OGJ Newsletter

Oct. 10, 2016
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

OPEC agrees to consider production cuts

Ministers of the Organization of Petroleum Exporting Countries have agreed to consider trimming aggregate member production by as much as 740,000 b/d in response to a halving over the past 2 years in the price of crude oil.

Crude prices jumped more than $2/bbl in New York on London in response to the news but remained below $50/bbl.

At an extraordinary meeting in Algiers, they said a group production target of 32.5-33 million b/d would "accelerate the ongoing drawdown of the stock overhang and bring the rebalancing [of the oil market] forward."

The OPEC Secretariat, customarily citing "secondary sources," this month reported average total production by group members in August of 33.24 million b/d.

In Algiers, OPEC ministers said a committee of representatives from member countries would recommend production levels of individual members and develop a framework for consultations with oil-producing countries outside OPEC.

The consultations would include "identifying risks and taking proactive measures that would ensure a balanced oil market on a sustained basis, to be considered at the November OPEC conference." That meeting will be Nov. 30 in Vienna.

Federal carbon price announced in Canada

Provincial governments in Canada are resisting the federal government's plan to impose a carbon price higher than most of them have in place.

Prime Minister Justin Trudeau announced a nationwide floor price on emissions of greenhouse gases while inaugurating debate in the House of Commons over ratification of the Paris agreement on climate change.

The price would start at $10/tonne of carbon dioxide and rise to $50/tonne in 2022.

Alberta Premier Rachel Notley said she won't support the move unless the federal government helps win approval for an oil pipeline linking her province with a Canadian coast. Alberta will impose a carbon tax of $20/tonne next year, increasing to $30/tonne in 2018.

The federal proposal meets stiff resistance in neighboring Saskatchewan, where Premier Brad Wall says the tax will devastate his province's economy.

Like Alberta, British Columbia has a carbon tax lower than that of the federal plan, but an increase is one of 190 conditions imposed by recent federal approval of a natural gas pipeline crucial to LNG development.

Quebec and Ontario have cap-and-trade plans but will have to ensure their emission cuts meet federal goals. Environment ministers of both provinces voiced approval of the federal plan.

Nova Scotia, which has aggressively cut emissions from power generation, is reported to be concerned about how Trudeau's initiative will raise prices of gasoline and other fuels.

Other provinces are still formulating climate policies.

Merger forms Double Eagle Energy Permian

Double Eagle Energy Permian LLC, Fort Worth, has been formed through the merger of Double Eagle Lone Star LLC and Veritas Energy Partners Holdings LLC, owning more than 63,000 net acres in the Midland basin.

The acreage, of which more than 70% is operated, is mainly in Midland, Martin, Howard, and Glasscock counties, Tex.

Double Eagle Lone Star was a unit of Double Eagle Energy Holdings II LLC, a portfolio firm of Apollo Natural Resources Partners Funds I and II. Veritas was a portfolio of investment partnerships managed by Post Oak Energy Capital LP, Houston.

Cody Campbell and John Sellers are co-chief executive officers of the new company. They held the same positions with Double Eagle Energy Holdings II. Hollis Sullivan, Veritas Energy president, becomes chairman of the new company.

Exploration & DevelopmentQuick Takes

Alaska's North Slope yields large light oil find

Two exploration wells and 126 sq miles of 3D seismic have confirmed 6 billion bbl of light crude in place on Caelus Energy Alaska LLC's Smith Bay state leases on Alaska's North Slope, the company reported.

Two exploration wells have confirmed 6 billion bbl of light crude in place on Caelus Energy Alaska LLC's Smith Bay state leases on Alaska's North Slope. Photo from Caelus.

The Caelus-Tulimaniq No. 1 (CT-1) and step-out Caelus-Tulimaniq No. 2 (CT-2) were drilled early this year, targeting a large Brookian submarine fan complex spanning 300 sq miles. Subsidiary Caelus Energy Alaska Smith Bay LLC drilled and logged both wells, encountering an extension of the accumulation 5.25 miles northwest of the CT-1 discovery at the CT-2 location. The operator encountered gross hydrocarbon columns in excess of 1,000 ft in each well. The CT-1 and CT-2 logged 183 and 223 ft of net pay, respectively. The wells were not flow tested due to seasonal time constraints, the company said, but extensive sidewall coring and subsequent lab analyses confirmed the presence of reservoir-quality sandstones containing 40-45° gravity oil.

Caelus plans to drill an additional appraisal well and acquire 3D seismic data over outboard acreage. The company believes the Smith Bay fan complex may contain 10 billion bbl of oil in place when the adjoining acreage is included. Due to the favorable fluids contained in the reservoir, Caelus expects to achieve recovery factors of 30-40%.

