OGJ Newsletter
GENERAL INTEREST Quick Takes
Wintershall switches Mittelplate land base to renewable power
Wintershall Dea switched the power supply to Mittelplate drilling and production island in the Schleswig-Holstein Wadden Sea National Park to 100% certified electricity from renewable sources, making Mittelplate the first oil field in Germany to be produced solely with green electricity (OGJ Online, Jan. 28, 2013).
Previously, Middleplate electricity primarily was generated from a turbine on the island driven by associated gas extracted along with crude oil. Wintershall Dea is discontinuing power generation from the gas turbine and will get all its power from the mainland exclusively from renewable sources. This also applies to all other facilities belonging to the Holstein Production District on the mainland, such as treatment plants and offices in Friedrichskoog, as well as landing stage in Cuxhaven.
In terms of direct emissions, in 2018 the international oil and gas industry emitted on average 17.4 kg CO2/boe produced. By comparison, Mittelplate emitted just 3.6 kg CO2/boe in 2019. As a result of measures such as shutting down the turbine and changing power supply, Wintershall expects to emit only 0.4 kg/boe in 2021.
By 2021, Wintershall Dea will switch all production locations in Germany to certified electricity generated from renewable sources.
BHP to acquire Shenzi interest from Hess
BHP, operator of Shenzi field in the deepwater Gulf of Mexico, agreed to acquire Hess Corp.’s 28% working interest in the field for $505 million.
Shenzi, a six-lease deepwater development, produced an average of 11,000 net boe/d (90% oil) in the first 8 months of 2020.
Structured as a joint ownership, BHP currently holds 44% with partners Hess (28%) and Repsol SA (28%). The acquisition would bring BHP’s working interest to 72%.
The transaction, subject to customary closing conditions, is expected to close before yearend with an effective date of July 1, 2020.
Occidental sells onshore Colombia assets
Occidental Petroleum Corp., Houston, signed an agreement to sell its assets onshore Colombia to The Carlyle Group for $825 million, with $700 million up front and the remainder payable subject to certain production and commodity price targets.
The transaction, which is expected to close in fourth-quarter 2020, includes operations and working interests in the Llanos Norte, Middle Magdalena, and Putumayo basins. Occidental will retain a presence in the country with offshore Colombian exploration blocks.
Occidental has announced over $2 billion of divestitures in 2020 that are expected to close by yearend and continues to advance additional asset sales (OGJ Online, Aug. 19, 2020).
Petrobras starts process to sell Albacora, Albacora Leste assets
Petróleo Brasileiro (Petrobras) has started the opportunity disclosure stage (teaser) for sale of its entire stake in the Albacora and Albacora Leste concessions in the northern part of the Campos basin, offshore Brazil.
The fields have established oil production from high-quality Cretaceous and Tertiary (Eocene, Oligocene, and Miocene) reservoirs.
The 455-sq km Albacora field, in water depths of 100-1,050 m, lies about 110 km from Cabo de São Tomé on the northern coast of Rio de Janeiro. In August, it produced 38,700 b/d of oil and 716,000 cu m/d of gas. Petrobras is operator with 100%. Its main producing reservoirs comprise high-quality, stacked, turbiditic sandstones of the Carapebus formation. Robust field reservoir characterization is underpinned by recent 4D and 3D seismic surveys and seismic attribute analysis. A number of horizontal and deviated well penetrations exist across the block. An extended well test is under way at the Forno discovery with results expected this year’s fourth quarter.
The 511.56-sq km Albacora Leste field lies in water depths of 1,000-2,150 m about 120 km from Cabo de São Tomé. In August, Albacora Leste produced 33,300 b/d of oil and 707,000 cu m/d of gas. The field comprises high quality turbiditic sandstone reservoirs with primary stratigraphic traps and secondary structural components. Upcoming drilling and workover activities are projected to increase near-term production and sustain extended production plateau. Presalt development is focused on the Arapuçá discovery (well tie-back planned for 2023). Petrobras is operator with a 90%. Repsol Sinopec Brasil holds the remaining 10%.
As part of the sale process, prospective buyers will be able to submit an offer on Albacora or Albacora Leste, or both.
Exploration & Development Quick Takes
Equinor submits POD, lets contracts for Breidablikk development
Equinor and partners submitted plans to the Norwegian Petroleum Directorate to develop Breidablikk oil field (previously called Grand, license 169 B2) in the Norwegian Continental Shelf (NCS), northeast of Grane field in the North Sea about 185 km west of Haugesund. Investments for Breidablikk will total around 18.6 billion kroner. Startup is expected in 2024.
Breidablikk consists of the 25/11-27 discovery (F structure) and the 25/8-4 discovery (D structure). The field will be developed with four subsea templates, each with six slots. The templates will be tied into and controlled from the Grane platform. The plan calls for 23 production wells, and oil will be processed and exported via Grane to the Sture terminal in Hordaland county.
