OGJ Newsletter

June 8, 2015
International news for oil and gas professionals

general interestQuick Takes

Oklahoma governor signs law to prevent fracing bans

Oklahoma cities and counties would be unable to ban hydraulic fracturing or other oil and gas operations under Senate Bill 809 that Oklahoma Gov. Mary Fallin has signed into law.

The Oklahoma law, effective in 90 days from May 29, allows municipalities or counties to enact regulations concerning road use, traffic, noise, and odors associated with oil and gas operations. It also authorizes fencing requirements around drilling sites and setback requirements for a well from homes and businesses.

Fallin noted the law reaffirmed that the Oklahoma Corporation Commission remains Oklahoma's primary oil and gas regulator. The three commission members are elected by voters.

"They are best equipped to make decisions about drilling and its effect on seismic activity, the environment and other sensitive issues," Fallin said in a statement. "The alternative is to pursue a patchwork of regulations that, in some cases, could arbitrarily ban energy exploration and damage the state's largest industry, largest employers, and largest taxpayers."

Previously, Oklahoma municipalities had attempted to regulate fracturing using a 1935 statute that gave local governments authority over oil and gas activities within city boundaries.

Texas Gov. Greg Abbott signed a similar law for his state in May after the voters of Denton, Tex., authorized a fracturing ban. The ban stemmed from a referendum item on the November 2014 ballot (OGJ Online, May 18, 2015).

European oil majors call for carbon pricing systems

Recognizing "the importance of the climate challenge," six major European oil and gas companies have joined together in calling for governments around the world and the United Nations Framework Convention on Climate Change (UNFCCC) "to introduce carbon pricing systems and create clear, stable, ambitious policy frameworks that could eventually connect national systems."

BP PLC, BG Group PLC, Royal Dutch Shell PLC, Statoil ASA, Eni SPA, and Total SA jointly documented their position in a letter from their chief executives to the UNFCCC Executive Secretary and the president of the COP21 ahead of the UNFCCC's COP21 climate meetings in Paris in December.

They note that the current trend of greenhouse gas emissions is more than what the Intergovernmental Panel on Climate Change says is needed to limit global temperature rise to no more than 2° C.

Emphasizing the importance of natural gas in reaching their goal, the chief executives wrote, "We firmly believe that carbon pricing will discourage high-carbon options and reduce uncertainty that will help stimulate investments in the right low-carbon technologies and the right resources at the right pace. We now need governments around the world to provide us with this framework and we believe our presence at the table will be helpful in designing an approach that will be both practical and deliverable."

EPP acquires Eagle Ford midstream assets

Enterprise Products Partners LP (EPP), Houston, has executed agreements to purchase all of the member interests in EFS Midstream LLC from affiliates of Pioneer Natural Resources Co., Irving, Tex., and Reliance Industries Ltd., Mumbai, for $2.15 billion. The companies announced last year their desire to divest EFS Midstream (OGJ Online, Nov. 4, 2014).

Payment will take place in two installments, the company said, with the first amount of $1.15 billion being paid at closing and the final payment of $1 billion being paid by the first anniversary of the closing.

The company said completion of the transaction is subject to customary regulatory approvals and closing conditions. Enterprise expects the closing in third-quarter 2015.

Under the agreement's terms, the Pioneer and Reliance joint development will dedicate its Eagle Ford shale acreage to EPP under a 20-year, fixed-fee gathering agreement that includes a minimum volume requirement for the first 7 years. Pioneer and Reliance will also dedicate their Eagle Ford shale acreage under related 20-year fee-based agreements with EPP for gas processing, NGL transportation and fractionation, and for natural gas, processed condensate, and crude oil transportation services.

EFS Midstream provides gas gathering, treating, compression, and condensate processing in the Eagle Ford shale and includes about 460 miles of natural gas gathering pipelines, 10 central gathering plants, 780 MMcfd gas treating capacity, and 119,000 b/d of condensate stabilization capacity.

