API: Production costs driving gasoline prices
API chief economist John Felmy said gasoline prices are simply driven by the product’s manufacturing costs and that market fundamentals rather than speculation are what drives today’s higher prices.
Pump prices are up from a year ago because refiners are incurring higher costs for oil and ethanol. Higher credit card fees and sales taxes also are contributing to the increased prices at the pump, Felmy said during a conference call with reporters to discuss gasoline prices going into the Memorial Day holiday weekend in the US.
Gasoline demand in the US was up in this year’s first quarter compared with year-earlier levels. In April, however, demand declined 2.2% from April 2010. Urban areas especially experienced a decline in demand in April, Felmy said, adding that it is difficult to determine whether this dip was the result of the sluggish economy or if it was due to higher gasoline prices.
Heater-treater collapse caused Mariner platform fire
The collapse of a fire tube inside the heater-treater on Mariner Energy Inc.’s Vermilion 380-A platform caused a Sept. 2 fire on the platform 102 miles off Louisiana, the US Bureau of Ocean Energy Management, Regulation, and Enforcement said on May 25.
It said its accident investigation panel found that the fire tube on the nearly 30-year-old piece of equipment had been weakened over time from heat, corrosion, pitting, and other factors. The heater-treater used heat from a fire tube as well as chemicals and electricity to separate oily emulsions into oil and water.
Investigators also found that after the platform lost primary power because of the fire, the emergency generator failed to start and supply power to the firewater pump, leaving the 13-member crew without a firewater system to aid them in trying to fight the fire, according to BOEMRE. Ultimately, the crew was forced to evacuate the platform, and all were later transported to safety, it said.
The investigation panel interviewed the platform’s crew, reviewed documentary and physical evidence, examined equipment onboard the platform, and consulted with an oil production platform and heater-treater expert, the US Department of the Interior agency said.
BOEMRE said its investigators recommended that Mariner be issued several incidents of noncompliance, which may be used as the basis of future civil penalties. The agency said it will now consider the panel’s recommendations before taking further action, and that production from the platform remains shut-in until BOEMRE personnel approve all safety and structural corrections.
BOEMRE noted that it has issued a safety alert to oil and gas operators to address the investigation’s findings as a way to inform the offshore industry of circumstances surrounding the accident and offer recommendations that help to prevent such an incident’s recurrence.
BOEMRE, NOAA to coordinate OCS policymaking
The US Bureau of Ocean Energy Management, Regulation, and Enforcement and the National Oceanic and Atmospheric Administration signed a memorandum of understanding to jointly ensure environmentally sound offshore energy development.
The two agencies announced the MOU at the International Oil Spill Conference in Portland, Ore.
BOEMRE Director Michael R. Bromwich said the MOU will stimulate greater efficiency in developing US Outer Continental Shelf energy policy and conservation.
NOAA Administrator Jane Lubchenco said the MOU is consistent with recommendations from US President Barack Obama’s independent oil spill commission.
Apache drops New Brunswick; Corridor proceeds
Corridor Resources Inc., Halifax, received notice that Apache Canada has elected not to proceed with the second phase of the farmout program with Corridor in respect of the potential Frederick Brook shale gas resource development near Elgin, NB.
The two horizontal wells drilled and hydraulically fracture stimulated by Apache, Will DeMille G-59 and Green Road B-41, using similar large slick water techniques, have not generated sustained shale gas production to date. In May, G-59 was reopened and flowed frac fluid at low rates with minor gas shows over 5 days. When the Will DeMille G-59 well was shut-in after initial testing in early December, 2010, it had recovered only 4% of the total frac fluid, Corridor noted.
Corridor previously reported that the B-41 well had been placed on 45-day gas lift that ended on Mar. 16. At that time, the well was shut-in after recovering 17% of the frac fluid. In late May, due to significant well head pressure buildup, the well was reopened and flowed gas at a maximum rate of 700 Mscfd for several hours prior to frac fluids loading the well causing gas rates to decline.
Based on a consensus among third-party expert consultants and Corridor technical staff, the most significant issues identified with the G-59 and B-41 well performance relate to the design of the horizontal wells in this high-stress environment and the fracture technique. Corridor believes that a different well design and frac program will lead to a commercial development of the Frederick Brook shale.
