OGJ Newsletter

Aug. 2, 2021


Pembina terminates Inter Pipeline acquisition

Pembina Pipeline Corp. terminated the proposed business combination with Inter Pipeline Ltd. after Inter Pipeline said its board of directors would not reconfirm a recommendation that shareholders vote in favor of the deal.

On May 31, the companies noted the proposed share-for-share transaction valued at $8.3 billion (Can.) that would have created one of the largest energy infrastructure companies in Canada (OGJ Online, June 1, 2021).

Brookfield Infrastructure Partners proposed multiple takeover offers for Inter Pipeline in an effort to top Pembina Pipeline (OGJ Online, June 7, 2021). On July 19, an affiliate of Brookfield made a revised offer with consideration, at the election of Inter Pipeline shareholders, of either $20.00 in cash or 0.25 of a Brookfield Infrastructure class A exchangeable

subordinate voting share for each Inter Pipeline share, subject to proration.

In a statement July 26, Inter Pipeline said its board of directors “is open to engaging with Brookfield in an effort to reach a mutually agreeable transaction in the best interests of shareholders,” and that the company will be in a position to make a formal recommendation on the revised Brookfield offer in due course.

Inter Pipeline has agreed to pay Pembina a $350 million (Can.) termination fee.

Whiting to acquire Williston basin asset, divest Colorado asset

Whiting Petroleum Corp. entered into separate definitive agreements to acquire oil and gas assets in the Williston basin of North Dakota and divest of all its oil and gas assets in the Denver-Julesburg basin of Colorado.

The Williston basin assets are being acquired from an unnamed private company for total cash consideration of $271 million. The assets include 8,752 net acres with net daily production of 4,200 boe/d (80% oil); 5 gross/2.3 net drilled and uncompleted wells; and 61 gross/39.5 net undrilled locations (100% operated) in Mountrail County, ND.

Separately, an agreement to divest Redtail assets in Weld County, Co. was reached, including associated midstream assets, to an unnamed private entity for total cash consideration of $187 million. The assets span 67,278 net acres with daily production of 7,100 boe/d (51% oil).

The deals “result in a significantly deeper drilling inventory in our key Sanish operating area, while divesting of properties in Colorado that were not going to compete internally for capital,” said Lynn A. Peterson, Whiting president and chief executive officer, July 21. “Including these transactions, the company now estimates that in a mid-$50s oil environment it has over 6 years of high-quality drilling inventory, assuming a two-rig drilling program,” he continued.

Both deals are expected to close in this year’s third quarter.

NOPSEMA invites public comments for Santos’ proposed Bonaparte seismic survey

Santos Ltd.’s proposed 3D seismic survey in the Bonaparte Gulf has been put out for public comment by Australia’s National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA).

The plan is to acquire the data over four permits in the Petrel subbasin—two exploration permits (WA-454-P, WA-545-P) and two retention leases (WA-27-R, WA-40-R).

The program will cover areas surrounding the Tern-Frigate, Breakwater, and Sparrowhawk prospects and is expected to take 100 days to complete.

Santos proposes to run the survey between Dec. 1, 2021 and Mar. 31, 2022. Water depths in the region are 45-105 m.

The data will be used to create regional geological models and enable the company to plan exploration and development strategy as well as the potential location of future exploration and development wells.

Gas discoveries have long been known in the area with Petrel field discovered in 1969-1970, Tern in 1971, and Frigate in 1978, all by Atlantic Richfield (ARCO).

 Exploration & Development Quick Takes

Shell takes FID for Whale development in Gulf of Mexico

Shell Offshore Inc., a Royal Dutch Shell PLC subsidiary, has taken final investment decision (FID) for the Whale US Gulf of Mexico deepwater development. Cash-preservation efforts brought on by the impact from the pandemic delayed project FID by 1 year. Production is scheduled to begin in 2024.