Hibiscus terminates Kitan field deal

Malaysian company Hibiscus Petroleum Bhd. has terminated its $18-million purchase of Talisman Energy Inc.'s 25% interest in Kitan oil field in the Timor Sea (OGJ Online, Apr. 7, 2014).

The purchase deal was struck in June 2014, but Hibiscus told the Malaysian stock exchange this week that conditions precedent to the share sale agreement had not been fully satisfied by the May 31 cut-off date.

Kitan field, which lies in the Joint Petroleum Development Area between Australia and Timor Leste 550 km northeast of Darwin, was discovered in 2008.

It is operated by Italy's Eni SPA with 40% interest. Japan's Inpex Corp. holds 35% while Talisman holds 25%.

The field was brought on stream in 2011 via three subsea wells connected to the Glas Dowr floating production, storage, and offloading vessel. Production is running at about 10,000 bo/d.

Exploration & DevelopmentQuick Takes

Statoil enters offshore Nicaragua with four licenses

Statoil ASA has been awarded four licenses covering 16,000 sq km in the largely unexplored Sandino basin of the Nicaraguan Pacific. Statoil will operate the licenses with 85% interest, partnering with Empresa Nicaraguense del Petroleo (Petronic), which will hold the remaining interest. Initial work commitments during the 2½-year first exploration phase include reprocessing of 2D seismic, acquisition of new 2D seismic data, and geological and geophysical studies.

Information obtained from the initial studies and seismic survey will form the basis for Statoil's next steps in the licenses.

"Offshore the Nicaraguan Pacific is virtually untested and the awards of new acreage in this frontier area are in line with our exploration strategy of access at scale," commented Nick Maden, senior vice-president for Statoil's exploration activities in the Western Hemisphere.

Petrobras confirms Carcara light oil potential

Petroleo Brasilierio SA (Petrobras) found a 352-m oil column of 31° gravity in continuous and connected reservoirs while drilling the second well in the Carcara area on Block BM-S-8 in the ultradeep waters of the presalt Santos basin.

Well 3-SPS-105, also known as Carcara North, is 4.6 km north of discovery well 4-SPS-86B in 2,072 m of water. The reservoirs are situated just below the salt layer from a depth of 5,820 m. Pressure data show the column is the same accumulation as the discovery well, Petrobras says.

The company will assess the productivity of the reservoirs after drilling concludes. Well 3-SPS-104DA, also known as 3-BRSA-1216DA-SPS and Carcara Northwest, is scheduled to be drilled this year, advancing the company's discovery evaluation plan (PAD).

Petrobras in 2012 encountered 400 m of continuous oil pay at the Carcara discovery well (OGJ Online, Aug. 15, 2012). That followed the confirmation of the discovery's continuity (OGJ Online, June 1, 2012). The Carcara PAD, approved by Brazil's National Petroleum Agency, is expected to conclude in March 2018.

Petrobras operates Carcara North with 66% stake. Partners are Petrogal Brasil SA 14%, Barra Energia do Brasil Petroleo e Gas 10%, and Queiroz Galvao Exploracao e Producao SA 10%.

Kina's PNG wildcat well hits volcanic rock

Kina Petroleum Ltd.'s much-hyped wildcat in northern Papua New Guinea has hit an unexpected problem.

Raintree-1, the first well to be drilled north of the highlands in decades, has encountered volcanic rocks. The well was targeting a strong seismic reflector that was interpreted as a carbonate reef structure at the edge of the underexplored Ramu basin.

However, at a well depth of 1,088 m, the bit passed into volcanic lithology, the age and significance of which is still being evaluated.

The current plan is to continue to 1,200 m prior to making a logging run.

The result is reminiscent of a similar mistake made in Bass Strait by Planet Oil group in the 1960s with Sailfish-1, which targeted what was purported to be a classic dome structure, only to find it was volcanics.

