OGJ Newsletter

GENERAL INTEREST Quick Takes

Government of Guyana to auction off offshore blocks

The Government of Guyana through the Ministry of Natural Resources will auction off 14 oil blocks in the nation’s first-ever competitive offshore oil and gas licensing round.

Block acreage range is 1,000-3,000 sq km. Eleven are in shallow water, while the remaining three are in ultra-deepwater. Companies participating in the must pay a minimum signing bonus of $10 million for shallow blocks while deepwater blocks carry a signing bonus of $20 million.

As part of this new model agreement, the royalty has been increased to 10% from the 2% granted to Stabroek block. The current 75% cost recovery ceiling has been lowered to 65%. Profit sharing after cost recovery remains 50-50 between the contractor and the government. The new terms double Guyana’s share to 27.5% from 14.5%, plus the newly introduced 10% corporate tax.

Companies will be given an opportunity to bid for blocks but must possess a proven track record of technical, financial, health and safety, and environmental capabilities. Bidders will be assessed based on guaranteed work programs which will be weighed with the offered signing bonus. Local content commitments also will be examined.

There will be no restrictions on the number of bids a company may submit, but each successful bidder will be limited to an award of three blocks.

The government will make amendments to the Petroleum (Exploration and Production) Act 1986 to reflect, where necessary, fiscal changes identified for this national bid round and all future operations. The licensing round process is expected last for 5 months and should be concluded by end-first-quarter 2023.

Majors produce winning bids for blocks offshore Canada

Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) received five successful bids for Eastern Newfoundland region exploration licenses totaling $238,075,321 (Can.) in work commitments and covering 1,222,907 hectares. No bids were received for the South Eastern Newfoundland region.

ExxonMobil Canada Ltd. produced the winning bid (operator, 70% interest) for Parcel 8 of Orphan basin, offshore Newfoundland and Labrador, bid partner QatarEnergy (QPI Energy Canada Ltd. 30%) said in a release Nov. 3.

Offshore Eastern Canada, Parcel 8 lies in water depths of 2,500-3,000 m and covers an area of about 2,700 sq km.

Other successful bids were BP Canada Energy Group ULC for Parcel 12 (100%); Equinor Canada Ltd. (60%) and BP Canada Energy Group Ltd.  (40%) for Parcel 26, Equinor Canada Ltd. (60%) and BP Canada Energy Group Ltd.  (40%) for Parcel 27; and Equinor Canada Ltd. (60%) and BP Canada Energy Group Ltd. (40%) for Parcel 28.

Subject to bidders satisfying the requirements specified and receiving government approvals, C-NLOPB will issue the new exploration licenses in January 2023.

Qatargas lets $4.5-billion contract to Saipem

Qatargas has let a contract to Saipem for two offshore gas compression complexes offshore the northeast coast of Qatar aimed at sustaining North Field production. The contract value is about $4.5 billion, the service provider said in a release Oct. 19.

Work on the North Field Production Sustainability Offshore Compression Complexes Project – EPC 2 includes the engineering, procurement, fabrication, and installation of the two compression complexes, including two of the largest fixed steel jacket compression platforms ever built, flare platforms, interconnecting bridges, living quarters, and interface modules, Saipem said.

The award follows a February 2021 engineering, procurement, construction, and installation (EPCI) contract let to Saipem by Qatargas related to offshore infrastructure for the field.

ConocoPhillips moves toward second Otway basin farmin

ConocoPhillips Australia (CPA) signed a joint operating agreement (JOA) with 3D Oil Ltd., Melbourne, to advance a farmin to 3D Oil’s Vic/P79 permit on the southern edge of offshore Otway basin, western Victoria.

The permit lies to the south and west of producing gas fields which are connected to the western Victoria processing and pipeline system.

Under the terms of the agreement, CPA will pay 3D Oil $3 million cash for 80% interest and operatorship.

