GENERAL INTERESTQuick Takes
CNRL links plan to Alberta debottlenecking
Canadian Natural Resources Ltd., Calgary, is linking its capital spending plan for 2019 to the debottlenecking of oil production in Alberta. Citing “a lack of market access and a dysfunctional pipeline nomination process” in Canada, the company plans a “base capital program” of $3.7 billion (Can.) in 2019, about $1 billion below its longer-term, “normalized capital program” and the outlay expected this year.
The base 2019 budget includes $3.1 billion in sustaining capital and $600 million for long-term growth projects.
But CNRL noted that crude prices in Canada rose after the Alberta government’s Dec. 2 announcement of a 325,000-b/d curtailment to production of crude and bitumen, starting in January (OGJ Online, Dec. 3, 2018). It said it will monitor effects of the production cut and progress on the planned but delayed expansions of the Keystone XL and Trans Mountain pipelines. “Dependent on the outcome of these two factors, Canadian Natural has the capability to adjust our 2019 capital spending budget closer to normalized levels,” it said, adding the adjustment could be as much as $700 million.
CNRL Pres. Tim McKay said the company plans to start steaming at its Kirby North steam-assisted gravity drainage project in the Athabasca oil sands region of Alberta in the third quarter this year and to begin production in the fourth quarter of 2019. Production is to reach 40,000 b/d in the first half of 2021.
The company also will start flow from new pads at its Primrose cyclic steam stimulation development in the Cold Lake region that eventually will add 26,000 b/d of production. “Production volumes from both thermal projects are strategically targeted to align with improved market access,” McKay said.
USGS: Fossil fuel extraction emissions fell in 2005-14
Estimated emissions from fossil fuel extraction on federal lands of the three main gases associated with climate change went down from 2005 to 2014, a US Geological Survey study said.
Releases of carbon dioxide fell 6.1% to 1,279 million tonnes over 10 years, it said. Methane releases in 2014 totaling an estimated 47.6 million tonnes of CO2 equivalent (CO2e) were 10.5% lower than in 2005, while the 5.5 million tonnes of CO2e for nitrous oxides in 2014 was 20.3% less than 10 years earlier.
It said the estimates represent the first accounting of emissions from fossil fuels produced on federal lands and from their combustion and growing capture and sequestration. “The estimates included in this report can provide context for future energy decisions, as well as a basis to track change in the future.”
Emissions from fossil fuels produced on federal lands represent, on average, 23.7% of national emissions for CO2, 7.3% for methane, and 1.5% for nitrous oxides over the 10 years included in this estimate, the study said. Amounts did not include operations on American Indian tribal lands.
The USGS study’s data are consistent with both rising US production and the increased use of gas to generate electricity, an American Petroleum Institute spokesman told OGJ on Nov. 26.
“That increase has played the most significant role in achieving 30-year lows in CO2 emissions from power generation that we see today,” he said. “America now leads the world in natural gas production—and gas output has doubled as overall methane emissions from the US gas system have fallen significantly—16%—since 1990.”
OMV, Sapura Energy enter partnership
OMV Exploration & Production GMBH will pay $540 million for a 50% stake in a newly formed joint venture company, SEB Upstream Snd. Bhd., under an agreement entered with Sapura Energy Bhd. (OGJ Online, Sept. 12, 2018).
Additional payment of as much as $85 million is possible based on certain conditions mainly linked to the resource volume in Mexico’s Block 30 at the time of the final investment decision. Both companies have agreed to refinance the existing intercompany debt of $350 million.
“The oil and gas demand is expected to increase by 20% until 2030 in Malaysia and OMV is taking the opportunity to capitalize on this growing market,” said Rainer Seele, chief executive officer and chairman of OMV Group.
The partnership’s management will be based in Malaysia and there will be equal representation on the board.