The US Energy Information Agency reported that Alaska's crude production dropped 6.8% month-over-month as of July and 2.6% year-over-year to 438,000 b/d.

Caelus owns a 75% working interest in 26 leases covering 117,000 acres in Smith Bay, about 150 miles west of Prudhoe Bay and 90 miles east of Barrow. The acreage is on state land offshore from the federal National Petroleum Reserve-Alaska.

Lundin completes Barents Sea appraisal well

Lundin Petroleum AB unit Lundin Norway AS has produced natural gas from Lower Triassic reservoir sections on its PL609 7220/11-3 A (Alta-3) reentry well in the southern Barents Sea. The well lies east of the Alta discovery, which is estimated to contain gross contingent resources of 125-400 MMboe.

The original Alta-3 well was drilled in 2015 and encountered a 120-m gross hydrocarbon column. The reentry well was designed to further assess the quality of the Permo-Carboniferous carbonate reservoir and to conduct injection and production tests, Lundin said. It was the first of three wells in the operator's 2016 drilling campaign on the Loppa High, and it was drilled to a TD of 2,575 m, MD of 2,389 m, and in 400 m of water (OGJ Online, July 21, 2016).

The operator performed three tests-two of which injected 5,000 and 18,200 bbl of seawater below the oil-water contact in the Falk and Orn formations, respectively. The operator produced 21 Mscfd of gas in third test through a 1-in. choke from the Lower Triassic reservoir.

Pressure data from the Alta-3, Alta-3A, and Alta-3AR indicate good communication with the two previously drilled wells on the Alta discovery (OGJ Online, Sep. 30, 2015). Lundin Petroleum Pres. Alex Schneiter said, "Further appraisal over the Alta discovery will be required during 2017 to fully delineate this large structure."

Once the Leiv Eiriksson rig has plugged and abandoned the Alta-3 well, it will move 60 km to the north on PL609 to reenter the suspended well 7220/6-2 to complete the drilling of the Neiden prospect, which is estimated to contain gross unrisked prospective resources of 204 MMboe.

North Sea well delivers heavier-than-expected oil

Independent Oil & Gas PLC (IOG) says a sample from its first appraisal well on the Skipper oil discovery of the northern North Sea indicates 11° gravity oil, "a significantly higher viscosity than expected."

Skipper lies on Block 9/21a in license P1609, where IOG is sole owner and operator. In July and August, the firm drilled the well to a TVD of 5,578 ft and retrieved oil samples as it moved toward a development plan (OGJ Online, Aug. 22, 2016).

The firm says the measurements do not align with its observations and therefore the remaining samples need to be reviewed and tested. The next steps will then be reservoir modeling to consider potential development options. Determining commerciality may therefore take several months.

"The analysis of the oil retrieved from the appraisal well indicates that Skipper is a heavy oil discovery with similar gravity to other nearby heavy oil fields," explained Mark Routh, IOG chief executive officer. "We have observed that the oil moves in the reservoir and is mobile at surface at ambient conditions."

IOG notes the crest of the Skipper reservoir in the appraisal well was found to be 44 ft shallower than prognosed. As a result, the firm's estimate of the most likely oil in place has increased to 142.6 million bbl from 136.5 million bbl in the 2013 competent persons report.

The quality of the sands, although not cored, suggested permeabilities of more than 10 darcies, which is better than previously assumed, the firm says.

BP's Bight drilling plan approval delayed again

Australia's offshore oil and gas regulator National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) has asked BP PLC to supply more information about its plans to drill the Stromlo-1 wildcat in the Great Australian Bight offshore South Australia.

NOPSEMA says it needs the data to decide whether the company's environmental plan is acceptable, although it has not said exactly what part of the plan lacked the detail it requires. The regulator merely said the request for more information was a normal part of its assessment of an environmental plan.

BP has already had two environmental plans for drilling in the Bight rejected following NOPSEMA's finding that they did not meet regulatory requirements.

The request is not an invitation to resubmit the plan or rejection, so the project is still in limbo.

BP says NOPSEMA has neither rejected nor accepted its environmental plan. The latest move is a request to clarify aspects of the company's plan and for BP to supply information that has not been included in the data submitted so far.

NOPSEMA has requested the information by Oct. 28, although it also said BP can request more time if needed.

It now appears that even if acceptance of the plan is forthcoming after this latest request, the timeframe for spudding the well this year will be extremely tight.

