OGJ Newsletter

Aug. 12, 2013
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

FERC proposes fine for BP over 2008 gas trading

The US Federal Energy Regulatory Commission ordered four BP North American subsidiaries to show cause why they should not pay a $28 million fine for allegedly trying to manipulate the Houston Ship Channel-Katy Hub natural gas price spread in 2008. BP immediately disputed the Aug. 5 order, and said it would fight the allegations.

The order also would require BP to disgorge $800,000 plus interest, or a modification of those amounts if warranted. FERC gave the company 30 days to formally respond.

An attached Enforcement Office staff report alleged that three traders on the "Texas team" of BP's Southeast gas trading desk tried to perpetuate a wide spread between HSC and Katy Hub prices which had developed in the wake of Hurricane Ike in late summer 2008. The alleged scheme, which began Sept. 18, was extended through October and into November, the report said.

BP stands by its February 2011 statement that its gas traders did not try to manipulate markets in late 2008, Geoff Morrell, vice-president and head of US communications, said in an Aug. 5 statement. FERC based its allegations on a 2-min telephone call between a BP trainee and gas trader that FERC has taken out of context, he noted.

"The recording does not support any allegation of wrongdoing," Morrell said. "In fact, the trainee involved in the conversation states that his characterization was incorrect and the trader never agrees with nor condones the trainee's statements. The trader also reacts strongly to the trainee's comments and interrupts him because the trainee's comments—as the trainee admits on the call—are incorrect and inappropriate."

The trader also promptly reported the conversation and BP's compliance personnel acted appropriately in examining the trading at issue, Morrell added.

Crews drilling relief well in Gulf of Mexico

At presstime last week, crews were under way with the drilling of a relief well to secure natural gas Well A-23 on South Timbalier Block 220 off Louisiana, the US Bureau of Safety and Environmental Enforcement said, adding that drilling, which started on Aug. 4, is expected to take about 35 days.

Operator Walter Oil & Gas Corp. hired the Rowan EXL-3 jack up rig to drill the relief well to Well A-23, which is in 154 ft of water about 55 miles offshore.

Walter experienced a loss of control of Well A-23 July 23 on an unmanned platform during completion work on a sidetrack well. Hercules Offshore safely evacuated 44 workers from the Hercules 265 jack up rig before leaking natural gas ignited on the rig hours later (OGJ Online, July 24, 2013).

On July 25, BSEE confirmed the gas flow subsided after a natural bridging process, and the fire was suppressed.

BSEE noted Aug. 5 that many factors can affect the relief well drilling schedule, including weather and the process of locating the target wellbore at the end of the relief well drilling. Once Well A23-A is intercepted, crews will pump drilling mud and then cement into it.

Walter planned to submit its plans for well-intervention work to BSEE for review and approval. Federal regulators previously approved plans to drill the relief well.

From visual observation, BSEE said a sheen was no longer present in the area of the well. The US Coast Guard continues to maintain a 500-m safety zone around the site.

Firefighting and other marine vessels remain onsite with workers from Walter, Hercules, and other engineering contractors.

BSEE and USCG are overseeing the response efforts. BSEE is investigating the cause of the loss of well control.

Proved reserves of oil, gas make record gains

Oil and gas exploration and production companies operating in the US added nearly 3.8 billion bbl in proved reserves of crude oil and lease condensate in 2011, according to a recent report released by the US Energy Information Administration. EIA reported that US proved reserves at yearend 2011 totaled 29 billion bbl, up 15% year-on-year and the greatest volume increase since EIA began publishing proved reserves estimates in 1977.

Proved reserves of US wet natural gas, meanwhile, increased to 348.8 tcf at yearend 2011 from 317.6 tcf at yearend 2010. EIA said, "Though this increase was lower than the 33.8 tcf added in 2010, it was only the second year since 1977 that natural gas net reserves additions surpassed 30 tcf."

EIA noted that proved reserves of crude oil and lease condensate increased in 2011 in each of the five largest crude oil and lease condensate areas, namely Texas, the Gulf of Mexico federal offshore, Alaska, California, and North Dakota.

Texas has the largest increase, up by 1.8 billion bbl, mostly from continuing development in the Permian and Western gulf basins. North Dakota had the second-largest increase, up by 771 million bbl, driven by development activity in the Williston basin. North Dakota and Texas combined accounted for two thirds of the net increase in total US proved oil reserves in 2011, EIA said.

Proved wet natural gas reserves increased in 2011 in each of the five largest gas producing states: Texas, Wyoming, Louisiana, Oklahoma, and Pennsylvania, EIA said. Texas and Pennsylvania accounted for a combined 73% net increase in proved wet natural gas reserves in 2011. Proved reserves in shale gas plays accounted for 38%, or 131.6 tcf, of total proved reserves in 2011.

