GENERAL INTEREST — Quick Takes
CERI: Low oil prices hurt Canadian economy
Persistence of low crude oil prices through 2021 would hurt more than help the Canadian economy by constricting oil-producing and affiliated industries, finds a study by the Canadian Energy Research Institute.
"The regional differences suggest that some provinces will hurt and some will benefit from lower crude prices, but on the national level Canadian economic growth will suffer as a result of low crude prices," says the study by Dinara Millington.
The study models economic effects of a reference case assuming a West Texas Intermediate crude price rising from $53.25/bbl in 2015 to $72.88/bbl in 2021 and a low case with a WTI price of $46.26/bbl in 2015 rising to $51.25/bbl in 2021.
In the reference case, oil sands production rises to 3.1 million b/d from 2.1 million b/d over the study period. Capital investment averages $19.576 billion (Can.)/year, and the US/Canadian exchange rate is 0.85.
In the low case, oil sands production rises to 2.9 million b/d from 2 million b/d, capital investment averages $13.703 billion/year, and the exchange rate is 0.75. Nonenergy exports are $7.558 billion higher on a 7-year average in the low case.
In comparison with the reference case, the low case yields national declines of 24.5% in cumulative gross domestic product growth, 22.6% in compensation, 19.7% in employment, 25% in federal taxes, and 22.4% in provincial taxes.
"Despite some mitigating factors, lower oil prices are, on the whole, not favorable for Canada," the study says, suggesting, "For every Canadian-dollar gain in WTI price, Canadian GDP would gain almost $1.7 billion on average."
Murkowski: CRS analysis raises key oil tax questions
A new Congressional Research Service (CRS) report examines eight important questions about US President Barack Obama's proposed crude oil tax, US Senate Energy and Natural Resources Committee Chair Lisa Murkowski (R-Alas.) said as she released a third CRS study following the president's initial announcement (OGJ Online, Feb. 4, 2016).
"We have astonishingly few details about the president's proposal, and the few details we do have all suggest that this tax or 'fee' would further imperil the American energy renaissance," Murkowski said on Mar. 3. "We don't even know if the administration's own math works out."
The report addressed eight "unaddressed" issues regarding what the White House calls a fee, including details related to production forecasts, inflation estimates, the point of collection, and the home heating oil subsidy program.
Revenue estimates for the $10.25/bbl oil fee appear in the president's fiscal 2017 federal budget proposal, it noted. "The revenue estimates extend out to 2026, and as a result, are based on projections of US oil use," the report said. "The basis of the oil quantity estimates, as well as how they are related to [US] Energy Information Administration projections, [is] not disclosed in the budget."
Murkowski previously released CRS studies of the Obama's proposed oil tax that the Energy and Natural Resources Committee's majority staff commissioned on Feb. 8 and Feb. 23.
"This report will not be the last as I continue to examine the potential impact of such a harmful policy that, whatever the details may be, is certain to harm domestic energy production," the senator said.
Barclays sees gas-price recovery in 2017
Natural gas prices in the US will be lower than earlier forecast this year but will ease back up in 2017, says Barclays Research, citing storage patterns. Because gas inventories will end winter above forecast levels at what it expects to be 49% above the 5-year average, Barclays has lowered its projected average gas price for 2016 to $2.50/MMbtu from $2.56/MMbtu.
As demand grows and storage pressures ease in 2017, the average gas price will rise to $3.05/MMbtu-$2.90/MMbtu in the first half and $3.20/MMbtu in the second half.
Production from the US Northeast will have to augment storage withdrawals to meet demand in 2017, until then offsetting declines in gas associated with shrinking oil production.
Barclays expects demand this year to be boosted by suppressed gas prices in a trend set to continue in 2017, when new industrial facilities start up LNG and pipeline exports grow.
