OGJ Newsletter

March 9, 2015
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

Senate vote to override Obama's KXL veto falls short

The US Senate's vote to override President Barack Obama's veto of legislation authorizing construction of the proposed Keystone XL (KXL) crude oil pipeline fell 5 votes short of the necessary two-thirds majority (OGJ Online, Feb. 25, 2015). Sixty-two senators-including 4 Democrats-voted in the affirmative, while 37 voted no.

Sen. John Hoeven (R-ND), S. 1's sponsor, said he and other senators who support TransCanada Corp.'s proposed 1,179-mile pipeline from Hardisty, Alta., to Steele City, Neb., would continue to press for approval by attaching a similar measure to another must-pass bill "such as an energy, transportation, or appropriations bill."

The Mar. 4 vote does not end the fight for the project's approval, Sen. David Vitter (R-La.) said afterward. "Keystone obviously has wide bipartisan support across the country, yet President Obama and Senate Democrats have put their political agenda ahead of bipartisan compromise, job creation, and energy independence out of sheer political spite," he said.

Sen. Barbara Boxer (D-Calif.), the Environment and Public Works Committee's ranking minority member, said, "I'm glad the Republican leadership failed to override President Obama's veto of the Keystone XL pipeline, which does nothing for Americans and is a gift for Canadian big oil interests. It is time Republicans brought up legislation that will help Americans, like a highway bill or an equal pay for equal work bill."

American Petroleum Institute Pres. Jack N. Gerard said the Senate's attempt to override Obama's veto proved Washington is working for the people. "That's why Democrats and Republicans came together on this bill and that is why there are efforts to override the president's veto.

"While we urge Congress to continue to fight for KXL, there should be no need for congressional action if the president would make a final judgment on Keystone," Gerard said. "The president has always had the authority on this and he can approve this pipeline today."

ExxonMobil spending down 12% to $34 billion

ExxonMobil Corp. plans $34 billion in capital spending during 2015, representing a 12% decrease from 2014.

Further cuts are expected in 2016-17, when annual capital and exploration expenditures are expected to average less than $34 billion. Company spending peaked in 2013 when its budget was $42.5 billion (OGJ Online, Mar. 5, 2014).

"We are capturing savings in raw materials, service, and construction costs," explained Rex W. Tillerson, ExxonMobil chairman and chief executive officer.

During the next 3 years, the company expects to start up 16 major oil and natural gas projects and is on track to increase production to 4.3 million boe/d by 2017.

Production in 2015 is expected to rise 2% to 4.1 million boe/d, driven by 7% liquids growth. The increase is supported by the ramp up of several projects completed in 2014 and the expected startup of seven new major developments in 2015, including Hadrian South in the Gulf of Mexico, expansion of the Kearl project in Canada, Banyu Urip in Indonesia, and deepwater expansion projects at Erha in Nigeria and Kizomba in Angola.

In 2016 and 2017, production ramp up is expected from several projects including Gorgon-Jansz in Australia, Hebron in eastern Canada, and expansions of Upper Zakum in United Arab Emirates, and Odoptu in Far East Russia.

ExxonMobil said its downstream and chemical businesses, meanwhile, remain resilient in the lower commodity price environment and continue to generate solid cash flow, helped by abundant North American crude and gas supplies that have led to lower feedstock and energy costs.

Petrobras to divest $13.7 billion in 2015-16

Petroleo Brasileiro SA (Petrobras) plans to divest $13.7 billion in 2015-16, up from the previously reported $5-11 billion in the company's business and management plan for 2014-18.

In an effort to reduce leverage, preserve cash, and focus on priority investments, 40% of the divestment will comprise the company's gas and power segment, 30% exploration and production in Brazil and abroad, and 30% downstream.

Petrobras notes the $13.7 billion is sensitive to market conditions, and changes in those conditions could cause the company to adjust its plans.