Equinor awarded a contract to Aker Solutions for delivery of the subsea production system, valued at about 2.5 billion kroner, including options. The contract covers the delivery of the four subsea templates and up to 23 subsea trees and associated components.
Wood PLC was let a contract to provide engineering, procurement, construction, and installation (EPCI) services worth $84 million. Wood will deliver all topside modifications at the Grane installation in preparation for tie-back of Breidablikk subsea development. Modifications will include integration of new pipelines and an umbilical, as well as increasing capacity for produced water at the facility.
Total recoverable reserves from Breidablikk are estimated at 30 million standard cu m of oil (200 million bbl).
Equinor operates Breidablikk with 47.5%. Partners are Petoro AS 30%, Vår Energi 10%, and ConocoPhilips Skandinavia AS 12.5%.
Origin begins fracturing Beetaloo basin well
Origin Energy Ltd. started fracturing activities on the Kyalla-117 well in the Velkerri liquids-rich gas play in the Beetaloo subbasin, Northern Territory, Australia.
Origin, in joint venture with Falcon Oil & Gas, drilled the well in January, but was forced to suspend fracturing plans when the COVID-19 pandemic caused state border closures and consequent restrictions on movement of personnel and equipment (OGJ Online, Dec. 10, 2019).
The well is seen as a test of frontier Beetaloo sub-basin region potential.
The Kyalla-117 appraisal, near Daly Waters, was drilled to a total depth of 3,809 m with a 1,579 m lateral section. During drilling, elevated gas shows associated with relatively high liquids content were encountered in all three of the target reservoirs—the Velkerri, Hayfield, and Kyalla formations.
Fracturing of the zones will be followed by production testing.
Initial results are expected by yearend with full results available during first-quarter 2021.
Origin is financing current operations, up to $25 million (Aus.), as part of its farm-in agreement with Falcon.
Origin is operator with 77.5%. Falcon holds the remaining 22.5%.
ConocoPhillips lets contracts for Tommeliten Alpha development
ConocoPhillips has let contracts to Aker Solutions for modifications on the Ekofisk installations to integrate the Tommeliten Alpha discovery, offshore Norway.
The front-end engineering and design (FEED) contract starts immediately and is expected to be completed in second-quarter 2021. The service company values the contract at 130 million kroner. The contract includes an option for the engineering, procurement, construction, and installation (EPCI) work following the completion of the FEED, subject to Norwegian authorities’ approval of the plan for development and operation and a new award decision by the Tommeliten Alpha partnership.
The FEED work will be led by Aker Solutions’ office in Stavanger, Norway.
A contract to deliver the subsea production system for the development also was awarded to Aker Solutions. The estimated contract value is 1.2 billion kroner. The scope of work covers a complete subsea production system including 10 vertical subsea trees, two manifolds, wellheads, satellite structures, control systems, and tie-in equipment.
Tommeliten Alpha, in the southern part of the Norwegian sector in the North Sea some 25 km southwest of Ekofisk field, was proven in 1977. Water depth at the site is 75 m. The reservoir, at a depth of 3,000 m, contains gas and condensate in chalk in the Paleocene Ekofisk formation and Upper Cretaceous Tor formation. Four wells were drilled on the discovery, the last one in 2003, according to the Norwegian Petroleum Directorate web site. Development of Tommeliten Alpha has been stopped two times at the concept selection stage. Different alternatives for a development of the discovery are being studied, all based on a tie-back to Ekofisk.
ConocoPhillips Skandinavia AS is operator for the Greater Ekofisk Area (35.11 %). Other license owners are Total E&P Norge AS (39.90 %), Vår Energi AS (12.39%), Equinor Energy AS (7.60 %), and Petoro AS (5.00 %).
Drilling & Production Quick Takes
President Energy progresses Las Bases Concession well development
President Energy expects well LB-1001 in the Las Bases Concession, Rio Negro, Argentina, to be on production by the end of November, subject to successful testing, following net gas pay in line with pre-drill expectations and in line with the offset former LB-x1 producing well (OGJ Online, July 13, 2020).
The development well was drilled to target depth of 1,700 m. A full suite of open hole electronic logging has been performed and the well was successfully cased and cemented. Costs for drilling, casing, completing, and testing are expected to be within the $1.9-million budget.
Electronic logs indicate a total of 54 m net gas pay spread among six formations. The main formations of interest show generally good permeability and 15-20% porosity. The results support pre-drill probable (P50) expectations both to initial gas production (100,000 cu m/d or 588 boe/d) and targeted reserves of 6 bcf, subject to testing and reservoir performance under production conditions.
The drilling rig is preparing to move to exploration well EVN-1, while the workover rig is moving to LB-1001 for completion and preparation for testing.
