GENERAL INTEREST — Quick Takes
EIM, AEP partner for unconventional work in Mexico
EIM Capital, a private equity fund in Mexico City, announced a long-term partnership with an affiliate of American Energy Partners LP (AEP) of Oklahoma City to explore for unconventional resources in Mexico although financial terms were not disclosed.
The US Energy Information Administration reported in January 2014 that Mexico ranked eighth in the world in terms of oil and condensate technically recoverable from shale, estimated at 13.1 billion bbl.
Regarding natural gas, EIA reported Mexico holds 545 tcf of technically recoverable shale resources (UOGR, March-April 2014). Energy reform in Mexico has opened its oil and gas resources to outside exploration and production companies and outside investors.
The greatest unconventional potential exists in the part of the Eagle Ford shale that extends into Mexico's Burgos basin from South Texas.
EIM Capital is led by Chief Executive Officer Franco C. Hamdan and former Mexican President Vicente Fox. AEP is led by Aubrey K. McClendon, former Chesapeake Energy Corp. cofounder and chief executive officer.
AEP and EIM Capital agreed AEP will invest in EIM Capital to jointly pursue investments in Mexico's energy industry and explore unconventional oil and gas development. No specifics were outlined.
Hamdan, EIM Capital founder and chief executive officer, said, "Mexico's proximity to the US market's established infrastructure, service providers, and operators could help quickly scale the nascent Mexican shale industry and, with the right conditions, Mexico could rapidly emerge as a global leader in energy production."
AEP Chairman and CEO McClendon said, "EIM's knowledge of and investments in Mexican infrastructure coupled with [AEP's] knowledge of and operation within the unconventional energy industry will produce unparalleled opportunities."
Wood calls for further UKCS incentives
The architect of a UK strategy to boost offshore oil and gas work has called on the government and industry to apply "clever thinking to incentivize investment."
Calling crude prices below $50/bbl unsustainable, retired Wood Group Chairman Ian Wood told the BBC the industry "is right now facing as tough a time as it has ever faced."
Wood led a committee that in 2013-14 developed recommendations for taxation and regulatory changes to help the country achieve what it called maximum economic recovery from the mature UK Continental Shelf oil and gas resource. The government has implemented many of the recommendations (OGJ Online, Feb. 25, 2015).
In his Aug. 28 remarks to the BBC, Wood said the government and industry should continue seeking tax changes to encourage development. "Otherwise, we will not be in a position to take advantage of the upturn," he said.
E&P startup buys Permian assets from W&T Offshore
Ajax Resources LLC, a newly formed exploration and production company backed by private equity firm Kelso & Co., has agreed to acquire all interest in Yellow Rose field belonging to Houston-based W&T Offshore Inc. for $376 million.
W&T also reserved a 1-4% sliding scale overriding royalty interest in the field. The deal is effective Jan. 1 and expected to close during the third quarter.
W&T's interest in Yellow Rose field includes 25,800 net acres in Andrews, Martin, Gaines, and Dawson counties in West Texas. Net production from the field in July averaged 3,000 boe/d.
Ajax believes that significant resource potential exists in the assets-which the company was formed to acquire-through multiple stacked pay horizontal drilling zones, and the company will benefit from extensive well control with more than 200 vertical and horizontal wells drilled and producing across the property.
Ajax will be led by Chief Executive Officer Harvey Klingensmith, who has more than 40 years of operating experience in the oil and gas industry.
For W&T, the move represents an opportunity to increase its focus on offshore E&P. Earlier this year the company reported a discovery at Ewing Banks Block 910 and the start of production from the Medusa SS No. 6 well on Mississippi Canyon Block 538, both in the deepwater Gulf of Mexico (OGJ Online, May 28, 2015).
"This sale will allow us to strengthen our balance sheet and improve our financial flexibility to pursue the acquisition of Gulf of Mexico assets while valuations are favorable," explained Tracy W. Krohn, W&T chairman and chief executive officer. "We believe that current conditions are good for W&T to identify quality offshore producing assets that offer upside exploration and development opportunity."
Total to sell retail network in Turkey
Total SA has agreed to sell its service-station network and commercial sales, supply, and logistics properties in Turkey to Turkish conglomerate Demiroren Holding for about $356 million.
The French company will retain its lubricant and odorless LPG operations in Turkey.
Exploration & Development — Quick Takes
GeoPark follows Chachalaca success with Jacana
GeoPark Ltd.'s Jacana 1 exploration well flowed 1,880 b/d of 14.9° gravity oil with a water cut of 1.9%, the company said. This discovery follows the company's previously success with the Chachalaca 1 (OGJ Online, Aug. 28, 2015).