"The major unknowns for 2017 will come on the production side and will specifically focus on the Northeast's ability to grow and the levels of associated gas production potentially reentering the market when oil prices rebound," Barclays says. "The load will continue to fall on the Northeast. Although we do forecast a tick-up in associated gas as oil moves higher, it is unlikely to be sufficient in both quantity and required lead time." The firm projects gas in storage at the end of October 2017 to total 3.7 tcf.
"Given new demand entering the market, it is questionable how the market will view that number given the previous two winters have entered the season at around 4 tcf," Barclays says.
Gazprom secures €2-billion Chinese loan
PJSC Gazprom has secured a €2-billion, 5-year loan facility with Bank of China Ltd. London Branch in a deal that improves prospects for large projects to export Russian gas to China.
Gazprom called the loan "the largest deal in terms of the amount of financing attracted directly from one financial institution and the first bilateral loan facility agreement with a Chinese bank."
Gazprom has multibillion-dollar agreements with China National Petroleum Corp. to lay two natural gas pipelines, one based on eastern Siberian fields and the other supplied by fields in western Siberia.
With oil and gas prices slumping, the Chinese economy slowing, and Gazprom facing new competition in Russia, both projects have encountered problems.
Development of the western pipeline was suspended last July when the companies couldn't agree on price.
For the eastern project, Gazprom has sought help with financing, including an advance payment from CNPC to support construction, according to news reports. The Chinese company rejected the request.
Exploration & Development — Quick Takes
Det norske adds seven NCS licenses
Det norske oljeselskap ASA has agreed to acquire Noreco Norway AS's Norwegian license portfolio, including a $5-million cash balance. The deal is effective Jan. 1.
The portfolio consists of seven licenses on the Norwegian Continental Shelf, including 20% interest in the Gohta discovery on PL492 in the Barents Sea. Noreco's 4.36% interest in the Enoch field is not included in the deal.
"Following the recent acquisition of both Svenska Petroleum Norway and Premier Oil's Norwegian subsidiary (OGJ Online, Nov. 16, 2015), this takeover of Noreco Norway underlines Det norske's belief in, and commitment to, the Norwegian Continental Shelf," said Det norske CEO Karl Johnny Hersvik.
Group drills SNE-3 appraisal well off Senegal
A group led by Cairn Energy PLC has drilled the SNE-3 appraisal well offshore Senegal, confirming the field's upper reservoir units can flow at commercially viable rates and make a material contribution to oil volumes.
Project partner, FAR Ltd., Perth, says that two drillstem tests were run in these upper units over the past week. The company said a gross 15-m zone flowed at rates as high as 5,400 b/d of oil with a stabilized main flow of 4,000 b/d through a 56/64-in. choke. Another 5.5-m zone was added to the first flow and produced at a combined stabilized rate of 4,500 b/d through the same choke size. The flows were constrained by the available test equipment, but still exceeded FAR's expectations.
FAR said the results confirmed an excellent reservoir quality and a correlation between the other two wells on the field (OGJ Online, Dec. 10, 2015).
A 144-m-long core was taken across the entire reservoir interval and the SNE-3 well confirmed a gross oil column thickness of 101 m. This compares with a gross column of 103 m at SNE-2 and 96 m at SNE-1. The oil measured 32° API gravity, the same as the previous two wells.
FAR added that the reservoir units were intersected higher than expected on the structure, suggesting the southern flank of the field may extend further south than originally mapped.
SNE field lies in the Sangomar Deep offshore block and SNE-3 is about 3 km south of the SNE-1 discovery well.
The third well has been plugged as planned and the Ocean Rig Athena rig will move to the BEL-1 location to evaluate a buried hills play on the Bellatrix prospect that lies above and to the north of SNE field.
Cairn holds 40% in the block. Other partners include ConocoPhillips 35%, FAR 15%, and Senegal state oil concern Petrosen 10%.
Pakistani exploration well flows 16 MMcfd of gas
Petroleum Exploration (Pvt.) Ltd. (PEL), a privately owned Pakistani company, has identified a hydrocarbon-bearing zone in the Lower Guru formation with its Aminah-1 exploration well drilled on Badin South block in the Sajjawal (Sindh) district.
