two Northern Territory permits
Norway's Statoil AS has pulled out of two exploration permits in the southern Georgina basin onshore Northern Territory.
The move follows disappointing results from drilling and testing in permits EP127 and EP128 that Statoil conducted with Baraka Energy & Resources Ltd., South Perth.
The companies say the wells found insufficient reservoir permeability in any of the target shale formations despite encouraging hydrocarbon shows.
Commenting on Statoil's exit, Baraka said it had been approached by a Canadian company interested in pursuing exploration in conventional oil and gas reservoirs in EP127.
Baraka says that all minimum expenditures for both permits have been met and further exploration will be subject to discussions with the joint venture partners (including the interested Canadian group) and the regulator.
The company has not yet heard whether Statoil also plans to withdraw from EP103 and EP104, which are operated by PetroFrontier Corp., Calgary.
Statoil recently was awarded a new permit offshore Western Australia in which it holds 100%.
Bids spike in Northern Alaska lease sales
Alaska's Division of Oil & Gas received 356 bids on 298 tracts in its 2014 Northern Alaska area-wide lease sales, trumping the 92 bids received for 91 tracts in the same areas last year (OGJ Online, Nov. 6, 2013).
The North Slope took the bulk of this year's bids at 297, while the Beaufort Sea received 57 bids and the North Slope Foothills received 2 bids.
Drilling & Production — Quick Takes
Echo platform explosion occurred during maintenance
Fieldwood Energy LLC, Houston, reported that the Nov. 20 explosion at its West Delta 105 "E" platform, known as Echo, occurred as employees of Fieldwood-contracted Turnkey Cleaning Services (TCS) were cleaning a heater-treater.
During the cleaning process, one Turnkey employee was fatally injured and a second suffered what Fieldwood describes as "visible injuries"-the company initially described those injuries as "serious" (OGJ Online, Nov. 21, 2014). That employee was transported immediately to West Jefferson Hospital in Marrero, La., for evaluation and treatment.
Two other individuals who complained of ringing in their ears were also flown to that hospital to be evaluated. All three individuals have since been released from the hospital.
The Echo platform had not been producing oil or gas for more than a week to undergo routine maintenance when the incident occurred. No wells were producing at the time.
Fieldwood says the explosion was an isolated pressure event that occurred inside the heater-treater, and not a well explosion or well blowout. The incident was not related to drilling, and no fire occurred.
The incident was contained immediately after it occurred with no damage to the environment, platform, or wells, Fieldwood reports. The US Bureau of Safety and Environmental Enforcement is investigating.
TCS is a Maurice, La.-based industrial cleaning service company specializing in the cleaning of offshore facilities, including the cleaning of heater-treaters, which separate oil from water and other materials.
CNOOC starts oil flow from Pearl River Mouth basin
CNOOC Ltd. started production from the Huizhou 25-8 oil field-Xijiang 24-3 oil field Xijiang 24-1 district joint development project in the South China Sea's Pearl River Mouth basin.
Four wells are producing 6,300 b/d of oil, and the project is expected to reach peak production of 33,000 b/d in 2016. The main production facilities include two drilling and production platforms and 29 producing wells. The project, which lies in 100 m of water, shares a floating production, storage, and offloading vessel.
Xijiang 24-3 oil field started production in November 1994, then-operated by Phillips China Inc. Operatorship of the project transferred to CNOOC in January 2010, and the company currently holds 100% interest.
Petrobras starts production from Santos basin FPSO
Petroleo Brasileiro SA (Petrobras) has launched production from the Cidade de Ilhabelha floating production, storage, and offloading vessel in Sapinhoa field of the Santos basin presalt.
Cidade de Ilhabelha is operating in 2,140 m of water, 310 km off the Brazilian state of Sao Paulo. The FPSO is capable of producing 150,000 b/d and storing 1.6 million bbl of oil, compressing up to 6 million cu m/day of natural gas, and injecting 180,000 b/d of water.