Drilling & ProductionQuick Takes

DEA submits PDO for Norwegian Sea's Dvalin field

DEA AG, Hamburg, has submitted the plan for development and operation (PDO) of Dvalin field, previously known as Zidane field, to Norway's Ministry of Petroleum and Energy.

Production is slated to begin in 2020. A total volume of 18.2 billion cu m of natural gas from two reservoirs is expected to be produced from the Dvalin license. Development cost is estimated at €1.1 billion.

Dvalin will be developed with a four-well subsea template connected to the Heidrun platform (OGJ Online, Mar. 18, 2013). Gas will be processed at Heidrun in a new module before being transported in a new export pipeline connected to the 482.4-km Polarled pipeline. It will then move to the Nyhamna onshore gas terminal, where it will be processed and transported to the European market.

"Together with our partners, we have come up with a development solution with sustainable long-term economics in an environment of low market prices," commented Hans-Hermann Andreae, managing director of DEA Norge AS. Dvalin is DEA's first operated field development project in Norway.

The firm cites "creative work in the project team and market developments in the supplier industry" as making the project economically sound. "Over the last few years we have managed to reduce cost by more than 20%," said Andreae. "As a consequence, DEA has got the opportunity to open a new area in the Norwegian Sea for gas production and export."

Dvalin field is on Blocks 6507/7/9 and 6507/8 of PL435 in the Norwegian Sea, 15 km northwest of Heidrun and 290 km from Nyhamna in Norway.

DEA lets contracts for Dvalin project

DEA has let a contract to Aker Solutions for the Dvalin project's subsea production system in the Norwegian Sea. Aker will build a 300-ton subsea template for four wells and also will build the umbilical to be connected with the Heidrun platform.

DEA also let a contract to Aibel to ready the Heidrun platform to receive production from Dvalin. Aibel will build a 400-tonne injection system and a 4,000-tonne module for gas treatment. Aibel said they are to be installed in 2018 and 2019, respectively. Construction work will be carried out at the Aibel yard in Haugesund, Norway.

Topside modifications for tie-in of Dvalin to Heidrun will be planned and executed by the Heidrun operator, Statoil ASA.

BP: Output shut from Clair platform after oil release

BP PLC reported that the Clair platform, 75 km west of the Shetland Islands, has been taken offline after "a quantity of oil in water" was released into the North Sea early Oct. 2.

The most likely volume of oil to sea has been calculated from platform data as around 95 tonnes, or about 700 bbl, BP said.

The firm said on Oct. 3 the incident resulted from a technical issue with the system designed to separate the mixed production fluids of water, oil, and gas. The release was stopped within an hour once the issue had been identified.

BP will keep output from the platform shut "for the time being" as it investigates the cause of the technical issue.

BP, international industry-funded cooperative Oil Spill Response Ltd., and the UK's newly formed Department for Business, Energy, and Industrial Strategy have been working together to assess any potential environmental impacts and to determine the best response.

BP believes "the most appropriate response is to allow the oil to disperse naturally at sea, but contingencies for other action are being prepared."

Oil has been observed on the sea surface. Both direct observation and oil-spill modelling indicate the oil to be moving in a northerly direction away from land, the firm said.

PROCESSINGQuick Takes

IOC approves projects for Barauni, Panipat refineries

State-owned Indian Oil Corp. Ltd. (IOC) has reached final investment decision on its previously announced proposal to increase oil processing capacity at the company's 6 million-tonne/year Barauni refinery in Begusarai District, Bihar.

At a Sept. 29 meeting, the company's board approved an investment of 82.87 billion rupees for a project that includes expanding crude processing capacity to 9 million tpy and adding a downstream polypropylene unit at the Barauni refinery, IOC said in a Sept. 30 filing to the National Stock Exchange of India Ltd. and BSE Ltd. (formerly Bombay Stock Exchange).

The board also approved a separate investment of 15.27 billion rupees at the Sept. 29 meeting for projects at the company's 15 million-tpy Panipat refinery and petrochemical complex in Haryana north of New Delhi.

Alongside ongoing implementation of an olefin-recovery project, the Panipat investment will cover an expansion of the complex's existing naphtha cracker, a revamp of the monoethylene glycol (MEG) plant, and modifications to a benzene expansion unit, the company said.Upon first announcing the project in 2015, IOC said it will execute the Barauni expansion project in two phases.

A detailed configuration study and technoeconomic evaluation for Phase 1 of the expansion-which will boost capacity by 1 million tpy to 7 million tpy-remain under way, with the project scheduled for execution in 2016-17, India's Ministry of Petroleum and Natural Gas (MPNG) said.

Phase 2, which will add the remaining capacity increase of 2 million tpy, is due to be completed by 2020-21, MPNG said.