President Energy is operator in the Las Bases Concession with 90% interest. Empresa de Desarrollo Hidrocarburífero Provincial SA holds the remaining 10%.
Strike Energy starts West Erregulla appraisal campaign
Strike Energy Ltd. started the West Erregulla appraisal campaign, onshore Perth basin, with spud of the first well by the Easternwell 106 drilling rig.
Up to three appraisal wells, drilled to about 5,000 m, will be drilled. West Erregulla 3 (WE-3) is designed to test the continuation of the commercial gas accumulation in the northern fault block, and West Erregulla 4 (and 5) will appraise the reservoir distribution in the central fault block.
The 26-in. surface hole section for WE-3 was successfully drilled to 1,210 m TD final section depth. The drilling assembly has been pulled out of hole and running of the 20-in. surface casing has begun. The casing will be run to depth and then cemented in place. Operations will then proceed to the first intermediate section with a 17.5-in. drilling assembly to be run in hole and commence drilling to a nominal section depth of 2,740 m.
After coring and logging operations, all three wells will be flow tested (on success) and completed as future producers across the Kingia-High Cliff sequences for the proposed Phase 1 production operations. The Wagina gas discovery, made in West Erregulla-2, will be appraised during the West Erregulla 4 and 5 wells.
Strike Energy is operator (50%) in EP469 with joint venture partner Warrego Energy (50%).
Bahamas Petroleum to spud Perseverance #1 in December
Bahamas Petroleum Co. (BPC) will drill Perseverance #1, offshore Bahamas, utilizing the Stena IceMAX drilling rig. Well spud is expected 3-4 days following the rigs arrival in the B-North segment of the Cooper license on Dec. 15 (OGJ Online, Feb. 26, 2020).
The Stena IceMAX is a harsh environment DP class 3 drillship capable of drilling in water depths up to 10,000 ft with a fully integrated managed pressure drilling system.
Perseverance #1 will be drilled to a depth of 4,800-5,600 m. It is targeting 0.77 billion bbl recoverable P50 oil resources with an upside of 1.44 billion bbl.
BPC 100% owns and operates Perseverance #1.
PROCESSING Quick Takes
Irving Oil terminates deal to buy NARL Come-by-Chance refinery, assets
Privately owned Irving Oil Ltd., Saint John, NB, has cancelled its previously announced agreement with Silverpeak, a New York-based investment management firm, to acquire the Silverpeak-North Atlantic partnership’s North Atlantic Refining Corp., which includes NARL Refining LP’s 130,000-b/d refinery at Come-by-Chance, Newf., as well as a network of retail sites and other marketing assets (OGJ Online, May 28, 2020).
The purchase agreement has been terminated, but confidentiality provisions of the agreement prohibit further comment at this time, Irving Oil said on Oct. 6.
NARL Refining—which paused production activities at Come-by-Chance refinery in late March to ensure safety of its employees, their families, and operations amid the coronavirus (COVID-19) pandemic—previously announced it was in the process of undertaking projects aimed at increasing crude flexibility and efficiency at the refinery as part of the operator’s strategy to support the site’s long-term viability and competitive advantage (OGJ Online, Apr. 1, 2020; Aug. 1, 2019; July 8, 2019).
Irving Oil owns and operates its 320,000-b/d St. John refinery in the eastern Canadian province of New Brunswick, as well as the 75,000-b/d Whitegate refinery in County Cork, Ireland.
Shell lets contract for Moerdijk ethylene complex
Royal Dutch Shell PLC has let a contract to TechnipFMC PLC to provide engineering, procurement, and module fabrication (EPF) for proprietary equipment and related services for eight ethylene furnaces at Shell Nederland Chemie BV’s 971,000-tonnes/year Moerdijk petrochemicals complex in the Netherlands.
Based on TechnipFMC’s multi-lane radiant coil design, the new steam cracker furnaces will replace 16 older units to increase energy efficiency and reduce greenhouse gas (GHG) emissions at the complex without reducing capacity at the complex, the service provider said on Sept. 30.
The furnaces will be shipped to the site in modules, enabling the cracker to maintain continuous operation throughout the upgrading project, according to TechnipFMC.
The new steam cracker furnaces are anticipated to reduce the Moerdijk complex’s carbon dioxide (CO2) emissions by about 10%.
TechnipFMC—which did not disclose a timeframe for its work on the project—valued the EPF contract at between $75-250 million.
Shell’s investment in the furnace revamp at Moerdijk comes as part of the operator’s ambition to become a net-zero emissions energy business by 2050 or sooner, said Thomas Casparie, executive vice-president of Shell’s global chemicals business, on Sept. 4.
Shell said it expects work on the Moerdijk upgrading project to be completed in 2025.