The well was spudded on Jan. 6 and reached target depth of 2,297 m on Feb. 3. Initial testing of the formation flowed 16 MMcfd of gas on 48/64-in. choke. According to PEL, it is now planning a second well for the block, Ayesha North-1.
Rosneft starts drilling exploratory well off Vietnam
OJSC Rosneft said it started drilling an exploratory well offshore Vietnam in the Nam Con Son basin. It's the first time Rosneft has been drilling operator in international waters.
The PLDD-1X well was drilled in 162 m of water on Block 6.1 and has a design depth of 1,380 m. Japan Drilling Co. Ltd. is using the HAKURYU-5 drilling rig.
Rosneft Vietnam BV owns 35% of a production-sharing contract in Block 6.1 with two gas-condensate fields-Lan Tay and Lan Do-about 370 km offshore (OGJ Online, Jan. 20, 2003).
Block 6.1 produced its 300 millionth barrel of oil equivalent last year, and provides about 12% of energy needs in Vietnam, Rosneft said (OGJ Online, Feb. 25, 2010).
The company plans to shoot broadband 3D seismic on Block 6.1 later this year "to enhance ongoing production recovery and explore potential in deeper prospects."
Rosneft also plans to drill another exploratory well in the Nam Con Son basin in nearby Block 5.3/11. Rosneft has 100%.
Drilling & Production — Quick Takes
Aramco to nearly double gas production in decade
Saudi Aramco plans to nearly double its natural gas production to 23 standard bcfd in 10 years, Aramco Chief Executive Officer Amin Nasser told an industry conference in Jubail on Mar. 8.
Having already increased its gas output to more than 12 bcfd from 3.5 billion bcfd during the early 1980s, Aramco has set a production goal for the coming decade.
"Work is under way to execute an ambitious plan to implement this," Nasser said, stopping short of elaborating. He did say Aramco is exploring and developing unconventional gas.
The company is working to boost gas output for electricity and petrochemical production by developing gas fields not associated with oil production.
He also said Aramco plans to boost its refining capacity to 8-10 million b/d from its current capacity of 5.4 million b/d.
Eni group installs Zubair treatment plants
The group led by Eni SPA redeveloping supergiant Zubair oil field in southern Iraq has completed three new oil, gas, and water treatment plants (OGJ Online, July 16, 2013).
Together with restructured and modernized facilities, the new plants boost total oil and gas treatment capacity at Zubair to 650,000 b/d.
Four new treatment trains at the Hammar production center have capacities totaling 200,000 b/d. New trains with capacities of 50,000 b/d each are in place at the Zubair and Rafydia production centers.
Hammar and Zubair are on production. Rafydia will start up by the end of this month.
The new plants have water injection capacities totaling about 300,000 b/d.
Zubair produces about 360,000 b/d of oil, twice its level when the technical services contract with South Oil Co. for field redevelopment went into effect in February 2010.
Production is to increase during the next few years to 850,000 b/d, a target renegotiated from the originally agreed 1.2 million b/d.
UBS: Petrobras to cut more rig contracts
New cuts to ultradeepwater drilling plans by Petroleo Brasileiro SA (Petrobras) aggravate strains on the Brazilian holding company Sete Brazil and on the offshore drilling industry generally, according to UBS Securities LLC.
Citing press reports, UBS says the state-owned oil company has proposed to enter contracts for only 10 of the 29 ultradeepwater rigs it originally ordered through Sete. Seven of those contracts were cancelled late last year.
For surviving contracts, UBS says, Petrobras seeks shorter terms and 30% reductions in day rates.
UBS calls the move "a clear foreshadowing for the offshore drilling industry and longer-term demand from the region."
In addition to hurting Brazilian shipyards and their suppliers, the Petrobras cuts increase reported pressure on Sete to enter bankruptcy or restructure.