Shell added to its Paleogene exploration success in the Perdido area in the deepwater US Gulf of Mexico with the Whale discovery in 2017 (OGJ Online, Jan. 18, 2018). The well, in 8,000 ft of water, encountered 1,400 net ft of oil-bearing pay.

The FPU lies in the Alaminos Canyon Block 773 and is adjacent to the Shell-operated Silvertip field, some 10 miles from the Shell-operated Perdido platform and 200 miles southwest of Houston. Fifteen oil producing wells are expected.

Whale’s design closely replicates Vito, a four-column semisubmersible host facility in the greater Mars Corridor. Vito is scheduled to begin production in 2022.

Whale is expected to reach peak production of 100,000 boe/d and currently has an estimated, recoverable resource volume of 490 MMboe.

Shell Offshore is operator with 60% interest. Chevron USA Inc. holds the remaining 40%.

Serinus discovers gas in Satu Mare concession

Serinus Energy PLC discovered gas in the Sancrai-1 well about 7.8 km south of the Moftinu gas development project on the Satu Mare concession in northwestern Romania’s Pannonian basin (OGJ Online Oct. 14, 2020).

The well was drilled to a total depth of 1,600 m 5 days ahead of schedule and about 19% below budget. Continuous formation gas shows were recorded over 20 m of gross pay over four sand intervals from measured depths of 855-875 m. At this interval measured total gas was 5.5-11.1% with an estimated average porosity of 23-27%. Open-hole petrophysical analysis further confirmed a gas-bearing Pliocene sand zone.

Serinus will perforate and test the Pliocene sand zone prior to completing the well for future production.

The proximity of Sancrai-1 to the 15-MMcfd Moftinu gas processing plant allows the well to be put on commercial production while drilling additional appraisal development wells into the structure to fully delineate the gas field.

Serinus has 100% working interest in the concession.

Equinor receives large Johan Sverdrup module

Equinor ASA and its Johan Sverdrup partners took delivery of a 5,000-ton additional module for the Johan Sverdrup riser platform from Aker Solutions ASA. The module is a part of the field’s second development phase and is the latest in a series of large deliveries from Aker Solutions to the Johan Sverdrup field development (OGJ Online, June 8, 2021).

The module consists of 11 sections and is on a barge at Stord. It will be towed to the field and lifted on board the riser platform by the heavy-lift vessel Sleipnir.

Engineering and procurement were carried out by Aker Solutions’ locations in Stavanger, Bergen, Fornebu, Mumbai, and London. Fabrication was carried out by Aker Solutions’ partners in Poland and at yards in Stord and Egersund. Assembly, completion, and commissioning were carried out at the Stord yard.

Johan Sverdrup is the third largest oil field on the Norwegian continental shelf, with expected recoverable reserves of 2.7 billion boe. Once Phase 2 is on stream—expected by fourth-quarter 2022—full field gross production capacity of 755,000 b/d of oil is expected, up from 720,000 b/d (OGJ Online, June 16, 2021).

Equinor is operator with 42.6% interest. Partners are Lundin Energy Norway AS (20%), Petoro AS (17.36%), Aker BP ASA (11.57%), and Total E&P Norge AS (8.44%).

 Drilling & Production Quick Takes

Shell delivers Barracuda first gas, eyes area development

Shell Trinidad and Tobago, through Royal Dutch Shell PLC subsidiary BG International, began production on Block 5C in the East Coast Marine Area (ECMA) in Trinidad and Tobago—a milestone in the delivery of gas domestically and internationally through Atlantic LNG Co., Shell said July 22. First gas was reached July 18.

Block 5C, known as Project Barracuda, is a backfill project with about 25,000 boe/d (140 MMscfd) of sustained near-term gas production with peak production expected to be about 40,000 boe/d (220 MMcfd). It is Shell’s first greenfield project in the country and one of its largest in Trinidad and Tobago since the BG Group acquisition (OGJ Online, Apr. 8, 2015).