Well 3-SPS-69, the first to go into operation, has a production potential of 32,000 b/d. Oil produced in Sapinhoa averages 29° gravity and will be offloaded by tankers.
The gas not used for reinjection will be transported through the Sapinhoa-Lula-Mexilhao gas pipeline to the Monteiro Lobato gas treatment unit in Caraguatatuba on the coast of Sao Paulo state. Cidade de Ilhabela will be connected to nine production wells and seven injection wells. Peak production is expected in next year's second half.
Petrobras contracted a consortium of QGOG and SBM Offshore in March 2012 to build the FPSO. The hull was converted from a tanker at the CXG shipyard in China, while the integration of the process plant modules took place at the Brasa Shipyard in Niteroi in Rio de Janeiro state.
Sapinhoa production started in January 2013 by interconnecting well 1-SPS-55 to FPSO Cidade de Sao Paulo, whose production capacity is 120,000 b/d (OGJ Online, May 16, 2014).
Sapinhoa is operated by Petrobras with 45% interest. Remaining interest is held by BG E&P Brasil Ltda. 30% and Repsol Sinopec SA 25%.
Maersk Oil lets contract for Culzean field work
Maersk Oil North Sea UK Ltd. has let a multimillion-pound contract to DNV GL for the Culzean field development project in the UK North Sea.
The scope includes independent competent person verification, independent verification body, pressure equipment directive, and the explosive atmospheres directive ATEX services. The team will be managed from the UK, and DNV GL will use additional resources and expertise from its team in Denmark to deliver the work.
Culzean is a high-pressure, high-temperature field discovered in 2008 on Block 22/25 and appraised between 2009 and 2011 (OGJ Online, Jan. 30, 2009; Mar. 10, 2011). If successfully developed, it could provide about 5% of the UK's total gas consumption by 2020-21, DNV GL says. Production from the project is expected in 2019.
Maersk Oil and co-venturers JX Nippon E&P (UK) Ltd. and Britoil (BP) have chosen a new standalone facility to develop the discovery, a complex of bridge linked platforms comprising a 12 slot wellhead platform, a central processing facility, and utilities-living quarters. Two front-end engineering and design contracts were let earlier this year (OGJ Online, May 29, 2014; Aug. 12, 2014).
Subject to a final investment decision in 2015, a phased installation of the facilities would begin in 2016.
PROCESSING — Quick Takes
MRPL wraps Mangalore refinery expansion project
Oil & Natural Gas Corp. unit Mangalore Refinery & Petrochemicals Ltd. (MRPL) has completed the long-delayed Phase 3 expansion and upgrading project at its 194,000-b/d refinery at Mangalore, India (OGJ Online, June 8, 2010).
By the close of the second quarter of financial year 2014-15, MRPL had entered all new installations involved in the expansion into operation, the company said in its latest quarterly earnings report.
The most recent units to enter service include the third train of a three-train sulfur recovery unit, a raw water treatment system, LPG mounded bullet storage tanks, and other facilities.
Additionally, a captive power plant (CPP) built at the refinery site as part of the Phase 3 project is operating but remains under stabilization, the company said.
Earlier in the year, MRPL confirmed start-up of other units in the Phase 3 expansion, including a 2.2 million-tonne/year 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), and a 3 million-tpy delayed coking unit (OGJ Online, Apr. 4, 2014).
MRPL also said an integrated 440,000-tpy polypropylene unit that will use LPG, light distillates, and propylene produced by the refinery's FCC as feedstock is now 97% mechanically completed and will be commissioned during the third quarter of financial year 2014-15.
Announced in February 2010, the Phase 3 expansion project was designed to increase the refinery's complexity and profitability by increasing refining capacity to 300,000 b/d as well as equip the plant to process lower-cost heavy, sour, and high-TAN crudes, MRPL said.
Petronas to buy out Phillips 66's interest in MRC
Petronas has reached a deal with a subsidiary of Phillips 66 to acquire full ownership of Malaysian Refining Co. Sdn. Bhd. (MRC), which operates of one of two refining trains included in Petronas' 200,000-b/d refinery complex in Sungai Udang, Melaka state, Malaysia.