All seven cancellations last year were drillships, as are all but one, a semisubmersible, of the 12 expected cancellations, according to UBS. Surviving contracts are for five semis and five drillships.
EIA projects monthly oil output drop for Permian
A year after US shale oil production began its decline, output form the Permian basin is finally projected to follow suit.
Crude oil production in April from the seven major US shale regions is expected to fall 106,000 b/d to 4.87 million b/d, according to the US Energy Information Administration's latest Drilling Productivity Report (DPR). That includes a 4,000-b/d drop in the Permian to 2.04 million b/d.
The DPR focuses on the Bakken, Eagle Ford, Haynesville, Marcellus, Niobrara, Permian, and Utica, which altogether accounted for 95% of US crude production increases and all US natural gas production increases during 2011-13.
The Eagle Ford is expected to contribute its usual largest share of declines, shedding 58,000 b/d to 1.18 million b/d. The Bakken is expected to fall 28,000 b/d to 1.08 million b/d, while the Niobrara is expected to drop 15,000 b/d to 408,000 b/d.
Data published by the EIA show overall US crude production in December averaged 9.26 million b/d, down from 9.31 million b/d in November and 9.43 million b/d in December 2014 (OGJ Online, Mar. 1, 2016).
US shale gas production in April from the seven regions, meanwhile, is forecast in the DPR to fall 450 MMcfd to 46.31 bcfd. The Eagle Ford also is projected to take the largest hit, losing 182 MMcfd to 6.34 bcfd, followed by a 108-MMcfd drop in the Marcellus to 17.32 bcfd. The only increase is expected in the Utica, up 22 MMcfd to 3.65 bcfd.
PROCESSING — Quick Takes
Iraq breaks ground on grassroots Missan refinery
Iraq has started construction on a long-planned $6-billion refinery in the country's southern-border province of Missan.
In a recent groundbreaking ceremony, Iraq's Deputy Minister for Refining Deiaa Jaafar laid the first cornerstone for the proposed 150,000-b/d refinery, which is being built by a consortium of Swiss company Satarem and Wahan Co. of China, according to a release from the Iraqi Ministry of Oil.
The country's first refinery to be constructed as part of Iraq's invitation to global public investors to help boost domestic refining capacity (OGJ Online, June 29, 2010), the project will be funded by funded by the Export-Import Bank of China and China Development Bank, Jaafar said.
Iraqi state-owned Missan Oil Co. will operate the refinery on behalf of owners Wahan 85% and Satarem 15%.
A timetable for the project's completion was not disclosed.
Iraq, which initially signed a contract with Satarem in October 2013 for the Missan refinery's construction (OGJ Online, Dec. 2, 2013), plans an additional three refineries that will add more than 700,000 b/d to its national refining capacity, including the 300,000-b/d Nassiriya refinery, 150,000-b/d Kirkuk refinery, and the 140,000-b/d Karbala refinery (OGJ Online, June 4, 2013).
The Karbala refinery, which began construction in February 2014, is due to be commissioned by 2020.
Sonatrach lets contracts for three new refineries
Algeria's state-owned Sonatrach SPA has let a series of contracts to Amec Foster Wheeler (AFW) to provide front-end engineering and design for three grassroots refineries that will add a total of 15 million tonnes/year in refining capacity in the country.
To be built in Biskra, Tiaret, and Hassi Messaoud, each of the three refineries will have a capacity of 5 million tonnes/year and will be configured to process Algerian crude oil.
In addition to atmospheric distillation, all three refineries will include the following processing capabilities and installations: LPG separation; hydrocracking; desulfurization; bitumen production; blending; effluents treatment; and utilities, storage tanks, shipping facilities, and administrative buildings.
The proposed Biskra refinery also will include a unit for lubrication oil production, the service provider said.
AFW also will help Sonatrach to select licensors for process technology to be installed at the new refineries, the company said. While it did not disclose a value of the three FEED contracts, AFW did confirm its scope of work on the projects is scheduled to be completed during third-quarter 2017.