Kina nevertheless says the igneous rock does not necessarily kill the Raintree prospect. A good sealing unit was encountered at 1,000 m and the follow-up prospects at Kwila and Sogerum will target a shallower Plio-Pleistocene sandstone reservoir down dip of active gas seeps on the northern flank of the Banam Anticline.

The presence of volcanics, however, does send a note of caution because igneous rocks often alter source rocks and impede hydrocarbon migration as well as altering the potential for reservoir, trap, and seal.

LLOG finds oil on Crown & Anchor prospect

Privately owned LLOG Exploration Co. LLC and partners are studying subsea development of a discovery at their Crown & Anchor prospect on Viosca Knoll Block 959 in the Gulf of Mexico.

LLOG said an exploratory well encountered more than 50 net ft of oil-bearing sand in a high-quality Miocene reservoir. It didn't report test results.

LLOG holds a 60% working interest. Partners are Ridgewood Energy and Stone Energy Corp.

Drilling & ProductionQuick Takes

Woodside to exit Tanzania PSA with Beach

Woodside Petroleum Ltd. has chosen not to take up its option to proceed to Phase 2 of the Lake Tanganyika South production-sharing agreement in Tanzania with Beach Petroleum Ltd.

Woodside farmed into Beach's permit last year (OGJ Online, July 14, 2014). The terms remain confidential, but in general Woodside agreed to refund Beach's past costs, including its early seismic survey program, and then fund another seismic program that was carried out during 2014-15.

Beach serves as operator with 30% interest while Woodside held the remaining interest.

Phase 2 included Woodside providing a capped carry for Beach through the cost of the first exploration well. Woodside would have also taken the operatorship.

Now, however, with Woodside's exit, Beach has resumed 100% interest in the PSA. The company says it has preserved its rights to go ahead with the drilling phase, but has yet to decide whether to bring in another farm-in company or sell out of the block.

Beach secured the onshore-offshore block that encompasses the southern end of 600-km Lake Tanganyika in 2008, keen to explore the potential of the Albertine Rift, the western branch of the East African Rift play that has been successfully explored to the north in Lake Albert in Uganda.

The Beach block included natural oil seeps that indicate a working petroleum system beneath the lake. Early work suggested a potential for traps containing 200 million bbl or more.

The practical problem though is that exploration drilling requires transport inland, followed by assembly of an offshore drilling rig to work in the deepest part of the lake. There has been some thought given to first drilling a land-based deviated well under the lake to check for a valid petroleum system before commitment to the offshore drilling.

Woodside has decided that the low oil-price environment does not satisfy the risk-reward equation.

ConocoPhillips reports first steam from Surmont 2

ConocoPhillips reported first steam on May 29 from Phase 2 of its Surmont oil sands project in the Athabasca region of northeastern Alberta.

Production is expected to begin in the third quarter, ramping up through 2017 while adding 118,000 bo/d of gross capacity. Total gross capacity for Surmont 1 and 2 is expected to reach 150,000 bo/d.

Commercial production from the project, which uses steam-assisted gravity drainage to recover the bitumen, started in 2007 (OGJ Online, Dec. 11, 2007). Construction on Phase 2 began in 2010 (OGJ Online, Jan. 19, 2010).

ConocoPhillips operates Surmont in a 50-50 joint venture with Total E&P Canada (OGJ Online, May 11, 2005).

Chevron moving Big Foot TLP off location

Chevron Corp. will delay the start of production at deepwater Big Foot oil field in the Walker Ridge area of the Gulf of Mexico because of damage to subsea installation tendons installed for connection to the field's tension-leg platform.

The company will move the 15-slot, drilling and production TLP to sheltered waters. The unit was neither damaged nor connected to any subsea wells or tendons when the several tendons lost buoyancy. There were no injuries or fluid releases. Chevron said production will not start late this year, as planned.