Jacana field lies southwest of large Tigana oil field on Llanos 34 Block offshore Colombia. Jacana 1 was drilled to a total depth of 10,900 ft. The zone of interest is at 10,200 ft, which includes the Guadalupe and Mirador formations. According to GeoPark, Jacana field follows the same fault trend as Tigana, and appears to be combination structural-stratigraphic trap.
The company expects to gather further production history to determine stabilized flow rates and the extent of Jacana field. As previously reported, GeoPark continues drilling operation on appraisal well Tilo 2. It plans drill a second Jacana appraisal well following completion of Jacana 1. GeoPark holds a 45% interest in Llanos 34 Block.
Tap Oil signs PSC for block offshore Myanmar
Tap Oil Ltd. reported its entry into Myanmar following the signing of the production-sharing contract for shallow-water Block M-7 in the Moattama basin offshore Myanmar. Tap holds 95% participating interest in the block and has assumed operatorship.
Tap Energy (M7) Pte. Ltd. and its local joint venture participant Smart E&P International Co. Ltd. signed the PSC with Myanmar Oil & Gas Enterprise (MOGE) on Aug. 26.
Under the PSC, the JV partners have agreed to undertake an 18-month environmental and social impact assessment and study period followed by an option to proceed to a 3-year commitment exploration work program.
Tap anticipates that it will spend $2.75 million on the block up to and including the study period, which has a minimum expenditure requirement of $2 million. The 13,372-sq km Block M-7 lies 160 km east of the 6.5-tcf Yadana gas field, and 70-km north east of the 1.5-tcf Zawtika gas field.
Buru finds more oil onshore Canning basin
Buru Energy Ltd., Perth, has intersected a gross 23-m column of oil at the top of the Ungani Dolomite formation with its Praslin-1 wildcat drilled in permit EP 391 in the onshore Canning basin of Western Australia.
Well logs indicate the oil-bearing interval is similar to that of the productive zone at the nearby Ungani oil field. However reservoir characteristics still have to be confirmed with a production test program at a later date.
Praslin-1 is about 90 km east of Broome and 15 km west of Buru's producing Ungani field.
The well will be plugged back to the base of the interpreted oil column and a completion string run into the hole. The rig will next move further east to the Victory-1 well, which is also on the Ungani trend. This will be followed by Senagi prospect later in the year.
Operator Buru and Mitsubishi Corp. each have a 50% interest in EP 391.
USGS estimates Cherokee Platform Province reserves
The Cherokee Platform Province in Kansas, Oklahoma, and Missouri contains estimated recoverable reserves totaling 463 million bbl of crude oil, 11.2 tcf of natural gas, and 35 million bbl of natural gas liquids, the US Geological Survey said in a Sept. 1 report.
USGS said the assessment was part of its National and Global Petroleum Assessment Project.
Drilling & Production — Quick Takes
Surmont 2 oil sands production launches from Alberta
Operator ConocoPhillips and 50-50 partner Total SA have started production from their Surmont 2 in-situ oil sands facility situated 63 km southeast of Fort McMurray in the Athabasca region of Alberta.
ConocoPhillips describes the Surmont 2 facility, construction of which began in 2010 (OGJ Online, Jan. 19, 2010), as "the largest single-phase steam-assisted gravity drainage (SAGD) project ever undertaken."
Since first steam in May (OGJ Online, June 1, 2015), the reservoir has successfully been heated to a point where the well pairs can be converted to a SAGD configuration, allowing the oil to flow. Production was declared once the inspected product was successfully routed to sales tanks, ConocoPhillips says.
Production will ramp-up through 2017, adding 118,000 bo/d. Total gross capacity for Surmont 1 and 2 is expected to reach 150,000 bo/d. Surmont 1 started commercial production in 2007 (OGJ Online, Dec. 11, 2007).
Malampaya compression platform installed
Installation of a depletion compression platform near deepwater Malampaya gas and condensate field offshore the Philippines is complete, reports Arup, which provided engineering support services for the fabrication and installation of the self-installing substructure (OGJ Online, Apr. 30, 2012).
The new, 13,000-ton platform is part of the third phase of Malampaya development by Shell Philippines Exploration BV and partners Chevron Corp. and state-owned PNOC Exploration Corp.
The platform was set in place in less than 24 hr during February with an in-built jacking system. Since then the facility has been connected via a 43-m bridge link to the existing concrete gravity substructure processing platform.