Based in Malaysia, Sapura Upstream holds an expected life of field production of 260 million boe. The company’s production entitlement in 2017 was 4.1 million boe/year from fields in Peninsular Malaysia. Sapura Upstream has two natural gas exploration and production blocks offshore Sarawak. First gas from the SK408 gas fields is expected in 2020 with a ramp-up in 2023 that could reach an estimated total plateau production entitlement of 21 million boe/year. The company also holds acreage in New Zealand, Australia, and Mexico.
Serica completes Bruce, Keith, Rhum deals
Serica Energy PLC, London, has become operator of Bruce, Keith, and Rhum gas fields in the UK North Sea after completing two deals through which it acquired interests from BP PLC, Total E&P UK Ltd., BHP Billiton Petroleum Great Britain Ltd., and Marubeni Oil & Gas (UK) Ltd. (OGJ Online, Nov. 6, 2018).
Serica’s interests now are 98% in Bruce field, 100% in Keith, and 50% in Rhum. Production of the fields net to Serica’s interests exceeds 23,000 boe/d, of which more than 85% is gas.
Exploration & DevelopmentQuick Takes
Lukoil, KazMunayGas sign Zhenis agreements
Lukoil and KazMunayGas have signed a joint operating agreement and finance agreement covering exploration and development of the Zhenis license area off Kazakhstan.
The companies agreed in principal earlier this year to form a partnership to seek exploration and production rights on the block, in 75-100 m of water 80 km offshore (OGJ Online, June 5, 2018). The companies next will negotiate an exploration and production contract with the Kazakh Ministry of Energy.
Wintershall gets 10% of Ghasha Concession
Wintershall Holding GMBH has received a 10% share of the Ghasha Concession covering development of Hail, Ghasha, Dalma, and other sour natural gas fields offshore Abu Dhabi.
The Abu Dhabi government and Abu Dhabi National Oil Co. earlier awarded a 25% interest in the concession to Eni (OGJ Online, Nov. 13, 2018). ADNOC retains a 60% interest.
The Ghasha project is expected to produce 1.5 bcfd of sour gas and 120,000 b/d of condensate.
It’s part of a plan by Abu Dhabi to increase gas production enough to meet domestic demand and possibly become a net gas exporter. ADNOC will increase gas production from onshore Shah field to 1.5 bcfd and develop sour gas at Bab and Bu Hasa fields, also onshore.
It also has formed a venture with Total to explore for gas in unconventional reservoirs in a large area west of existing production (OGJ Online, Nov. 12, 2018).
Talos lets contract for Zama field development
Talos Energy Inc. has let a concept and engineering services contract to McDermott International Inc. for a development project in Zama field—the first offshore Mexico block awarded to a private operator (OGJ Online, Sept. 18, 2018). The contract award is for engineering services, including concept selection and follow-on pre-FEED.
McDermott will execute the contract award with IO Oil & Gas Consulting, a joint venture of McDermott and Baker Hughes. McDermott will manage all phases of the engineering services process and will workshare engineers and designers in Mexico City and will receive support from IO and input from the customer. Based on the final concept solution from IO, McDermott will provide the follow-on pre-FEED services for development. Work on the concept selection has begun and is expected to be complete in third quarter 2019.
Discovered in July 2017, Zama field lies on Block 7 in the Sureste basin offshore in the Mexican Gulf of Mexico in 540 ft of water. Zama-1 was the first exploration well drilled offshore Mexico by a private sector operator. Talos estimates the field has 400-800 million recoverable boe, with an estimated peak production of 150 million boe/d. Appraisal activities are planned later this year with two additional wells. Start of production is expected by 2022.
Tullow farms in to licenses in the Comoros
Tullow Oil PLC has reached a deal with Discover Exploration Ltd. to farm in to Blocks 35, 36, and 37 offshore the Union of the Comoros in the Indian Ocean. Simultaneously, Discover agreed to acquire the entire issued share capital of Bahari Resources Ltd., its 40% joint venture partner in the Comoros PSC.