Moody's last month revoked the company's investment-grade rating because of "concerns with the ongoing investigation of corruption and possible liquidity pressures that may arise if the company is not able to timely deliver its audited financial statements," Petrobras reported at the time.

The reduction came on the heels of the appointment of Alde Mir Bendine as the company's chief executive officer. Maria das Gracas Silva Foster, who previously served in the role, and five other senior executives resigned the week before amid the corruption scandal (OGJ Online, Feb. 9, 2015).

Moody´s noted that Petrobras may endure challenging times in the coming years while attempting to reduce its debt.

Exploration & DevelopmentQuick Takes

Total to take operatorship of Elk-Antelope field

Total SA has been unanimously voted operator of the joint venture operating Elk-Antelope gas field in petroleum retention license 15 in the eastern highlands of Papua New Guinea.

The move follows the defeat last month of legal action taken by Oil Search Ltd. and its Pac LNG Group Co. affiliates against Total's purchase of 40.1% interest in the permit from previous operator InterOil Corp. (OGJ Online, Feb. 11, 2015; Mar. 26, 2014). The International Chamber of Commerce arbitration panel in London dismissed Oil Search's claim that it had preemptive rights over shares in the field.

Total's appointment as new operator will take place through a transition plan in the terms of the JV operating agreement and is subject to approvals from the Papua New Guniea government.

Oil Search has accepted the arbitration decision and says it is willing to work constructively with Total and its other JV partners towards the development of the Elk-Antelope resource as soon as possible.

BOEM proposes lease sale for western gulf

The US Bureau of Ocean Energy Management (BOEM) will offer tracts covering nearly 22 million acres offshore Texas for oil and gas exploration and development-including all available unleased areas in the western Gulf of Mexico planning area-in Lease Sale 246 scheduled for Aug. 19 in New Orleans.

The sale will encompass 4,000 blocks covering 21.8 million acres and lying 9-250 miles offshore in 16-10,975 ft of water. BOEM estimates the proposed sale could result in production of 116-200 million bbl of oil and 538-938 bcf of natural gas.

The offshore sale is the eighth under the administration's Outer Continental Shelf Oil and Gas Leasing Program for 2012-17. The last western gulf lease sale drew 93 bids from 14 companies over 81 blocks covering 433,823 acres, totaling nearly $110 million in apparent high bids (OGJ Online, Aug. 20, 2014).

The first six sales netted $2.4 billion. The seventh gulf sale, central gulf Lease Sale 235, will be held on Mar. 18 (OGJ Online, Oct. 16, 2014).

Kosmos well establishes potential offshore Morocco

A noncommercial gas and condensate discovery offshore Morocco establishes exploratory potential of the frontier Laayoune basin, reports operator Kosmos Energy.

The CB-1 well on the 22,000-sq-km Cap Boujdour permit cut 14 m of net hydrocarbon pay in clastic reservoirs in a gross hydrocarbon-bearing interval of about 500 m. It will be abandoned.

Situated 170 km offshore in 2,135 m of water, the well was drilled to a total depth of 5,700 m at a net cost to Kosmos of $85 million.

"While not a commercial find, this first well in the basin has significantly derisked further exploration by demonstrating a working petroleum system, including the presence of a hydrocarbon charge, as well as effective trap and seal," explained Andrew G. Inglis, Kosmos chairman and chief executive officer.

Inglis said the Cap Boujdour block includes "a diverse range of independent plays and fairways with multiple prospects."

He said, "We will analyze the information gathered from CB-1 and integrate it with the additional 3D seismic data we recently acquired to refine our exploration plan, including deciding on the location and timing of a potential second well."

The Atwood Achiever drillship will now move to Mauritania to test the Tortue prospect, which has estimated resources of 2 billion boe recoverable across both Mauritania and Senegal (OGJ Online, Feb. 4, 2015).

Kosmos operates the Cap Boujdour license with 55% interest. The company has held exploration rights in the permit area since 2006 under a petroleum agreement with Morocco's Office National des Hydrocarbures et des Mines (ONHYM).