Final investment decision for the project was made in January 2020. It comprises two subsea wells (100% Shell owned), one in Endeavour field and one in Bounty field. Both are tied back to Shell’s Dolphin platform. Endeavour was drilled to a depth of 20,000 ft (6,096 m). Bounty was drilled to a depth of 16,000 ft (4,877 m).

Shell now moves toward delivery of the four-well development project in Block 22 and North Coast Marine Area (NCMA)-4, an offshore natural gas field in Trinidad and Tobago. The Colibri project is a joint venture with Heritage Petroleum Co. Ltd. (OGJ Online, Sept. 8, 2020). First gas is expected in 2022.

Shell holds 46-57.7% interest in each of Atlantic LNG’s four liquefaction trains at Point Fortin on the southwest coast of Trinidad. Together, the plant can produce up to 100,000 cu m/day of LNG, which is shipped on LNG tankers to various destinations around the world. In addition to LNG, the facility produces natural gas liquids (NGLs).

Petrobras adds production quarter-over-quarter

Average production of oil, NGL, and natural gas by Petrobras in this year’s second quarter reached nearly 2.80 MMboe/d, 1.1% above the prior quarter, due to the continued ramp-up of platforms P-68 (Berbigão and Sururu fields) and P-70 (Atapu field).

Production in the presalt area totaled 1.96 MMboe/d in the quarter, representing 70% of Petrobras’ total production, 1 percentage point above first-quarter 2021 and 4 percentage points above second-quarter 2020.

In 2Q21, oil and NGL production in the presalt fields was 3.4% higher than in the previous quarter, due to the ramp-up of platforms P-68 and P-70, and the stabilization of production levels on the platforms that carried out schedule stoppages in 1Q21, mainly the FPSO Cidade de Paraty and P-66 (Tupi field). In addition, the operator recorded better performance on platforms P-74 and P-76 (Búzios field). These effects were partially offset by the scheduled stoppages of the P-58 (Jubarte field).

Oil and NGL production in the postsalt in the year’s second quarter was 2.9% lower than in the previous quarter, due to higher losses from maintenance stoppages in Campos basin and the divestment of Frade field.

Among the stoppages, Petrobras had higher impact with the platforms FPSO Campos dos Goytacazes (Tartaruga Verde field), P-40 (Marlim Sul field), P-25 and P-31 (Albacora field), P-48 (Albacora field), Barracuda and Caratinga) and P-50 (Albacora Leste field).

Onshore and shallow water production in second-quarter 2021 was 99,000 b/d, 10,000 b/d lower than the previous quarter, mainly due to well interventions, equipment maintenance, the maintenance stoppage of the P-31, in addition to the natural decline of production.

Production abroad in second-quarter 2021 was 43,000 boe/d from the fields in Bolivia, Argentina, and the United States. The drop compared to first-quarter 2021 is mainly due to the natural decline of the fields in Bolivia (San Antônio, San Alberto, and Itaú).

CNOOC starts production from Luda 29-1

CNOOC Ltd. started production at Luda 29-1 oilfield. The field is in Liaodong Bay, Bohai Sea, in about 32 m of water.

The project has built a new wellhead platform with seven development wells planned in total, including four production wells, two water injectors, and one water source well. It will also use existing processing facilities in Luda 21-2 and Luda 16-3 oilfields The project is expected to reach peak production of about 4,440 b/d crude oil in 2021.

Aker BP installs Hod B jacket in anticipation of 2022 production

Aker BP installed a jacket at Hod B and will receive topsides later this summer in anticipation of production start-up in first-quarter 2022.

The platform is scheduled to sail from the Verdal yard in August. Work is under way to plan remaining activities to complete the project. Multiple subsea campaigns will be conducted to install and connect the gas lift pipe, production flowline, and umbilical. Integration work is under way on Valhall, and the Maersk Invincible drilling rig will start drilling production wells this autumn (OGJ Online, Dec. 8, 2020).