Following completion, which requires government approval, Tullow will operate the three blocks and hold a 35% working interest. Tullow will partly carry Discover for a 3D seismic survey planned for 2019 and for the first exploration well. Discover will hold a 65% non-operated working interest.
The blocks comprise an area of 16,063 sq km with a gross unrisked resource potential of up to 7 billion bbl of oil (+1.1 tcf of associated gas) in an oil case or 49 tcf of nonassociated gas (+2.3 billion bbl of condensate) in a gas case from two partly stacked prospects, Discover said.
Following ratification of the Comoros PSC in 2014, Discover and Bahari Resources acquired and interpreted circa 3,900 km of 2D seismic data and conducted a range of exploratory studies. Interpretation of the 2D seismic surveys, gravity and magnetic data, seep studies and regional studies identified many structural and stratigraphic traps in stacked Eocene and Cenomanian fans and basin modelling studies support a strong case for an oil charge in outer Rovuma delta.
Drilling & ProductionQuick Takes
Rystad: Permian gas flaring hits all-time high
Gas flaring in the Permian basin reached an all-time high in the third quarter as the persistent rise in production collided with severe takeaway capacity challenges, said Rystad Energy.
Rystad said gas flaring in the Permian averaged 407 MMcfd in the third quarter, and this number is likely to climb higher once final disposition figures are registered, given the substantial level of underreporting that still exists for September.
Rystad also expects flaring to rise well into 2019, reaching at least 600 MMcfd by mid-2019 assuming WTI oil prices recover to $60/bbl to support existing activity levels.
The energy research company also noted that, in Texas, there is an increased tendency whereby gas is flared on new wells for extended periods—often between 4-6 months—far beyond the 45-day period covered by the initial flaring permit.
Imperial reports start of work on oil sands project
Imperial Oil Ltd., Calgary, has let a contract to Babcock & Wilcox Enterprises Inc., Barberton, Ohio, to provide five industrial water-tube boilers for its Aspen oil sands project in Alberta.
Final investment decision to develop the $2.6-billion project—expected to produce 75,000 b/d of bitumen with the potential for further development of as much as another 75,000 b/d of bitumen—was made in early November (OGJ Online, Nov. 7, 2018). The project will include the first major commercial application of next-generation oil sands recovery technology designed to lower greenhouse gas emissions intensity and water use, while improving development economics, Imperial said.
B&W will design and supply the five MCFM 200-120 model boilers, which feature the company’s exclusive multi-circulation boiler technology, and modularized auxiliary components to provide steam for Imperial’s steam-assisted gravity drainage bitumen extraction operation.
Engineering work for the project is now under way and delivery is scheduled for fourth-quarter 2019 and first-quarter 2020.
Husky: White Rose oil spill from subsea flowline
Husky Energy Inc. reported that a survey by a remotely operated vehicle (ROV) showed a subsea flowline connection was responsible for an oil spill at White Rose field where production had been shut in on Nov. 15 due to inclemate weather.
The spill happened during the process of resuming operations on Nov. 16 (OGJ Online, Nov. 20, 2018). The ROV survey found no oil anymore at the spill source. Also, no oil had been observed at the surface since Nov. 16.
Operations will remain suspended until a full inspection is completed, and Husky has received the approval of the Canada-Newfoundland Offshore Petroleum Board. No human injuries were reported, but wildlife monitoring continues with a wildlife treatment center having been opened.
As of Nov. 26, Husky reported three birds were treated at the seabird rehabilitation center in St. John’s and another five birds had died.
Apache starts production from Garten development
Apache Corp. reported the start of production from its Garten development on Block 9/18a Area-W in the UK North Sea. The discovery well, drilled 6 km south of the Beryl Alpha platform, was placed on production in late November, less than 8 months after being drilled in March (OGJ Online, Mar. 23, 2018).