Corridor in December 2010 retested the G-41 well, which produced gas at a constant 4 MMscfd for 5 days at a final flowing pressure of 1,306 psi. During the first quarter of 2011, G-41 was used to provide gas lift and consistently delivered the required rate of 500 Mscfd during a 45 day test at a final pressure of 2,007 psi.
Corridor will drill two vertical appraisal wells in the Elgin area in late 2011 to confirm the well productivity required to proceed with a pilot phase.
Based on the results of these appraisal wells, Corridor plans a staged approach to demonstrate commercial viability that would include a pilot phase with a capacity of 40 MMscfd, targeting gas production in late 2013. This program would include vertical wells in a multiwell pad design to take advantage of the shale thickness and high gas saturations.
During the pilot phase, Corridor will evaluate various drilling and completion techniques. Corridor will provide details on the Frederick Brook shale gas development plans in a corporate presentation to be placed on its web site on June 6.
Corridor also will entertain discussions with potential joint venture partners who wish to engage in a program to develop the Frederick Brook shale and who can add value to the potential development. The information and data obtained to date from Corridor’s and subsequent Apache programs will be of significant value as this program advances.
Corridor noted that evaluation of the Frederick Brook shale gas resource is still in its early stage and that the best estimate of gross discovered resources is 67.3 tscf as estimated by GLJ Petroleum Consultants Ltd. in the GLJ shale resources report, effective June 1, 2009.
Noble adds Santiago find to Galapagos project
A Noble Energy Inc. group estimates a discovered resource of 130 million bbl of oil equivalent at its Galapagos project in the deepwater Gulf of Mexico, including the Santiago prospect where it announced a discovery May 31. About 75% of the discovered resource is oil.
Logs at Santiago, drilled to 18,920 ft in 6,500 ft of water on Mississippi Canyon Block 519, identified 60 ft of oil pay in a high-quality Miocene reservoir, Noble Energy said.
Santiago is the third discovery in the Galapagos project, where it joins Santa Cruz and Isabela. Noble Energy expects all three wells to be on production in early 2012. The company increased expected net production to Noble Energy from Galapagos to more than 10,000 b/d of oil.
Charles D. Davidson, Noble Energy’s chairman and chief executive officer, said, “The discovery at Santiago is a great way to resume our drilling program in the deepwater Gulf of Mexico. The well results were very consistent with our predrill expectations, and our teams did an outstanding job in the midst of a changing operating environment.”
Noble Energy in late February received industry’s first drilling permit after the deepwater gulf moratorium for Santiago, where drilling was suspended in June 2010. Drilling resumed in early April 2011 after multiple reviews of operating and response plans and third-party certifications of well designs and equipment.
The company is starting completion at Santiago using the Ensco 8501 semisubmersible. Completion is expected to take 2 months, after which the company plans to return to drilling the Deep Blue prospect at Green Canyon 723. Following Deep Blue, Noble Energy will spud an appraisal well at the Gunflint discovery at Mississippi Canyon 948.
Noble Energy operates Santiago with a 23.25% working interest. Other interest owners are Houston Energy LP with 10%, Red Willow Offshore LLC 20.25%, and BP Exploration & Production Inc., a subsidiary of BP America Inc., 46.5%.
Santos starting Bangladesh exploration program
Santos Ltd. said it plans to spend more than $100 million (Aus.) on a three-well exploration drilling campaign off Bangladesh that it expects to start later this year.
The wells will be drilled on the Block 16 production sharing contract in the Bay of Bengal. Santos operates the block under the supervision of Petrobangla.
Santos says its commitment to the drilling program stems from a recent decision by the Bangladesh government to allow new gas from Block 16 to be sold at directly negotiated prices. Existing production from Block 16 comes from Sangu gas field.
The three wells will target new reservoirs of gas not intersected by the Sangu field development. One of the wells (Sangu-11) will be drilled from the Sangu platform.
The other two wells will target prospects about 5 km from Sangu platform. The company said a fourth exploration well might be drilled on the Magnama prospect.
Drilling & Production — Quick TakesCNRL ramps up Pelican Lake oil production
Canadian Natural Resources Ltd. said it began ramping up production from Pelican Lake oil field in northern Alberta on May 24.
The 40,000 b/d field had been shut in for about 5 days because of the shutdown caused by forest fires near Slave Lake of the Plains Midstream Rainbow pipeline that transports Pelican Lake oil to Edmonton.