Partners are ONHYM 25% and Cairn Energy PLC's wholly owned subsidiary Capricorn Exploration & Development Co. Ltd. 20% (OGJ Online, Oct. 28, 2013).

Drilling & ProductionQuick Takes

Statoil, Sinochem submit POD for Peregrino Phase II

Statoil ASA and partner Sinochem have submitted a plan of development (POD) for the $3.5-billion Peregrino Phase II project to Brazil's National Agency of Petroleum, Natural Gas, and Biofuels (ANP).

Sanctioned in December, the project will extend the economic life of Peregrino field in the Campos basin offshore Brazil, adding 250 million bbl in recoverable resources.

The concept consists of a wellhead platform with a drilling rig, WHP-C, tied-back to the existing Peregrino floating production, storage, and offloading unit (OGJ Online, June 12, 2012). The facilities contain standalone power generation that will export power to WHP-A.

The number of production wells from Peregrino Southwest-not currently reachable by platforms A and B-will be increased to 21, of which 15 will be oil producers and 6 water injectors, all drilled from WHP-C in 120 m of water.

Based on the current plan, Phase II is expected to start production toward the end of the decade, but Statoil says it will adjust the schedule if necessary.

Peregrino has produced more than 90 million bbl of oil since production launched in 2011 (OGJ Online, Apr. 11, 2011). Sinochem took 40% interest in the field during the same year, completing its $3.07-billion acquisition from Statoil (OGJ Online, Apr. 15, 2011).

Shell withdraws application for Pierre River project

Shell Canada Ltd. has withdrawn its regulatory application for the proposed Pierre River heavy oil mine north of Fort McMurray.

The Pierre River Mine (PRM) application outlined a proposal for 200,000 b/d. The project "remains a very long-term opportunity for us, but it's not currently a priority," said Lorraine Mitchelmore, Shell Canada president and executive vice-president, heavy oil. "We will continue to hold the leases and can reapply in the future when the time is right," she said.

PRM had been joined with an application for a 100,000-b/d expansion of the Jackpine Mine, but Shell separated the applications in 2009. In 2013, a joint review panel recommended the Jackpine Mine expansion for approval (OGJ Online, July 10, 2013).

Tawke output to rise in Kurdistan region

Production from Tawke oil field in the Kurdistan region of Iraq will begin increasing this spring toward new capacity of 200,000 b/d, reports Bijan Mossavar-Rahmani, executive chairman of operator DNO ASA, Oslo.

Mossavar-Rahmani told a conference in Oslo that a new 24-in. pipeline will accommodate the production growth.

According to Genel Energy International Ltd., a partner in the Tawke production-sharing contract, the field had wellhead production capacity of 155,000 b/d at the end of 2013 and average output of 91,000 b/d last year.

DNO reported facilities capacity, before completion of the new pipeline, of 125,000 b/d.

The new pipeline connects Tawke field with the partners' Fish Khabur export facility to the west, which has a truck-loading station and tie-ins to export pipelines. It will supplement an existing 12-in. pipeline and truck-loading equipment in the field.

Mossavar-Rahmani said the company was completing the Tawke-30 well, the last horizontal producer in the current drilling campaign.

At yearend 2014, Tawke field had 28 wells, of which 26 were on production and 9 were horizontal.

In February, DNO said it was processing 3D seismic data in preparation for further drilling at the Peshkabir discovery of 2012, which is between Tawke field and Fish Khabur (OGJ Online, June 11, 2012).

Genel said appraisal will include a sidetrack of the Peshkabir-1 discovery well and drilling of the Peshkabir-2 well.

Peshkabir-1 encountered oil shows in Cretaceous, Jurassic, and Triassic intervals. Six zones were tested. The Jurassic Sargelu formation flowed 27-29° gravity oil at varying rates and water cuts.