The fixed facilities alliance between Aker BP, Aker Solutions, and ABB is delivering the platform. Both the jacket and topsides are being built at Aker Solutions in Verdal.

Hod field is in Block 2/11 in the southern part of the Norwegian sector of the North Sea, about 12 km south of Valhall and 6 km south of the Valhall Flank South platform. It will be developed with a normally unmanned installation which will be remotely operated from shore by the Valhall field center. It is expected to produce 40 MMboe of Valhall’s planned 2 billion bbl produced from the area.

Aker BP is the operator at Hod B (90%) with partner Pandion Energy (10%).


ExxonMobil JV completes units at USGC chemical complex

Saudi Arabian Basic Industries Corp. (SABIC) and ExxonMobil Corp. have reached mechanical completion of major derivatives units at the 50-50 joint venture Gulf Coast Growth Ventures LLC’s (GCGV) 1.8-million tonnes/year (tpy) ethane cracking complex in Portland, San Patricio County, Tex., near Corpus Christi (OGJ Online, Sept. 16, 2019).

With construction of the 1.1-million tpy monoethylene glycol unit and two polyethylene units—originally slated for capacities of 400,000 tpy each—with combined production capacity of 1.3 million tpy, GCGV plans to begin commissioning of the entire project in the fourth quarter, roughly a year ahead of its previously targeted fourth-quarter 2022 startup, ExxonMobil said on July 26.

Announcement of GCGV’s expedited startup schedule follows ExxonMobil’s confirmation in its third-quarter 2020 earnings presentation that the project was under budget and ahead of schedule amid an improved cost environment, as well as ExxonMobil’s implementation of cost-cutting efficiencies and formation of a dedicated global projects division ahead of the COVID-19 pandemic.

Details regarding the status of construction on the complex’s ethane cracker have yet to be confirmed.

ExxonMobil and SABIC formed GCGV in 2018 to take advantage of the USGC’s existing infrastructure to capture competitive pricing for US natural gas feedstock and access to rising demand for ethylene-based products in overseas export markets (OGJ Online, May 7, 2018).

Alongside forming part of SABIC’s growth strategy to build petrochemical installations in key markets —including the Americas—to address industry demand and achieve the company’s 2025 strategy, the proposed multibillion GCGV project also is one of the developments included as part of ExxonMobil’s 10-year, $20-billion Growing the Gulf expansion initiative announced in early 2017 (OGJ Online, Mar. 9, 2017).

Baltic Chemical lets contract for Ust-Luga complex

JSC RusGazDobycha subsidiary Baltic Chemical Complex LLC (BCC), through its contractor, has let a contract to McDermott International Ltd. to provide engineering and procurement (EP) for BCC’s $13-billion ethane-cracking complex, or gas chemical complex (GCC) portion, of the larger PJSC Gazprom-RusGazDobycha combined gas processing, liquefaction, and chemical complex for processing ethane-containing gas (CPECG) under construction at the Gulf of Finland near the seaport of Ust-Luga, Leningrad Oblast, Russia.

As part of the contract—awarded directly by Heat Transfer Technologies DMCC, a subcontractor of CPECG’s main project contractor China National Chemical Engineering & Construction Corporation Seven Ltd. (CC7)—McDermott will license technology rights, as well as deliver the basic design engineering package, module detailed engineering design, and full procurement of main equipment for a modularized spent caustic treatment solution to enable the GCC’s planned 3-million tonnes/year (tpy) polyethylene production, the service provider said on July 21.

McDermott, which completed front-end engineering design and ongoing early works for the GCC project, revealed neither the value nor duration of the latest EP contract.

Alongside BCC’s GCC, the CPECG—which officially began construction in May—also includes RusKhimAlyans’—a 50-50 special-purpose venture of Gazprom and RusGazDobycha—integrated natural gas processing and liquefaction complex (GPC of the CPECG), which will have 13-million tpy liquefaction capacity and initially process 45 billion cu m/year (bcmy) of wet natural gas feedstock it receives from Gazprom’s Achimov and Valanginian deposits in the Nadym-Pur-Taz region of the Yamal Peninsula.