CNRL expects to reach Pelican Lake preshutdown production rates in the next few days.
The company also has resumed 60% of the 3,100 bo/d and 8 MMcfd production capacity from its properties in the Slave Lake area of north-central Alberta. It said that it will restore the remaining production capacity as the electric power infrastructure is confirmed safe and capable of load.
No facilities were damaged by the forest fires, CNRL noted.
CNRL revises Horizon upgrader restart plan
Because of delays caused by the forest fires in northern Alberta, Canadian Natural Resources Ltd. has revised its plans for restarting the Horizon oil sands upgrader that was damaged in a fire on Jan. 6 (OGJ Online, Feb. 21, 2011).
CNRL had plans to mobilize workers back to the upgrader site on June 4 and targets the commissioning of all four coke drums during the first 2-3 weeks in August.
CNRL said the revised plan will accelerate the completion of Coke Drums 1A and 1B and result in obtaining full 110,000 b/d of synthetic crude production capacity earlier than previously planned.
The company noted that the facilities are not in danger from the forest fires but workers have been evacuated from the site since May 16 because of smoke from the fires.
The estimated upgrader fire repair-rebuild costs, including associated damage, remain at $350-450 million, the company said.
The company added that it maintains an insurance program that should adequately cover repair-rebuild costs. It also has business interruption insurance to alleviate a portion of ongoing operating costs.
Rowan orders drillships for 12,000 ft of water
A subsidiary of Rowan Cos. Inc. entered into turnkey contracts with Hyundai Heavy Industries Co. Ltd. for the construction of two ultradeepwater drillships at a cost of $605 million each.
HHI will build the drillships at its Ulsan, South Korea, shipyard. Rowan expects delivery of the drillships in late 2013 and mid-2014.
Rowan said the construction cost includes commissioning, project management, owner-furnished equipment, spares, and rig inventory, but excludes capitalized interest. The agreement with HHI also includes an option for an additional drillship of the same specification, exercisable in this year’s third quarter, for delivery in the last quarter of 2014.
The drillships will have a GustoMSC P10,000 design and will be capable of drilling to 40,000 ft in as much as 12,000 ft of water.
Other features of the drillship include:
• DP-3 compliant and dynamic positioning with retractable thrusters, dual-activity capability, five mud pumps, dual mud systems, and a maximum 1,250-ton hook-load capacity.
• Seven-ram blowout preventer stack incorporating full acoustic backup control and storage and handling facilities for a second BOP that will minimize well and between well nonproductive time.
• Hull integration with below-deck riser storage, 4 million lb riser tensioning, main load path active-heave drawworks with crown-mounted compensation, three 100-ton knuckle boom cranes, an active-heave 165-ton crane for simultaneous deployment of subsea equipment, a 20,000-ton variable deck load capacity, and accommodations for 210 personnel.
Rowan said the $605 million construction cost is based on a 12,000-ft water depth capable rig equipped with 10,000 ft of riser in order to enable a comparison to previous newbuild drillship announcements by other companies. But it intends to equip these rigs with 2,000 ft of additional riser so that they can drill in up to 12,000 ft of water.
The company said it also will incur costs of about $50 million/drillship for the additional equipment mentioned previously and for operational training and personnel ramp-up.
PROCESSING — Quick TakesRefinery blast ‘due to sanctions, government pressure’
An explosion and fire that killed at least two people and injured 22 at Iran’s Abadan refinery came after government pressure to promote the project in the face of international sanctions against the country, according to local media reports.
Tehran’s Arman newspaper, citing unnamed officials, said the explosion and fire was at one of the refinery’s two main compressors. It said the system, used to liquefy gas, was not ready to be operated.
The newspaper quoted an official of the National Iranian Oil Refining and Distribution Co. as saying the compressors were purchased from Munich-based Siemens AG, but that the firm—citing international sanctions—had declined to send experts to operate the machinery. Without those experts, Arman reported, Iranian personnel were in charge of operating the compressors and were under pressure to proceed despite concerns about an accident.
The explosion and fire happened during the inauguration ceremony for the new wing at the refinery, an event intended by Iran’s President Mahmoud Ahmadinejad to underscore his country’s self-sufficiency in producing gasoline.
Ahmadinejad survived the blast and fire, but he was roundly criticized by parliamentarians for putting political purposes ahead of safety in launching the facility.