The Big Foot TLP, which is in 5,200 ft of water 225 miles south of New Orleans, has design capacity of 75,000 b/d of oil and 25 MMcfd of natural gas (OGJ Online, Dec. 16, 2010).

PROCESSINGQuick Takes

Z Energy to buy Chevron NZ for $785 million (NZ)

Z Energy Ltd., the downstream petroleum entity headquartered in Wellington, has acquired Chevron New Zealand for $785 million (NZ).

The purchase provides Z Energy with ownership of the Caltex business in New Zealand that includes 147 retail outlets and 73 diesel outlets.

The deal comes on the heels of Chevron's separate sale of its 11.4% interest in New Zealand Refining Co. Ltd., which operates the 107,000-b/d Marsden Point refinery at Northland on the North Island's east coast last week (OGJ Online, May 29, 2015). Z Energy holds a 15% interest in the refinery.

Z Energy says its deal with Chevron excludes Chevron's upstream interests, but adds that it was in the best position and a logical buyer of Chevron's retail and distribution chain.

The company has now vastly increased its market share in New Zealand. Formed 5 years ago, Z Energy says this latest acquisition will bring to 350 its number of retail outlets. The company bought 210 outlets from Royal Dutch Shell PLC in 2010.

Z Energy will raise $185 million (NZ) from shareholders to help fund the Chevron acquisition, which is expected to yield $25 million in synergies from 2017 and give an immediate boost to the company's earnings.

Tidewater to buy Pembina area gas plant, pipelines

Tidewater Midstream & Infrastructure Ltd., Calgary, will pay $180 million (Can.) to unspecified "private company vendors" to purchase their 63% operated working interest in an unnamed 185-MMcfd natural gas processing plant in West Pembina along with related pipelines in central Alberta. The purchase price consists of $170 million cash and $10 million in Tidewater common shares (at $1.35/share).

Tidewater Midstream Pres., Chief Executive Officer, and Chairman Joel A. MacLeod declined Oil & Gas Journal's request to identify the sellers or the specific gas plant. OGJ's 2014 data for Canadian gas processing, however, reflect a single plant in Alberta with 185 MMcfd of inlet capacity: Blaze Energy Ltd.'s Brazeau River plant.

Tidewater said the plant has current throughput of about 140 MMcfd and can process sweet and sour natural gas and has "area leading" deep cut gas processing capability. In addition, the plant connects to producers through about 240 miles of gas gathering and NGL takeaway and crude systems.

Blaze Energy's web site says it conducts most of its operations in the "Brazeau River and West Pembina" areas of Alberta. Its Brazeau River complex possesses large deep cut sour gas capacity and, last year, was "operated and 63%-owned" by Blaze, which also operated gas gathering of about 220 miles.

Tidewater said it expects to complete the acquisition by June 30.

Hawaiian refinery inks supply deal

Hawaii Pacific Energy LLC, a subsidiary of Houston-based Par Petroleum Corp., has entered a crude oil supply and product offtake agreement with J. Aron & Co., the commodity trading arm of Goldman Sachs, for its 94,000-b/d refinery in the Campbell Industrial Park in Kapolei, 20 miles west of Honolulu, Ha., on the island of Oahu.

As part of the agreement, J. Aron will provide HPE to purchase mutually agreed crude cargos to process in the refinery, while HPE, in turn, will sell its refined products to J. Aron at market prices, Par Petroleum said.

The agreement, which will extend through May 2018 with two 1-year extension options, also will allow for HPE to repurchase refined products from J. Aron to sell to its own customers, as well as defer payments to J. Aron of up to up to $125 million, or 85% of certain receivables and company-owned inventory, the company said.

Par Petroleum said that in addition to reducing HPE's crude acquisition costs and increasing its flexibility to manage market price fluctuations, the deal with J. Aron will result in about $20 million in additional cash and liquidity under current market conditions.