CPA also will carry 3D Oil for the cost to drill one exploration well up to $35 million with a spud date before February 2025, after which 3D Oil will pay its 20% share.

Signing of the JOA is one of the last elements of the farm-out to CPA, which now needs government approval for completion.

The farmout builds on a previous agreement in 3D Oil’s T/49P in the Tasmanian sector of the Otway basin west of King Island in which CPA gained 80% interest and operatorship.

Vic/P79 covers 2,576 sq km, while T/49P covers 2,683 sq km. Once the Vic/P79 deal is approved, the joint venture will become the dominant player in terms of acreage in the offshore Otway.

 Exploration & Development Quick Takes

EEPGL lets FPSO FEED contract for Uaru development

ExxonMobil affiliate Esso Exploration and Production Guyana Ltd. (EEPGL) let a front end engineering and design (FEED) contract for a floating production, storage and offloading vessel (FPSO) to MODEC Inc. for Uaru, its fifth development project in Stabroek block, offshore Guyana.

MODEC will begin activities related to FPSO design and secure the second M350TM hull for FPSO service.

The 250,000-b/d FPSO—to be installed in water depth of about 2,000 m—will have water injection capacity of 350,000 b/d, 540 MMcfd gas processing capacity, and 2-million bbl of crude oil storage. 

Construction and installation is expected following FEED, government approvals, project sanction, final investment decision by ExxonMobil, and EEPGL’s release of the second phase (EPCI) of work.

MODEC is expected to operate the vessel for an initial duration of 10 years with potential options for continuation.

Uaru development, in the eastern portion of the block, will target 1.319 billion boe and is expected to come online end-2026.

Esso is operator of the 6.6-million-acre Stabroek block with 45% interest. Hess Guyana Exploration Ltd. holds 30% and CNOOC Petroleum Guyana Ltd. holds 25%.

Enwell to advance Ukraine license development plan

Enwell Energy PLC will continue its plan to develop the Svystunivsko-Chervonolutskyi (SC) exploration license in the Poltava region of Ukraine. Strong flow rates at the SC-4 well demonstrate the potential of the license area, which will be developed “as circumstances permit,” said company chief executive officer Sergii Glazunov. 

Development is expected to include installation of flow lines and gas processing and production infrastructure and the drilling of additional wells.

SC-4 is the company’s first well on the license and is primarily an appraisal well, targeting production from the V-22 horizon in the Visean formation. The well was spudded in August 2021, and, after a period of suspension due to the conflict in Ukraine, was drilled to its final depth of 5,585 m (OGJ Online, Mar. 15, 2022). Three intervals, at drilled depths of 5,530-5,533 m, 5,483-5,486 m, and 5,416-5,419 m within the V-22 Visean formation were perforated and underwent initial testing.

The two former intervals flowed gas, but not at a sustained rate. However, the latter interval, which was the primary target for the well, demonstrated strong productivity and stabilized flows. Accordingly, this interval underwent more extensive testing, using a variety of choke sizes, and produced at a stabilized flow rate of about 3 MMscfd gas and 3 b/d condensate (535 boe/d in aggregate). The well will now be suspended for future production.

The well was intended to also explore the shallower V-16 and V-21 Visean horizons. However, as the primary target of the well in the V-22 formation produced a stabilized flow, testing of these shallower horizons was not considered necessary at the present stage of development as it is intended that the V-22 horizon will be put on production once surface infrastructure is completed.

Petrobras evaluates Aram block discovery

Petróleo Brasileiro SA (Petrobras) will assess dimensions and commerciality of a discovery in Aram block after having successfully completed a drill-stem test (DST) of exploration well 1-BRSA-1381-SPS (Curaçao). The discovery lies 240 km from the city of Santos, State of São Paulo, in the southwest portion of Santos basin presalt at a water depth of 1,905 m.