A member country of the Organization of Petroleum Exporting Countries, Algeria currently has five major refineries with a combined crude processing capacity of more than 520,000 b/d.
While the country recently has updated a previously launched program to increase its nationwide refining capacity by 50% to lift production of gasoline and diesel to meet rising domestic demand, execution of the revised program-which calls for new refineries as well as upgrades to existing plants-likely has shifted beyond 2020, according to OPEC's latest annual outlook.
Total opens new plant at Bayport operations
Total SA has commissioned a $100-million hydro de-aromatization (HDA) plant at its petrochemical manufacturing site in Bayport, Tex., that will produce a range of 40 different high-purity special fluids for use in a variety of industrial applications for US and international customers.
Entered into operation on Feb. 14, the unit currently is in the process of ramping up to its designed production capacity of 250,000 tonnes/year, Total officials said at the plant's official opening ceremony on Mar. 7.
Modeled on Total's existing HDA plant in France, the Bayport HDA plant uses a catalytic reaction process that, when combined with high pressure and distillation, enables production of odorless, colorless, low-aromatic high-purity fluids customized to meet customer needs across a wide spectrum of industries, including pharmaceuticals, crop protection, water treatment, printing inks, paints and coatings, and cosmetics.
The Bayport HDA plant also will produce synthetic biodegradable fluids for onshore and offshore drilling in accord with Total's commitment to using clean drilling fluids for the company's exploration and production operations, said Phillippe Boisseau, Total executive committee member and president of the company's marketing and services division.
About 85% of the plant's special fluids production will be sold to US buyers, while the remaining 15% is to be exported to international customers to meet rising global demand for cleaner, greener products, Boisseau said.
Located adjacent to Total Petrochemicals & Refining USA Inc.'s 408,000-tpy Bayport high-density polyethylene plant on the same site, the new HDA unit receives feedstock via pipeline from Total's nearby 225,500 b/d Port Arthur refinery, as well as third-party suppliers.
TRANSPORTATION — Quick Takes
Gorgon LNG starts production off Western Australia
Chevron Corp. has started LNG and condensate production at the Gorgon project on Barrow Island off the northwest coast of Western Australia. The first LNG cargo is expected to be shipped imminently.
The project is supplied from the Gorgon and Jansz-Io gas fields within the Greater Gorgon area, between 80-136 miles off the northwest coast of Western Australia (OGJ Online, Apr. 30, 2015). It includes a 15.6-million tonne/year LNG plant on Barrow Island, a carbon dioxide injection project, and a domestic gas plant with the capacity to supply 300 terajoules/day of gas to Western Australia.
The first LNG carrier arrived at the plant in December (OGJ Online, Dec. 18, 2015).
The Chevron-operated Gorgon project is a joint venture of the Australian subsidiaries of Chevron with 47.3% interest, ExxonMobil Corp. and Royal Dutch Shell PLC each with 25%, Osaka Gas Co. Ltd. 1.25%, Tokyo Gas Co. Ltd. 1%, and Chubu Electric Power Co. Inc. 0.417%.
Petronas expects FLNG facility to sail in 2Q
Malaysia's state-owned Petronas said its first floating LNG (FLNG) facility is expected to sail in the second quarter. A Mar. 4 naming ceremony marked completion of construction at the Daewoo Shipbuilding & Marine Engineering Co. Ltd. (DSME) shipyard in Okpo, South Korea.
The PFLNG (Satu) FLNG facility will be moored at Malaysia's Kanowit natural gas field off Sarawak (OGJ Online, July 29, 2015). It will have a capacity to produce 1.2 million tonnes/year of LNG. Kanowit lies in 80 m of water 200 km offshore eastern Malaysia.
DSME Pres. and CEO Sung Leep Jung said Petronas and DSME's consortium partner, Technip, achieved 17 million hr of no lost time injuries during the construction project.