The discovery well at Garten encountered a downthrown structural closure with 778 ft of net oil pay in stacked, high-quality, Jurassic-aged sandstone reservoirs. The well is now producing 13,700 b/d of oil and 15.7 MMcfd of gas from the Beryl sand. Two lower zones also were tested, and all three zones will be commingled to maximize recovery.
Recoverable resource is expected to exceed 10 million bbl of light oil plus associated natural gas. Apache has 100% working interest in the Garten block.
In addition to being brought online ahead of the original target of first-quarter 2019, the field is “a unique technical achievement and represents Apache’s most complex smart well completion to date,” said Jon Graham, region vice-president, North Sea.
Garten is tied back to the Beryl Alpha platform, 180 miles northeast of Aberdeen.
ConocoPhillips completes Bayu-Undan infill program
The ConocoPhillips-led group at Bayu-Undan gas-condensate field in the Timor Sea reported the completion of its three infill well program. The third and final well was brought on line Dec. 3. A final investment decision for the program was made in January 2017 as part of the long-term development plan for the Bayu-Undan project. The program is comprised of two platform wells and one subsea well connecting into the existing offshore infrastructure.
The infill project came in 40% below budget and 3 months ahead of schedule. This has resulted in higher liquids production and increased offshore well capacity.
The wells were drilled with the Noble Tom Prosser rig, which has now been contracted by Adelaide-based Santos Ltd. to undertake a number of wells, including an appraisal of the recent Dorado oil discovery off Western Australia.
Santos also holds 11.5% of the Bayu-Undan joint venture and the onshore Darwin LNG facilities. Santos also has a 25% interest in the Barossa joint venture.
Barossa field, which lies in the eastern Timor Sea, is currently in front-end engineering and design phase and is the leading candidate to backfill the Darwin LNG plant when gas flow from Bayu-Undan ceases. A final investment decision for Barossa is expected late in 2019.
OIL starts CSS of well in Rajasthan
Oil India Ltd. has started what it says is India’s first cyclic steam stimulation (CSS) at its BGW-8 well in Rajasthan.
The well is in Baghewala field, where heavy oil was discovered in 1991. The state-owned company has experimented in the field with chemical floods and steam injection from portable generators. Belgrave Oil & Gas Corp. is assisting with the CSS work.
Sembcorp to modify FPSO for Cheviot field
Sembcorp Marine Rigs & Floaters Pte. Ltd. has been chosen to modify, repair, and extend the life of the Petrojarl Varg floating production, storage, and offloading vessel, which will anchor development of Cheviot oil field and satellites in the UK North Sea.
The wholly owned subsidiary of Sembcorp Marine Ltd. will conduct detailed engineering, fabrication, installation, and integration of the topside process skid; overhaul the existing internal turret and power generation; and repair and do life-extension work on the hull, tanks, and various systems onboard.
The engineering, procurement, and construction contract with Varg LLC, a wholly owned unit of Teekay Offshore Partners LP, Hamilton, Bermuda, is estimated to be worth $166 million.
The agreement will not take effect until the field operator, privately owned Alpha Petroleum Resources Ltd. of Guildford, UK, completes debt arrangements with a consortium of lenders and receives government approvals for its final development plan.
Cheviot formerly was named Emerald field, which was abandoned after recovery of only 8% of the original oil in place. Alpha plans to develop oil reserves at Cheviot and satellite Peel fields and the gas caps of Cheviot and satellite Padon field.
It estimates future recovery of at least 55 million bbl of oil and 120 bcf of natural gas.
The FPSO work is scheduled to be complete in July 2020.
Iguana gas field comes on stream off Trinidad
DeNovo Energy Ltd., a unit of Germany’s Proman AG, reported start of natural gas production from Iguana field offshore the west coast of Trinidad and Tobago in the Gulf of Paria. Once fully operational Iguana is expected to produce 80 MMcfd.
Operator of Block 1(a) and Block 1(b), DeNovo fast-tracked the project to production in just less than 3 years. Proman invested $250 million in DeNovo in 2015. Proman is the first downstream group to invest in Trinidad and Tobago’s upstream business (OGJ Online, Mar. 16, 2017).