Hydrocarbons had been previously identified in the well through wireline logging and fluid samples (OGJ Online Nov. 22, 2021). The DST investigated a thick interval of petroleum-bearing presalt carbonates, whose productivity was evaluated by dynamic production data. Oil samples were collected during the DST to be further characterized by laboratory analyses.

Petrobras is operator of Aram block (80%) with partner China National Petroleum Corp. (CNPC, 20%).

Strike Energy extends Perth basin Permian trend

Strike Energy Ltd., Perth, has identified four new leads with Permian-age reservoir potential in two 100%-owned onshore North Perth basin permits (EP 504, EP 503) and will acquire additional 2D seismic data before planning two exploration wells.

The leads lie within the Arrino and Kadathinni structures about 15 km east of the company’s South Erregulla gas field discovery and are contained within up-thrown fault blocks on the Tathra Fault Terrace inboard of the Urella Fault and at similar depths to Erregulla fields. They lie on trend with Lockyer Deep and encompass up to 100 sq km of combine closure, Strike said.

The Tathra Terrace structural trend comprises a series of linked fault blocks formed between the Urella fault to the east and the Tathra-Wicherina fault to the west and extending south from Lockyer.

The terrace forms a west-facing step down from the elevated Irwin Terrace into the deepest part of the North Perth basin called the Dandaragan Trough.

Similar east-facing structural trends in the region host discovered fields Beharra Springs and Waitsia, while Permian gas has also been proven in the axial high at West and South Erregulla.

Three linked closures, Arrino North, Arrino Central, and Arrino South, rise towards the north.

A deeper Kadathini lead comprises a separate additional fault block to the south.

Estimated depth of the four structures is 4,000 m for Arrino, which is similar to Lockyer Deep, to about 6,000 m for Kadathinni, which is deeper than West Erregulla.

The leads have been defined on limited 2D data, but the seismic lines show identical seismo-stratigraphy and structural style to the recent Permian discoveries at Lockyer Deep and South Erregulla, Strike said. An amplitude bloom at the Kingia Sandstone level has been observed on some lines.

 Drilling & Production Quick Takes

Eni, Sonatrach start field onshore Algeria

Italy’s Eni SPA and Algeria’s Sonatrach started production at HDLE/HDLS oil field in the Zemlet el Arbi concession, Berkine North basin, in the Algerian desert. 

HDLE/HDLS is currently producing 10,000 bo/d. Production will ramp up through an accelerated development plan which envisages drilling of new wells in 2023.

Preliminary estimates put the size of the discovery, made in March, near 140 million bbl of oil in place (OGJ Online, Mar. 21, 2022).

The concession is operated by a joint venture between Eni (49%), and Sonatrach (51%).

EOG plans 20-well program in newly accumulated Utica acreage

EOG Resources Inc. is targeting a 20-well program in the Utica in 2023 after establishing a new position in Ohio, accumulating 395,000 net acres and about 135,000 mineral acres in the southern portion of its acreage footprint—all for less than $500 million, the company said as part of its third-quarter earnings release Nov. 3.

The product mix averages about 60-70% liquids across the acreage where the company already has completed four wells and operates 18 additional legacy wells across a 140-mile trend.

For fourth-quarter 2022, EOG expects total crude oil equivalent volumes of 900,000-936,700 boe/d with US crude oil and condensate volumes of 460,400-468,400 b/d and 1,360-1,440 MMcfd for US natural gas. Capital expenditure of $1.25-1.45 billion is expected.

Total crude oil equivalent for third-quarter 2022 was 919,200 boe/d, above the midpoint of guidance, flat compared with second-quarter 2022 volumes of 920,700 boe/d, and above the 844,400 boe/d from third-quarter 2021.

Of those third-quarter volumes, crude oil production was 465,100 b/d, above the midpoint of guidance, and up less than 1% compared with this year’s second quarter. NGL production of 209,300 b/d increased 4% compared with the second quarter. Natural gas production of 1,469 MMcfd was a 4% decrease compared with second-quarter 2022 primarily due to plant maintenance in Trinidad.