Genel described the structure as a high-amplitude anticline that forms a mountain range on the surface with shallow layers outcropping on its flanks.

Tawke interests are DNO 55%, Genel 25%, and the Kurdistan regional government 20%.

PROCESSINGQuick Takes

Shell's Pearl GTL plant enters planned maintenance

Qatar Shell Ltd., a unit of Royal Dutch Shell PLC, has started a scheduled maintenance turnaround on one of two identical production trains at its Pearl gas-to-liquids (GTL) plant in Qatar's Ras Laffan Industrial City.

Planned maintenance activities at the train, which accounts for half of the plant's total GTL production capacity of 140,000 b/d, will continue for about 2 months, Shell said.

Shell, which operates Pearl GTL under a development and production-sharing agreement with Qatar Petroleum, did not disclose details on specific maintenance projects to be executed during the turnaround.

In late 2014, however, Shell Qatar did let a contract to a division of SNC-Lavalin Group Inc., Montreal, to provide long-term engineering, procurement, and construction management services related to plant changes, as well as minor base and medium projects for a new phase of the Pearl GTL project (OGJ Online, Dec. 11, 2014).

While no details have emerged regarding this "new phase" of Pearl GTL, SNC-Lavalin said the project would allow Shell Qatar to continue to enhance local development.

Launched in July 2006, major construction on the Pearl GTL project wrapped in 2010, with the gas processing plant starting production of condensate, LPG, and sulfur in March 2011 (OGJ Online, Mar. 23, 2011).

The complex, which also has the ability to produce 120,000 b/d of NGLs and ethane, ramped up to its full GTL production near the end of 2012.

In addition to producing kerosene, gas oil, and naphtha from GTLs, Pearl GTL uses Shell's patented process of converting natural gas into a clear base oil to produce Shell PurePlus technology base oils, which were formally introduced to the global market in a series of phased releases beginning in early 2014 (OGJ Online, Sept. 11, 2014).

Maintenance under way at Venezuelan refineries

Petroleos de Venezuela SA (PDVSA) is conducting both planned and unplanned maintenance work at three of its Venezuelan refineries.

At its 645,000-b/d Amuay refinery, which comprises part of the Paraguana Refining Center (CRP) in northwestern Venezuela's Falcon state, the company has undertaken a major overhaul of the plant's flexicoker and a flue stack, PDVSA said.

Work on the two units, both of which are in the process of restarting, is scheduled to be completed by end of first-quarter 2015.

While PDVSA also confirmed Amuay's Distillation Unit 1 and Hydrogen Reformer 3 are entering final phases of major maintenance, the company did not disclose a firm timeline for start-up of those units.

At the nearby 310,000-b/d Cardon refinery, which makes up the other half of CRP, PDVSA said minor maintenance and partial repairs remain ongoing at the plant's naphtha reformer and Distillation Unit 4.

The company, however, did not specify a timeframe for the completion of maintenance work at Cardon.

As of Feb. 26, crude oil throughputs at CRP averaged 613,800 b/d, or roughly 64%, of the complex's combined nominal capacity of 955,000 b/d, according to PDVSA.

The company also is in the process of restarting the fluid catalytic cracking (FCC) unit at its 146,000-b/d El Palito refinery near Pto. Cabello, Carabobo state.

The FCC, which underwent a precautionary shutdown earlier in the week following a disturbance in the compressed air system, was due to return to normal operations sometime on Feb. 26, according to PDVSA.

The emergency shutdown resulted in reduced crude oil throughputs at the refinery, which was operating with an average crude processing capacity of 121,000 b/d as of Feb. 26.

Despite local media reports that the refineries have more extensive issues that soon will lead to fuel shortages in Venezuela, PDVSA reiterated dispatch operations as well as fuel inventories at the CRP and El Palito production sites remain stable and within normal, planned levels.