PROCESSINGQuick Takes
Hanwha Total advances PE expansion at Daesan
Hanwha Total Petrochemicals Co. Ltd., a 50-50 joint venture of Hanwha Group and Total SA, will invest nearly $500 million to expand the polyethylene (PE) capacity of its Daesan refining and petrochemicals integrated complex in Chungnam Province, South Korea, about 145 km from Seoul.
The proposed project will increase PE capacity by about 60% to 1.1 million tonnes/year by yearend 2020, Total said.
Ethylene capacity at the site simultaneously will increase by 10% to 1.5 million tpy, the operator said.
The proposed project complements ongoing investments totaling $750 million to increase the Daesan complex’s ethylene production capacity by 30% to 1.4 million tpy by mid-2019 and to expand PE production capacity by 50% to 1.1 million tpy by yearend 2019 (OGJ Online, Dec. 11, 2017; Apr. 12, 2017).
The planned investments—which are intended to take advantage of competitively priced propane feedstock abundantly available due to the US shale gas revolution—will better position the Daesan complex to capture margins across the propylene-polypropylene value chain as it currently does in the ethylene-PE value chain, and allow the complex to meet local demand and supply Asia-Pacific’s growing polymers market.
Delek lets contract for Krotz Springs refinery
Delek US Holdings Inc. let a contract to a division of E.I. DuPont de Nemours & Co. to license technology for 74,000-b/sd refinery in Krotz Springs, La.
As part of the contract, DuPont Clean Technologies will supply its proprietary technology licensing and engineering services for a 6,500-b/sd STRATCO alkylation unit to enable the site to generate low-sulfur, high-octane, low-RVP alkylate with zero olefins, improving the quality and quantity of the refinery’s gasoline pool to meet increasingly strict clean fuel standards, DuPont said.
The unit also will allow the refinery to increase its production volume of gasoline while producing multiple grades of summer fuel, according to the service provider.
DuPont disclosed neither a value of the contract nor timeframe for the project’s completion.
The contract award, however, does follow Delek’s January announcement that it was building a 6,000-b/sd alkylation unit to add product flexibility and increase margin potential at the Krotz Springs refinery (OGJ Online, Jan. 9, 2018).
According to a filing with the US Securities and Exchange Commission, addition of the new alkylation unit would increase gasoline production at the refinery to 44,000 b/sd from 38,400 b/sd while simultaneously reducing output of lower-value products to 8,700 b/sd from 11,100 b/sd.
Previously estimated at an overall cost of $103 million, the now $113-million alkylation project is scheduled to be completed during first-quarter 2019, Delek said in a November presentation to investors.
TRANSPORTATIONQuick Takes
GAIL: Pipelay due on Barauni-Guwahati line
State-owned GAIL (India) Ltd. said pipe contracts recently awarded will allow construction to begin in December on a 453-mile natural gas pipeline between Barauni, Bihar, and Guwahati, Assam.
The spur line is part of the 2,110-mile Jagdisphur-Haldia-Bokaro-Dhamra system under construction in northeastern India.
GAIL said the larger project’s first phase will be completed within 2 months. Other phases, including the Barauni-Guwahati spur, will be completed sequentially by December 2021.
Open season launched for Jupiter crude oil pipeline
Jupiter Energy Group has launched a 90-day open season for binding shipper commitments on the Jupiter Pipeline, which is expected to be operational in fourth quarter 2020 (OGJ Online, Oct. 18, 2018).
Jupiter Pipeline will be a 650-mile, 36-in. crude oil system with origination points near Crane, Tex., and Gardendale-Three Rivers, Tex., and an offtake point in Brownsville, Tex.
As designed, it will be the only pipeline out of the Permian basin that can access all three deepwater ports in Texas—Houston, Corpus Christi, and Brownsville—and will have direct access to a fully capable very large crude carrier loading facility.