CNOOC’s Huizhou refinery ramps up VGO hydrotreating unit capacity
CNOOC Oil & Petrochemicals Co. Ltd., the refining arm of China National Offshore Oil Corp. (CNOOC), has completed successful performance testing of a previously commissioned vacuum gas oil (VGO) hydrotreater at subsidiary CNOOC Huizhou Petrochemicals Co. Ltd.’s two-phased 440,000-b/d Huizhou refinery in China’s Guangdong province (OGJ Online, Jan. 11, 2019).
Completed as of Sept. 24, the performance test certifies that the unit—based on E.I. DuPont de Nemours & Co. division DuPont Clean Technologies’ proprietary IsoTherming technology—is meeting performance guarantees, DuPont said.
Initially commissioned in late-September 2017 but operated at lower rates until recently due to market-driven reductions to throughputs at the refinery, the Huizhou IsoTherming VGO hydrotreater is designed to process 51,419 b/d of VGO into feedstock containing less than 1,000 wppm sulfur and less than 600 wppm nitrogen for the refinery’s FCC unit, according to DuPont.
The service provider did not disclose details regarding when the IsoTherming VGO hydrotreater would reach full operating rates.
DuPont did reveal, however, that CNOOC’s Huizhou refinery also chose the IsoTherming technology for a 71,637-b/d ultralow-sulfur diesel hydrotreating unit also commissioned in September 2017 at the site.
Keyera restarts Wapiti gas plant
Keyera Corp. has resumed operations following an unplanned outage that began in mid-August at its Wapiti natural sour gas processing and liquid stabilization plant about 60 km south of Grand Prairie, Alta. (OGJ Online, Aug. 25, 2020).
Keyera restarted operations at the Wapiti plant on Sept. 25, the operator said.
Wapiti’s restart follows the Aug. 17 halt of operations at the site due to an issue relating to the plant’s waste heat recovery system. The unplanned outage was extended indefinitely on Aug. 27 (OGJ Online, Aug. 28, 2020).
Keyera disclosed no further details regarding the total scope of the initial problem or root cause of the outage.
Keyera commissioned Phase 1 of the Wapiti gas plant in May 2019 with gas processing capacity of 150 MMcfd and condensate handling capacity of 25,000 b/sd, and also has approved a second phase of the Wapiti plant scheduled for commissioning in fourth-quarter 2020 that will add another 150 MMcfd of gas processing capacity at the site (OGJ Online, May 31, 2018).
TRANSPORTATION Quick Takes
Nord Stream 2 receives Danish operations permit
Nord Stream 2 AG has received an operations permit for the Nord Stream 2 pipelines on the Danish continental shelf. Commissioning can only take place when at least one of the 27.5 billion cu m/year (bcmy) parallel pipelines has been tested, verified, and when relevant conditions in the construction permit and operations permit have been met.
The permit was granted pursuant to Section 2 of Executive Order No. 1520, issued Dec. 15, 2017, on Certain Pipeline Installations in Danish Territorial Waters and on the Danish Continental Shelf and in accordance with the UN Convention on the Law of the Sea, according to which Denmark is obliged to allow the construction and operation of transit pipelines.
The pipeline project on the Danish continental shelf is part of a larger pipeline project, consisting of two pipelines with a total length of 1,230 km for the transport of gas from Russia to Germany. The natural gas pipelines begins in Russia, passes through Finnish, Swedish, Danish and German marine areas, and makes landfall on the German coast.
Authorities in Russia, Finland, Sweden, Germany, and Denmark have all granted permits for the project. Nord Stream 2 applied for the Danish permit Nov. 18, 2019. The original Nord Stream pipeline has been delivering as much as 55 bcmy of gas along a similar route since October 2012.
Taipower awards CTCI EPCC contract for LNG regasification
Taiwan Power Co. (Taipower) awarded CTCI Corp. an engineering, procurement, construction, and commissioning (EPCC) contract to build an LNG regasification terminal for Taichung power plant. The terminal will be Taipower’s first.
CTCI will carry out detailed design, procurement and supply of materials, construction and installment, precommissioning, commissioning, and 1 year of operation and maintenance service as part of the $647-million EPCC contract. Taipower’s current coal-fired Taichung power plant has 5.5 Gw of capacity.
The Taiwanese government intends to increase gas-fired power generation to 50% of the country’s total by 2025. This liquefaction project will ensure a stable natural gas supply of 720 tons/hr, which Taipower says will meet the demand of gas-fired power generating Units 1 and 2 at Taichung, as well as Units 4, 5, and 6 at Tunghsiao power plant.
Earlier this year CTCI won a $623-million EPCC contract to build China Petroleum Corp.’s (CPC) third LNG receiving terminal at Guantang industrial area, Taoyuan. CPC already operates a terminal in Taichung.