“This incident was not an act of intentional sabotage,” said Hamid-Reza Katouzian, head of Iran’s parliamentary energy committee. “Experts had forewarned that Abadan refinery was not ready to be inaugurated” (OGJ Online, May 24, 2011).
Iraq’s Baiji refinery due control upgrade
North Refineries Co. of Iraq named Honeywell the main engineering, procurement, and construction contractor for an upgrade of automation systems at its 310,000-b/d hydroskimming and hydrocracking refinery in Baiji.
Honeywell will fully automate the refinery, replacing a 30-year-old single-loop instrument control system. The contractor said the project, in addition to improving productivity, will offer “full scalability to support future technology upgrades.”
Built in 1982, the Baiji refinery has these processing capacities: catalytic reforming 46,000 b/d, catalytic hydrocracking 38,000 b/d, and catalytic hydrotreating 182,000 b/d.
It has design capacity to produce 64 MMcfd of hydrogen, 5,000 b/d of lube oils, and 26,000 b/d of asphalt.
Tornado idles Devon’s Cana gas plant
Devon Energy Corp. expects its new 200 MMcfd gas processing plant near Calumet, Okla., to be idle for up to 3 months for repairs to damage described as “significant” from a May 24 tornado.
The company continues to produce 100 MMcfd of natural gas and 5,000 b/d of natural gas liquids from Cana field, a development of the Cana-Woodford shale.
Devon brought the plant online last year with capacity expandable to 600 MMcfd (OGJ, Nov. 8, 2010, Newsletter).
TRANSPORTATION — Quick TakesPemex awards Campeche installation contract
Pemex EP let a contract to McDermott International Inc. for the procurement, construction, and installation of three oil and gas pipelines of between 8 and 20 in. OD in Mexico’s Bay of Campeche.
McDermott expects to begin pipeline installation engineering in this year’s second quarter, with subsequent fabrication of the risers, clamps and guards, subsea tie-in assembly, and additional platform piping and structural items at McDermott’s Altamira fabrication facility in Altamira, Mexico. McDermott’s DB16 will perform the installation, with completion expected by yearend.
The pipelines will extend in roughly 170 ft of water from the Kambesah Wells Recoverer Structure to the Kutz TA platform and the Ixtoc-A platform.
The more than $50 million contract will be included in McDermott’s second-quarter backlog.
Forest City basin gas lines due reactivation
Sefton Resources PLC has acquired two gas pipelines in the Forest City basin in northeast Kansas and plans to restore them to service.
Sefton’s TEG Mid-Continent Inc. subsidiary owns pipelines, coalbed methane leases, and gas processing facilities in Anderson, Franklin, and Leavenworth counties, Kan.
In East Kansas, Sefton has 45,000 acres in the Forest City basin. The company operates its leasehold with 100% working interest.
The 28-mile Vanguard pipeline, acquired in 2009, was seen as providing a gathering system for the company’s future drilling and also would establish a basis for potential joint ventures in both exploration and gas gathering and transportation.
By December 2010, the company gained control of a second pipeline consisting of 25 miles of various diameter pipe in Leavenworth County 2 miles east and north of the Vanguard pipeline. Once connected and activated, the two lines will provide 8-10 MMcfd of capacity and access to an interstate pipeline for Sefton-produced and third-party gas.
By January, all the valve systems were installed on the Vanguard pipeline. Sefton signed a letter of intent for a gas transportation and marketing agreement and a capacity and transportation agreement with a potential partner on the Vanguard system.
Sefton was working to establish an interconnection with Southern Star Pipeline’s interstate pipeline system and is looking at other interconnect options.
Sefton acquired leases, wellbores, equipment, and technical data close to the LAGGS pipeline. A $200,000 agreement was signed in March for 18 wellbores and associated technical data along the LAGGS pipeline. Assets valued at $108,861 have been cleared, and the rest need further due diligence.
In a separate deal, a computerized data base of proprietary well data and shallow gas prospects in the Leavenworth area, print maps, cross-sections, and a proprietary report detailing all prospects, geology and engineering in the LAGGS pipeline area has been acquired.
By early April, evaluation of segments of the LAGGS pipeline system were completed and tested.
Strategically, the LAGGS pipeline, the most critical segment of the system, will see the first gas volumes in 2011 and provide initial revenue to the company, Sefton said.
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