Increased revenue resulting from the transaction will help to maximize capacity utilization of the refinery as well as enable projects to improve its future performance, according to Joseph Israel, president and chief executive of Par Petroleum.

Par Petroleum completed its acquisition of the Kapolei refinery from Tesoro Corp. in September 2013 (OGJ Online, Sept. 27, 2013).

In addition to its 94,000-b/d crude distillation unit, the refinery includes the following processing capacities: 40,000 b/d of vacuum distillation, 13,000 b/d of naphtha hydrotreating, 18,000 b/d of vacuum gas oil hydrocracking, 2,000 b/d of diesel hydrocracking, 11,000 b/d of visbreaking, and 13,000 b/d of catalytic reforming.

Malfunction forces unit shutdown at Ohio refinery

A compressor malfunction has forced an unplanned shutdown of the fluid catalytic cracker (FCC) at PBF Energy Inc.'s 170,000-b/d refinery at Toledo, Ohio.

The FCC likely will remain out of service for 2-3 weeks, PBF Energy says.

While unaffected units at the refinery continue to operate at reduced rates, the company is continuing to monitor the situation to assess the economic impact of the FCC's unplanned downtime.

Currently, PBF Energy expects the Toledo refinery's total throughput for this year's second quarter to average 130,000-140,000 b/d, with full-year throughput expected to average 145,000-155,000 b/d, the company said.

Further details regarding the incident were not disclosed.

The Toledo refinery processes light, sweet crude, the majority of which is delivered via pipelines from Canada and the US.

Since acquiring the Toledo refinery from Sunoco Inc. in 2011 (OGJ Online, Mar. 2, 2011), PBF Energy has added additional truck and rail crude unloading capabilities that provide feedstock sourcing flexibility for the refinery and enable the plant to run a more cost-advantaged crude slate (OGJ, Aug. 5, 2013, p. 91).

In addition to its 170,000-b/d crude distillation and 79,000-b/d FCC units, the Toledo refinery includes the following processing capacities: hydrotreating, 95,000 b/d; hydrocracking, 45,000 b/d; catalytic reforming, 45,000 b/d; alkylation, 10,000 b/d; and udex benzene extraction, 16,300 b/d.

TRANSPORTATIONQuick Takes

DOE okays Alaska LNG to export to non-FTA areas

The US Department of Energy has issued a conditional authorization for Alaska LNG Project LLC to export as much as 2.55 bscfd of US-produced natural gas for a 30-year period to countries with no free-trade agreement with the US.

Earlier this year, Alaska LNG project partners filed resource reports with the US Federal Energy Regulatory Commission (OGJ Online, Feb. 12, 2015) for the project.

Alaska LNG is in the Nikiski area of Alaska's Kenai Peninsula.

Federal law generally requires approval of gas exports to countries that have an FTA with the US. For countries that do not have an FTA with the US, the Natural Gas Act directs DOE to grant export authorizations unless it finds that the proposed exports "will not be consistent with the public interest," DOE said.

DOE considered the Alaska application separately from other currently pending LNG export applications in the Lower 48 due to the relative geographic isolation of the gas resources on Alaska's North Slope.

ANS gas has been a stranded resource unavailable to commercial markets. The project proposed by Alaska LNG includes a pipeline intended to make ANS gas accessible.

Timor-Leste lets pre-FEED for Beaco LNG plant

Timor-Leste has let a $3.8-million pre-front-end engineering design contract to Amec Foster Wheeler for the proposed Beaco LNG plant.

Amec Foster Wheeler's scope for the contract includes concept selection studies, development of technical design, development of procurement and construction strategies, project implementation plans, capital cost estimate and schedule for the overall project.

Amec Foster Wheeler says work will be performed in close consultation with Timor-Leste's state-owned Timor GAP EP, which is managing the implementation of the Tasi Mane project comprising three clusters of development-the Suai supply base, Betano refinery, and Beaco LNG plant-situated along 155 km of Timor-Leste's southern coast.