The platforms and a catenary anchor-leg mooring buoy for condensate are in shallow water about 30 km from the field, where wells are completed subsea in 820 m of water in the West Philippine Sea off Palawan.
The Malampaya and Camago reservoirs produce about 380 MMscfd of natural gas and 15,000 b/d of condensate. From the platform, dry gas flows through a 504-km, 24-in. OD pipeline to a plant on Luzon south of Manila for further processing and ultimate delivery to electric power plants.
Shell Philippines completed the second phase of Malampaya development in 2013 with the addition of two production wells.
UK approves $4.5-billion Culzean development
The UK Oil & Gas Authority has greenlighted development of high-pressure, high-temperature (HPHT) Culzean field in the central North Sea.
Operator Maersk Oil and coventurers JX Nippon and BP PLC are investing $4.5 billion in the development, which Maersk notes "has benefited from the HPHT Cluster Area Allowance introduced by the UK government as part of the 2015 budget."
The allowance supports the development of HPHT projects-which tend to have considerably higher capital costs-and encourages exploration and appraisal activity in the surrounding area, or "cluster," Maersk says.
The gas-condensate field, discovered in 2008 (OGJ Online, Jan. 30, 2009), has resources estimated at 250-300 million boe. Production is expected to start in 2019 and continue for at least 13 years, plateauing at 60,000-90,000 boe/d.
The partners will develop Culzean with a standalone facility, which will be a complex of bridge-linked platforms comprising a 12-slot wellhead platform, a central processing facility, and utilities-living quarters (OGJ Online, Nov. 20, 2014). Two front-end engineering and design contracts were let in 2014.
Maersk recently let a contract to Tenaris for casing and related services for the project (OGJ Online, Aug. 25, 2015). Separately, Maersk Oil let a $1 billion engineering, procurement, and construction contract to Sembcorp Marine subsidiary SMOE Pte. Ltd., Singapore, for topsides for the project The contract includes construction of the central processing facility and two connecting bridges, wellhead platform, and utilities and living quarters platform topsides.
PROCESSING — Quick Takes
CHS takes full ownership of Kansas refinery
US farmer-owned cooperative CHS Inc., Inver Grove Heights, Minn., has completed its purchase of National Cooperative Refinery Association's refinery and related operations at McPherson, Kan., to take full ownership of the assets (OGJ Online, Dec. 1, 2011).
Conclusion of the deal follows a 2011 agreement with then-minority owners Growmark Inc., Bloomington, Ill., and MFA Oil Co., Columbia, Mo., to buy additional interest in the McPherson refinery in four annual increments starting on Sept. 1, 2012, and culminating on Sept. 1, 2015, CHS said.
CHS's current investments in infrastructure and pipelines at the 85,000-b/d refinery, now renamed the CHS Refinery at McPherson, are due to boost crude processing capacity at the Kansas plant to 100,000 b/d in 2016, the cooperative said.
CHS began the $330-million McPherson expansion, which was designed to be completed in phases during this year's second half and early 2016, in 2013 (OGJ Online, Mar. 12, 2013).
The expansion project is under way alongside a separate project to construct a $555-million replacement coker at the refinery (OGJ, Dec. 3, 2012, p. 100).
The cooperative incurred $186.8 million in costs related to the coker project during fiscal-year 2014 and $121.3 million during the 9 months ended May 31, CHS said in its latest quarterly earnings report to investors.
Capital expenditures related to the refinery's expansion amounted to $128.3 million for fiscal year 2014 and $105.1 million for the 9 months ended May 31.
South Africa's Engen wraps refinery turnaround
Engen Petroleum Ltd. has restarted its 125,000-b/d Enref refinery in Durban, South Africa, following a 4-week period of planned maintenance activities (OGJ Online, July 6, 2015).
The 30-day scheduled turnaround, which comes as part of the refinery's ongoing maintenance program to ensure safe and reliable operations, was completed at a cost of more than 150 million rand, the company said.
As a result of the maintenance work, the refinery currently is operating at 99.8% of its full capacity, according to John Naidoo, Engen's maintenance manager.
Turnaround activities included testing of all safety and protection equipment and systems, as well as routine maintenance and services on critical equipment as recommended by the original equipment manufacturer, Naidoo said.
The company, which previously warned of potential supply disruptions during the shutdown period, did not disclose details regarding impacts to supply commitments as a result of the planned outage.
The Enref refinery, South Africa's second largest, produces automotive, industrial, aviation, and marine fuels, as well as bitumen, lubricants, and a range of chemicals and solvents.