A final timeline for the Panipat olefin-recovery project has yet to be disclosed, but implementation, which began in 2015, remains ongoing, IOC said in its latest annual report.

Shell commissions unit at Pernis refinery

Royal Dutch Shell PLC has commissioned an aromatics unit and started construction on another at subsidiary Shell Nederland Raffinaderij BV's 404,000-b/d Pernis refinery and integrated petrochemical production site in Rotterdam, the Netherlands.

Completed several months ahead of schedule, the new heart-cut splitter at Pernis entered service on Sept. 15, Shell said.

Benzene from the unit will be transported via pipeline 35 km away to Shell's Moerdijk chemical plant between the major ports of Rotterdam and Antwerp, Belgium, where it will serve as feedstock for production of styrene monomer.

The aromatics unit comes as part of the firm's plan to increase flexibility and competitiveness of its operations through further integration of its refining and chemicals businesses.

The use of its own feedstock will allow Shell to continue increasing the profitability of its European chemicals business, Ryerkerk said.

Shell also confirmed on Sept. 15 that it has started official construction on a solvent deasphalting (SDA) unit to be added at the Pernis refinery. Designed to remove heavier fractions from crude oil feedstock to help boost production of lighter, higher-quality products with improved environmental performance, the SDA unit will equip the refinery with more flexibility to change its production slate to a different product mix in response to current market conditions.

The SDA unit remains on schedule to be completed sometime in 2018, Shell said. Badlands plans first US Gulf Coast merchant AO plant

Badlands NGLs LLC, Denver, has let a contract to S&B Engineers & Constructors Ltd., Houston, to build the first merchant alpha olefins (AO) plant at the US Gulf Coast for on-purpose manufacturing of polyethylene co-monomers 1-butene and 1-hexane. S&B will provide engineering, procurement, and construction services for the grassroots project, Badlands said.

Configured with production capacities of 93,000 tonnes/year for 1-butene and 141,000 tpy for 1-hexene, the AO plant is scheduled for startup during second-half 2018, Badlands said.

A value of the EPC contract was not disclosed.

Alongside the announcement, Badlands also confirmed that it has signed a 15-year agreement with an unidentified petrochemical and polymers marketer for 100% offtake of the proposed AO plant's output.

Badlands currently is considering two alternative US Gulf Coast sites for the project, both of which offer close proximity to water transportation routes to enable shipments to US and international customers alike.

The company said it expects to make a final site selection for the AO plant in the next few weeks.

In contrast to the oligomerization process typically used to manufacture polyethylene co-monomer AOs that manufactures a range of up to 14 different products in set ratios-including 1-hexene and 1-butene-the proposed AO plant will use proprietary ethylene metathesis technology processes to produce on-purpose 1-butene and 1-hexene to meet market demand without extraneous output of nonpolyethylene co-monomer AO products, Badlands said.

Already licensed by Badlands from an unidentified provider, the proprietary processing technology will yield 1-butene and 1-hexene products via ethylene dimerization and trimerization, respectively.

TRANSPORTATIONQuick Takes

IEnova closes purchase of Pemex stake in line JV

Infraestructura Energetica Nova SAB de CV (IEnova), a Mexican unit of Sempra Energy, San Diego, has completed its acquisition of Pemex Transformacion Industrial's 50% equity interest in the Gasoductos de Chihuahua joint venture for $1.14 billion.

IEnova's shares in the JV now increase to 100% from 50%. Pemex will retain 50% shareholder interest in the Ramones II Norte pipeline project through Ductos y Energeticos del Norte S de RL de CV. The assets in the deal comprise three natural gas pipelines, an ethane pipeline, and a LPG pipeline, and associated storage terminal.

IEnova develops, builds, and operates energy infrastructure in Mexico. As of Dec. 31, 2015, the firm had invested more than $4 billion in operating assets and projects under construction in the country.

Gazprom gets survey permit for TurkStream pipeline

PJSC Gazprom has received a survey permit for two strings of the 63 billion-cu m TurkStream natural gas pipeline's offshore section in Turkey's territorial waters.

Gazprom and Petroleum Pipeline Corp. (Botas) signed a memorandum of understanding on Dec. 1, 2014, to construct TurkStream.

The pipeline will extend 660 km along the old route of the South Stream gas line and cover 250 km of a new route toward the European portion of Turkey. The first string is planned to exclusively supply gas to the Turkish market.

Gazprom this month also secured TurkStream's first construction permit for its offshore section from Turkish authorities.

The offshore line will consist of four strings with a capacity of 15.75 billion cu m each.