Ultra taps gas, condensate in Wyoming

Ultra Petroleum Corp., Houston, said it produced 56.6 bcf of natural gas and 299,100 bbl of condensate in Wyoming and Pennsylvania in the quarter ended June 30.

Net production from Wyoming averaged 456 MMcfd of gas equivalent in the quarter, during which Ultra and its partners placed on production 36 gross wells with initial production that averaged 7.2 MMcfed.

Ultra averaged a record 9.6 days from spud to total depth in the quarter with 60% of all operated wells being drilled in less than 10 days. The average for all wells was 12.2 days.

Ultra initiated production from 7 gross wells in Pennsylvanian, where initial producing rates in its Marcellus program averaged 6.4 MMcfed for the new wells placed online during the quarter. Second quarter Pennsylvania net production averaged 186 MMcfed.

The company has 900 sq miles of 3D seismic across two thirds of its 260,000 net acres and is acquiring a further 35 sq miles over its operated acreage position. Ultra expects the additional 3D will further delineate Marcellus sweet spots and expand understanding of the Geneseo formation.

Exploration & DevelopmentQuick Takes

Chevron Canada adds to Duvernay land position

Chevron Canada Ltd. will boost its exploratory lease position in the Duvernay shale formation in Alberto to more than 250,000 acres by acquiring 67,900 net acres from Alta Energy Luxembourg SARL and affiliates for an undisclosed sum.

Chevron Canada in the second half of 2011 launched a multiwell exploratory program for unconventional resources in the Duvernay wet gas play. Initial production was achieved in 2012 on these 100%-owned and operated leases.

Jeff Lehrmann, Chevron Canada president, said, "To date, we have been encouraged by the reservoir data and production performance from our exploration drilling program on our Kaybob Duvernay leases. We are pleased to add to our acreage in this play as we advance our program to evaluate the potential for full-field commercial development."

Gazprom, Total to explore Subandean block

Gazprom of Russia and Total of France will explore the large Azero block in Bolivia's Subandean territory between Sucre and Santa Cruz, according to announcement on the web site of state oil and gas entity Yacimientos Petroliferos Fiscales Bolivianos.

YPFB said the two companies would invest $130 million to explore the block, which covers more than 700,000 acres in Chuquisaca and Santa Cruz departments.

It said the companies have committed to collect geophysical surveys and drill two exploratory wells. YPFB would back in for a 55% interest if a discovery were made.

Subsidiaries of the former Texaco and Sun Oil held exploration rights to Azero several decades ago.

Horizontal wells drilling at Galoc oil field

A unit of Otto Energy Ltd., Perth, heads a group that is drilling two horizontal wells in a second development phase at Galoc oil field offshore the Philippines.

The company expects the Galoc-5H and 6H wells, being batch-drilled in 311 m of water each with a planned 2,000-m lateral, to begin producing in the fourth quarter to the Rubicon Intrepid floating production, storage, and offloading vessel.

Each well is to have 5,000 m of total drilled footage with a horizontal section at 2,190 m true vertical depth in the reservoir, a turbiditic sandstone in the Miocene Galoc formation in the Palawan basin.

Galoc field, on Service Contract SC14C 65 km northwest of Palawan Island and 350 km south of Manila, has produced more than 10 million bbl since being commissioned in 2008. Output had fallen to 4,556 b/d in the quarter ended June 30, down 4.6% from the prior quarter.

Drilling & ProductionQuick Takes

AER: Primrose release totals 6,670 bbl

The amount of bitumen released to surface from four locations at Canadian Natural Resources Ltd.'s Primrose South and East thermal projects totaled 6,670 bbl as of Aug. 2, Alberta Energy Regulator (AER) reported (OGJ Online, July 18, 2013).

AER last month ordered CNRL to restrict steam injection in the cyclic steam stimulation project areas about 55 km north of Bonnyville in the Cold Lake region of Alberta.

It said the releases had affected 20.7 hectares of land.

"We do not currently have the evidence or data to support any conclusions as to the cause of the incident and look forward to reviewing CNRL's information supporting their conclusions on the root cause of the releases," AER Chief Executive Officer Jim Ellis said in a press statement.

On July 31, CNRL said the rate of release had declined to below 20 b/d of bitumen emulsion. Clean-up had cut the area of focus to 13.5 hectares, it said.

"Canadian Natural believes the cause of the bitumen emulsion seepage is mechanical failures of wellbores in the vicinity of the impacted locations," the company said.

It said it has begun production in some Primrose areas where steaming would have continued if the releases hadn't occurred.