The GPC will produce as much as 4 million tpy of ethane, and more than 2.2 million tpy of LPG, with ethane from the complex to feed nearby BCC’s proposed $13-billion ethane cracking project that—once in operation—will produce more than 3 million tpy of polymers. About 18 bcmy of gas remaining after processing at GPC—including ethane extraction, LPG, and 13 million tpy of LNG—will be exported from the site via Gazprom’s gas transmission lines.

RusGazDobycha expects to complete first-phase construction of the GCC during fourth-quarter 2023, with second-stage construction to wrap in fourth-quarter 2024.


Trans Mountain expansion gets route variance approved

Canada’s Trans Mountain crude oil pipeline expansion project has received approval from the Canada Energy Regulator for the 18-km West Alternative Route in the Coldwater Valley area of British Columbia. The new route moves the pipeline away from an underground aquifer supplying the Coldwater Indian Band with water. Trans Mountain will be able to carry 890,000 b/d of Alberta-sourced production to the coast in Burnaby, BC, once the expansion is complete, nearly triple its current capacity.

Construction of the roughly 700-mile pipeline, following a route parallel to that of the original Trans Mountain, is under way in both Alberta and British Columbia and expected to be completed late 2022. In Alberta, Trans Mountain says it has begun work in the Yellowhead region west of Hinton, Alta. Construction in this area will continue through December 2022. Work in the greater Edmonton area is nearly complete.

Crews are also at work near Kamloops, BC. Activities include installation of a 1.5-km transmission spur north of Kamloops to power Trans Mountain’s Black Pines pump station, being built as part of the expansion project. Work also includes clearing, grading, stripping, and blasting. 

Maintenance and expansion is also under way at Burnaby Terminal, including tank construction, in-line inspections of existing pipe segments, and relocation of existing infrastructure where required. Boring is occurring to construct a 2.6-km tunnel connecting Burnaby Terminal to Westridge Marine Terminal.

Pembina Pipeline Corp. is part of a partnership seeking to buy Trans Mountain from the Canadian government. 

Cheniere, Tourmaline sign long-term gas supply agreement

Cheniere Energy Inc. subsidiary Corpus Christi Liquefaction Stage III LLC signed a long-term gas supply agreement (GSA) with Tourmaline Oil Marketing Corp., a subsidiary of Canadian gas producer Tourmaline Oil Corp.

Under the deal, Tourmaline agreed to sell 140,000 MMbtu/d of natural gas to Corpus Christi Stage III for 15 years beginning early 2023. The LNG associated with this gas supply, some 0.85 million tonnes per year (tpy), will be marketed by Cheniere. Cheniere will pay Tourmaline an LNG-linked price for its gas, based on the Platts Japan Korea Marker (JKM), after deductions for fixed LNG shipping costs and a fixed liquefaction fee.

Tourmaline Oil Corp. is acting as guarantor of the GSA on behalf of Tourmaline. The deal is expected to support development of the Corpus Christi Stage III project, which is expected to include up to seven midscale liquefaction trains with a total nominal production capacity of 10 million tpy. It has received all necessary regulatory approvals.

New Fortress begins LNG operations in Baja California Sur

New Fortress Energy Inc. (NFE) has started commercial operations at its LNG terminal in the port of Pichilingue, Baja California Sur, Mexico.

Under terms of an agreement signed in March, NFE will supply natural gas to the CTG La Paz and CTG Baja California Sur power plants in Baja California Sur through the terminal (OGJ Online, Mar. 17, 2021).

Additionally, NFE has nearly completed construction of its own gas-fired power plant in Baja California Sur with capacity of about 135 Mw that is expected to begin operations and the supply of power to the local grid later this quarter.