PDVSA restarts FCCU at Amuay refinery
Petroleos de Venezuela SA (PDVSA) has restarted the fluid catalytic cracking unit (FCCU) at its 645,000-b/d Amuay refinery in northwestern Venezuela's Falcon state following the unit's unplanned shutdown in early July.
Corrective maintenance on the 166,500-b/d FCCU has been completed, with the unit reentering operations as of Aug. 25, PDVSA said.
Repairs to the unit previously were scheduled to wrap on or about July 28, the state-run company said previously (OGJ Online, July 20, 2015).
PDVSA shuttered the unit on July 1 following unidentified problems with its regenerator and associated minor equipment.
Remaining processing units at the Amuay refinery as well as at the nearby 310,000-b/d Cardon refinery-which together comprise PDVSA's 955,000-b/d Paraguana Refining Center continued to operate normally during the unplanned maintenance period.
Despite the unit's extended outage, the company said it maintains sufficient fuel inventories to meet both its domestic and international supply commitments.
TRANSPORTATION — Quick Takes
PHMSA will award $54.1 million in safety grants
The US Pipeline and Hazardous Materials Safety Administration plans to award nearly $54.1 million in grants to support pipeline safety programs in 46 states, the District of Columbia, and Puerto Rico, the US Department of Transportation agency reported.
"These grants ensure state programs have the funding they need for resources, including personnel and equipment, to protect communities, carry out inspections, and enforce safety regulations that keep the entire pipeline network as safe as possible," US Transportation Sec. Anthony Foxx said.
PHMSA Administrator Marie Therese Dominguez announced the grants before an audience of state inspectors and regulators as part of the annual National Association of Pipeline Safety Representatives Board of Directors meeting in Tempe, Ariz., on Sept. 1.
"These grants extend the reach of PHMSA and our State partners into our communities," she said. "[They] allow us to have a strong local presence that is vital to effectively monitor pipelines and help protect the public from pipeline incidents."
PHMSA said the grants provide as much as 80% of operating costs for state pipeline regulatory agencies that agree to inspect intrastate pipelines on the federal agency's behalf.
Participating states and territories account for 330 inspectors who are responsible for more than 80% of the nation's intrastate natural gas and hazardous liquid pipeline mileage, the DOT agency said. More than 2.6 million miles of pipelines transport oil and gas to homes and businesses throughout the country, it noted.
Extension sought for Mackenzie Gas Project
The earliest possible construction start for the Mackenzie Gas Project, which would connect natural gas fields in the Canadian Arctic with northwestern Alberta, is 2022, according to a request by project sponsors for an extension in federal approval.
Canada's National Energy Board approved the project in December 2010 and issued a certificate of public convenience and necessity for the 1,220-km Mackenzie Valley Pipeline the following March (OGJ Online, Mar. 11, 2011). Unless extended, approval expires at the end of this year if construction doesn't begin.
"Due to the current challenging North American natural gas market conditions, a decision to construct the project has not yet been made," lead sponsor Imperial Oil advised in letter to the NEB. The company asked the board to extend the sunset clause to Dec. 31, 2022, "to provide time to determine if the currently oversupplied North American natural gas market will recover sufficiently to warrant a resumption in the project work."
If Imperial and its partners decided to proceed with the project, the letter said, they would need about 4 years for preconstruction work including fiscal framework discussions, detailed engineering, and "extensive" permitting.
"As a result," the letter said, "2022 is expected to be the earliest possible construction start."
The project is based on a 6-tcf gas resource in three Mackenzie Delta fields in Northwest Territories. In addition to the gas pipeline and field developments, work would include construction of a gathering system, gas processing plant, and 457-km natural gas liquids pipeline between Inuvik and Norman Wells.
Cenovus completes purchase of rail terminal
Cenovus Energy Inc. has completed the purchase of a crude-by-rail transloading facility in Bruderheim, Alta., from Canexus Corp. Both companies are based in Calgary.
Originally called North American Terminal Operations, the facility, about 50 km northeast of Edmonton, has been renamed Bruderheim Energy Terminal.
Cenovus began moving oil through the terminal last year and currently transports crude oil from its Foster Creek steam-assisted gravity drainage operation to Bruderheim via the Cold Lake pipeline. The terminal also has connections to the Access crude oil pipeline and links to the Canadian Pacific and Canadian National rail lines.
"The acquisition is part of Cenovus's strategy to build a strong portfolio of transportation options to help maximize market access and capture global prices for its oil," the company said.