"The company is of the view that reserves recovered from the Primrose area over its life cycle will be substantially unchanged," it said.

Horizontal well lifts Bacchus to 17,600 b/d

The Bacchus B-1 horizontal development well, third well in Bacchus field in the UK North Sea, has pushed field production past 17,600 b/d of oil, more than double the year-ago rate (OGJ Online, Aug. 2, 2012), said operator Apache Corp.

Bacchus B-1 went on production in July and is making 9,400 b/d. Apache logged 2,057 ft of net oil pay along a horizontal completion segment in high-quality Jurassic-aged Fulmar sandstone in the field's western fault block. Oil from the Bacchus is produced through a subsea tieback to Apache's Forties Alpha platform.

Following the recent success at Bacchus, Apache has extended its current Forties 3D seismic survey area to cover other Jurassic development and exploration targets on Apache licenses in the Bacchus area. The seismic survey is expected to be completed in September.

Apache has brought three new fields, Bacchus, Maule, and Tonto, on production in the Forties area since 2009. All three developments qualified under the UK government's small field allowance system, which provides economic incentives for operators to bring these discoveries into production.

James L. House, region vice-president and managing director of Apache North Sea, said, "Utilizing existing infrastructure within the Forties field area enables Apache to bring these smaller discoveries on production in a cost-effective manner for the benefit of all stakeholders. A little more than a year after first production, Bacchus has produced 3 million bbl of oil and has already paid out."

Apache is operator of Bacchus with a 50% interest. Partners are Endeavor Energy UK Ltd. 30% and First Oil Expro Ltd. 20%.

Cenovus seeks oil sands project expansion

Cenovus FCCL Ltd. has filed applications for Phase J expansion at its Foster Creek thermal oil sands project 90 km north of Cold Lake, Alta.

It seeks approval for construction of the Phase J expansion facilities and modification and expansion of Phase F, G, and H facilities to increase overall production capacity to 295,165 b/d of bitumen.

It recently reported net production at Foster Lake, a 50-50 project with ConocoPhillips, at 55,380 b/d of bitumen.

The project uses steam-assisted gravity drainage.

PROCESSINGQuick Takes

Biodiesel production reached record high in May

US production of biodiesel reached 111 million gal in May, according to the US Energy Information Administration. This was an increase from production of 106 million gal in April.

Biodiesel production from the Midwest region (Petroleum Administration for Defense District 2) was 67% of the US total, EIA said. Production came from 116 operating biodiesel plants with operable capacity of 2.2 billion gal/year.

Feedstocks consumed for biodiesel production were 3.4 billion lb during January-May, with a ratio of 7.6 lb of feedstock per gallon of biodiesel produced. Soybean oil accounted for 54% of the total biodiesel feedstocks.

Under the Renewable Fuel Standard program, the US Environmental Protection Agency sets annual targets for the use of biodiesel and other biofuel categories, such as advanced and total biofuels, which can also be satisfied through additional biodiesel use.

Targa starts up Train 4 at Cedar Bayou fractionator

Targa Resources LP, Houston, has started operations on the 100,000-b/d Train 4 at its Cedar Bayou fractionator at Mont Belvieu, Tex. Also, the company in mid-July broke ground on its 200-MMcfd cryogenic Longhorn gas processing plant in Wise County in North Texas.

Both announcements were part of Targa's Aug. 1 earnings call.

The $150-million Longhorn plant will start operations in early 2014, delayed by regulatory filings from third-quarter this year. The $385-million Train 4 expansion brings Cedar Bayou "net" fractionation capacity to 346,000 b/d, according to the earnings presentation.

The fractionator project was grounded in agreements between Targa and DCP Midstream LLC, Denver. When it announced Train 4 in 2011, Targa also said it was evaluating another 100,000-b/d Train 5 expansion (OGJ Online, Oct. 20, 2011). The presentation earlier this month made no mention of Train 5 plans.

In addition, Targa's presentation said the company's capacity to export LPG from its Gulf Coast terminal will expand to 3 million bbl/month in third quarter, from 1-1.5 million bbl/month. By third-quarter 2014, export capacity will exceed 5 million bbl/month.

Targa operates one of only two NGL export terminals on the Upper Texas Coast. In March this year, Enterprise Products Partners LP, Houston, began operations at the expanded Houston Ship Channel LPG export terminal owned by Oiltanking Partners LP, Houston.

The expansion increased loading capacity for low-ethane propane to about 7.5 million bbl/month from 4 million bbl/month (OGJ Online, Mar. 7, 2013).

Repairs on track at Geismar olefins plant

Williams Olefins LLC, a subsidiary of Williams Partners LP, plans to restart its Geismar Olefins plant in April 2014, after repairs following an explosion earlier this summer (OGJ Online, June 13, 2013), according to recent company announcement.