MRPL commissions unit at Mangalore refining complex

Mangalore Refinery & Petrochemicals Ltd. (MRPL) has started the process of commissioning an integrated polypropylene unit at its refinery in Mangalore, India, following the recent completion of a modernization project designed to increase the capacity and flexibility of crude oil processing at the plant (OGJ Online, June 8, 2010).

The first propylene feed entered the polypropylene unit on Feb. 27, MRPL said in a filing to India's BSE Ltd. (formerly Bombay Stock Exchange).

The unit is due to begin commercial production of polypropylene shortly, according to the BSE filing.

Commissioning of the 440,000-tonne/year polypropylene unit, which will use the Mangalore refinery's fluidized catalytic cracking (FCC) production of LPG, light distillates, and propylene as feedstock, remains on schedule with MRPL's most recent timeframe for the project, which targeted the unit's start-up for late February (OGJ Online, Feb. 13, 2015).

Earlier in the year, MRPL confirmed start-up of other units in the refinery's Phase 3 expansion, including the 2.2 million-tpy FCC (OGJ Online, Aug. 27, 2014), a 650,000-tpy coker heavy gas oil hydrotreating unit (OGJ Online, May 15, 2014), and a 3 million-tpy delayed coking unit (OGJ Online, Apr. 4, 2014).

MRPL wrapped the long-delayed Phase 3 expansion and upgrading project in late 2014 after it completed start-up of the third train of a three-train sulfur recovery unit, a raw water treatment system, LPG mounded bullet storage tanks, and other related offsite facilities (OGJ Online, Nov. 13, 2014).

Announced in February 2010, the Phase 3 expansion project was designed to increase the refinery's complexity and profitability by increasing refining capacity to 15 million tpy as well as equip the plant to process lower-cost heavy, sour, and high-TAN crudes.

TRANSPORTATIONQuick Takes

TAP initiates contracts for offshore construction

Trans Adriatic Pip+eline (TAP) AG has launched two pre-qualification contracts for building the natural gas pipeline's 105-km offshore section through the Adriatic Sea.

The first prequalification comprises engineering, procurement, construction, and installation (EPCI) of the 36-in. OD pipeline between the coastlines of Albania and southern Italy at depths reaching 820 m, including associated landfall civil works in each country and survey, seabed, and precommissioning activities. The second prequalification process is for supply of offshore line pipes and coating, divided into three lots.

TAP intends to issue related invitations to tender by May, following the current selection stage. It issued a tender invitation for onshore pipeline sections last year (OGJ Online, Oct. 15, 2014).

The 870-km pipeline will ship gas from the Shah Deniz II field in Azerbaijan to Europe, connecting with the Trans Anatolian Pipeline (TANAP) near the Turkish-Greek border at Kipoi and crossing Greece, Albania, and the Adriatic Sea, before coming ashore in southern Italy.

TAP targets first gas sales to Georgia and Turkey for late 2018, with first deliveries to Europe following about 1 year later. TAP is owned by BP PLC 20%, State Oil Co. of Azerbaijan Republic 20%, Statoil AS 20%, Fluxys 19%, Enagas SA 16%, and Axpo 5%.

Gassco takes over as operator of Knarr pipeline

Gassco has taken over as operator of the Knarr pipeline, which will transport rich gas to the Shell-Esso Gas and Liquids (Segal) system and St. Fergus in Scotland.

Knarr is a gas and oil field about 100 km north of Statfjord in the northern North Sea.

"We've had a close and good collaboration with Knarr operator BG Norge Ltd. throughout the process of preparing the pipeline for operation," reports Svein Birger Thaule, Gassco executive vice-president for asset management.

Next, the firm will complete emptying water from the pipeline and start filling it with gas. Start-up is expected during the spring, Thaule said.

The Knarr gas pipeline joint venture owns the 12-in. pipeline, and also has technical responsibility for its operation.

Tied into the existing far north liquids and associated gas system (Flags), the new 106-km rich gas pipeline has a technical capacity of 1.7 million standard cu m/day.