Petronas, which already owns 53% of MRC, will pay Phillips 66 Asia Ltd. $635 million in cash, plus an adjustment upon the sale's completion, for its 47% stake in refinery, Petronas said.
The full acquisition of MRC is intended to enable Petronas to realize greater synergy between its Melaka refining operations as well as strengthen its presence in the company's refining and trading ventures, said Datuk Wan Zulkiflee Wan Ariffin, Petronas's chief operating officer and chief executive officer of downstream business.
Alternatively, Phillips 66's divestiture of MRC will allow the company to redeploy resources to more strategic areas of its business, Phillips 66 said. Petronas said it expects to complete the deal on Dec. 31.
The company's Melaka refinery complex houses two refining trains, PSR-1 and PSR-2. The first train, PSR-1, is owned and operated by subsidiary Petronas Penapisan (Melaka) Sdn. Bhd. and has a capacity to process 100,000-b/d sweet crude and condensates, according to Petronas' web site. The MRC venture owns and operates the second train, PSR-2, which has a capacity to process 100,000-b/d of sweet and sour crudes.
Chevron lets contract for Cape Town refinery
Chevron South Africa (Pty.) Ltd. let a contract to a division of Jacobs Engineering Group Inc. to supply engineering, procurement, and construction management (EPCM) services at its 110,000-b/d refinery in Cape Town, South Africa.
Under the multiyear contract, which replaces a previous agreement signed in 2004, Jacobs Engineering will continue to provide personnel as well as EPCM services to the Cape Town refinery to support Chevron's long-term capital project performance improvement plan for the plant, the company said.
Jacobs Matasis (Pty.) Ltd., a subsidiary jointly owned with Matasis Investment Holdings (Pty.) Ltd. and based in Cape Town, will be responsible for executing the EPCM services portion of the agreement, Jacobs Engineering said.
TRANSPORTATION — Quick Takes
Navitas to build Eaglebine gas pipeline
Navitas Midstream Partners LLC, The Woodlands, Tex., will build the La Bahia gas gathering system, including a 20-in. OD pipeline extending from the northern end of the Eagle Ford shale (Eaglebine) in Brazos County, Tex., to a 120-MMcfd cryogenic processing plant being built in Grimes County, Tex. Navitas expects the plant to enter service in mid-2015.
A long-term, fee-based agreement with an independent producer underpins the projects.
Navitas received a $500-million line-of-equity investment earlier this year from an affiliate of Warburg Pincus, New York (OGJ Online, June 5, 2014).
Energy Transfer Partners LP, Dallas, earlier this month announced plans for its 70-mile, 24-in. OD Volunteer Pipeline from an interconnection with its Southeast Texas gathering system in Brazos County to an East Texas gas processing plant it's building (OGJ Online, Nov. 6, 2014).
Hiland launches open season for Double H system
Hiland Crude LLC has launched an open season to solicit shipper commitments to expanded capacity of the company's Double H crude oil transportation system, a 488-mile pipeline under construction.
An initial open season was held in 2012 for the base capacity. The facilities include the Hiland pipeline that originates in the Bakken oil production areas near Dore, ND, and Sydney, Mont., and terminates at Hiland's tankage near Guernsey, Wyo.
Hiland would deliver oil into connecting pipelines near Guernsey. Interconnections near Guernsey will include the Tallgrass Pony Express pipeline and other interconnections.
Initial start-up service on Double H pipeline will begin in late December and monthly nominations will be accepted for the month of January. The expansion will take place in phases with up to 45,000 b/d of interim capacity expected to be made available in first-half 2015.
Full capacity expansion including the installation of additional pump facilities and pipe expansions is expected to be completed by yearend 2016. Hiland says the expansion project is not reliant on any particular volume of new committed barrels. Final expansion design will be engineered based on the commitments received.