The restart will also bring online an expansion that will increase by about 50% the plant's ethylene production capacity.

Williams Olefins has been able to carry out expansions throughout most of the plant except for the immediate area of the explosion near the propylene fractionator. Based on initial damage assessment, Williams Partners has been engaged in the engineering, procurement, and demolition of affected equipment.

As of now, it said, major items slated for replacement include piping and heat exchangers associated with the propylene fractionator, large portions of the electrical power cable and control wiring in the plant, and support structures and piping damaged in the incident.

Enterprise lets contract for PDH unit

Enterprise Products Operation LLC, Houston, has let an engineering, procurement, and construction contract for its planed propane dehydrogenation (PDH) unit at Mont Belvieu, Tex., to a subsidiary of Foster Wheeler AG's Global Engineering & Construction Group. No contract value was disclosed.

Enterprise Products announced last year plans to build the 35,000-b/d PDH unit to take advantage of low-cost propane derived from increased NGL production out of nearby shale gas development.

At the time, the company did not specify the location but its siting the unit at Mont Belvieu complements the extensive fractionation the company operates there with several pipelines connected with local markets and export terminals.

The PDH unit will be able to produce as much as 750,000 tonnes/year of polymer-grade propylene, a prime feedstock for plastics manufacturers.

According to the 2012 announcement, the unit will be "one of the world's largest." Enterprise Products expects it to begin operating in third-quarter 2015 (OGJ Online, June 21, 2012).

TRANSPORTATIONQuick Takes

EPA updates storage tank emissions requirements

The US Environmental Protection Agency issued updates to standards it brought out in April covering air emissions from oil and gas storage tanks. The updates will phase in control deadlines, starting with higher-emitting tanks first, and will provide the necessary time to ramp up production and installation, it said.

EPA made the changes after receiving information that more storage tanks than it initially estimated will come online, the EPA said. Tanks that emit 6 tons/year or more of volatile organic compounds (VOC) will have to reduce those emissions by 95%, it noted.

It said the Aug. 5 order established two deadlines: Tanks which came online after Apr. 12 and are likely to have higher emissions will have to control VOC releases within 60 days or by Apr. 15, 2014, whichever is later. Tanks which came online before Apr. 12 and are likelier to have lower emissions must control those releases by Apr. 15, 2015.

The updated standards also establish an alternative emissions limit that would allow owners or operators to remove controls if they can demonstrate that the tanks emit less than 4 tons/year of VOC without controls, according to EPA. The rule also streamlines compliance and monitoring requirements for tanks on which controls have been installed already, it said.

The action does not affect requirements which EPA also issued in April covering capturing of natural gas emitted from hydraulically fractured wells, EPA noted.

Progress anchors NGTL's North Montney expansion

Progress Energy Canada Ltd. has signed firm transportation agreements with TransCanada Corp.'s wholly owned subsidiary Nova Gas Transmission Ltd. (NGTL) for 2 bcfd of natural gas shipments from northeastern British Columbia, underpinning development of NGTL's North Montney Mainline expansion project. The 189-mile, large-diameter North Montney expansion will include two sections—Aitken Creek and Kahta—both starting from NGTL's Groundbirch mainline.

The project also will include an interconnection with TransCanada's proposed Prince Rupert Gas Transmission (PRGT) project to provide natural gas supply to the proposed Pacific NorthWest LNG export facility near Prince Rupert, BC.

Under terms of the transportation agreements receipt volumes will ramp up between 2016 and 2019 to an aggregate volume of 2 bcfd and delivery volumes to the PRGT project will be 2.1 bcfd beginning in 2019. NGTL is also talking with other parties that have expressed interest in transportation services on North Montney.

NGTL is currently engaged in First Nations and community outreach, field studies, engineering and design work, and pipeline routing to support applications for regulatory approvals and to finalize project requirements. The company anticipates filing an application with Canada's National Energy Board in this year's fourth quarter for approvals to build and operate the project. Pending these approvals, NGTL expects the Aitken Creek section to be operational second-quarter 2016, the Kahta section second-quarter 2017 and the export delivery facilities in 2019.

The company estimates the total cost of the North Montney Mainline project at about $1.5 billion.

Sinopec begins building Guangxi LNG terminal

China Petroleum & Chemical Corp. (Sinopec) has announced the start of construction on an LNG terminal at the southern port of Tieshan, Beihai City, Guangxi Province.

The 5 million tonne/year regasification terminal will be built in two phases: Phase 1, 3 million tpy; Phase 2, 2 million tpy.

Upon completion in 2014, the project will complement and support the second West-East gas pipeline and Sino-Burma pipeline, Sinopec said.