Neptune Energy spuds Calypso near Draugen field

Neptune Energy started drilling Calypso exploration well 6407/8-8 S in production license (PL) 938 14 km north-west of Draugen field and 22 km north-east of the Njord A platform in the Norwegian Sea.

The well is being drilled by the Deepsea Yantai, a semisubmersible rig owned by CIMC and operated by Odfjell Drilling. The drilling program comprises a main-bore (6407/8-8 S) with an optional sidetrack (6407/8-8 A) based on the outcome of the exploration well.

The reservoir target is the middle and lower Jurassic formations and is expected to be reached at a depth of about 2,960 m.

Calypso is positioned within one of Neptune’s core areas on the Norwegian Continental Shelf. In the event of a commercial discovery, Calypso could potentially be tied back to existing infrastructure.

Neptune Energy is operator at PL 938 (30%) with partners OKEA ASA (30%), Pandion Energy AS (20%), and Vår Energi ASA (20%).

 PROCESSING Quick Takes

Petrobras finalizes sale of SIX processing plant, assets

Petróleo Brasileiro SA (Petrobras) has completed the sale of its 5,800-tonne/day Unidade de Industrialização do Xisto (SIX) unit—including a mine in one of the world’s largest oil shale reserves and a shale processing plant—in São Mateus do Sul, Paraná, to Forbes Resources Brazil Holding SA (F&M Brazil), a subsidiary of privately-held Forbes & Manhattan Resources Inc. (F&M), Toronto, Ont. (OGJ Online, Nov. 22, 2021).

As part of the Nov. 4 transaction, F&M Brazil acquired Petrobras’ 100% ownership interest in Paraná Xisto SA—operator of SIX and its associated assets—for an overall purchase price of $41.6 million, $3 million of which was previously paid as a guarantee at the contract signing in November 2021, Petrobras said.

In connection with completing the sale, Petrobras also signed a separate lease agreement with Paraná Xisto that allows Petrobras to continue unidentified research activities in experimental plants sited in the SIX area.

With the deal finalized, SIX assets are now managed by F&M Brazil, to which Petrobras will offer ongoing support for a transitional period of up to 15 months to ensure safe, uninterrupted operations, the seller confirmed.

Phillips 66 adds Sweeny fractionation capacity

Phillips 66 completed Sweeny Frac 4 at its Sweeny refinery complex in Old Ocean, Tex. The NGL fractionator, which achieved full rates in early October, adds 150,000 b/d of processing capacity. Total Sweeny Hub fractionation capacity is 550,000 b/d.

Underpinned by long-term customer commitments, the new fractionator follow startup of the second and third in late 2020 and the first in late 2015.

The company provided the update as part of its third-quarter 2022 earnings update Nov. 1.

Phillips 66 increased earnings quarter-over-quarter to $5.4 billion in third-quarter 2022, compared with earnings of $3.2 billion in second-quarter 2022. Excluding special items of $2.3 billion, the company had adjusted earnings of $3.1 billion in the third quarter, compared with second quarter adjusted earnings of $3.3 billion.

Midstream third-quarter 2022 pre-tax income was $3.6 billion, compared with $292 million in second-quarter 2022.

The chemicals segment reflects Phillips 66’s equity investment in Chevron Phillips Chemical Co. LLC. Chemicals third-quarter 2022 pre-tax income was $135 million, compared with $273 million in second-quarter 2022.

Refining third-quarter 2022 pre-tax income was $2.9 billion, compared with pre-tax income of $3 billion in second-quarter 2022.

 TRANSPORTATION Quick Takes

Equitrans call for legislation to finish Mountain Valley pipeline

Equitrans Midstream Corp. cited “the continued hostility of the Fourth Circuit Court panel” in calling for expeditious passage of federal energy infrastructure reform legislation that “specifically requires the completion of” its 2-bcfd Mountain Valley (MVP) natural gas pipeline project. The US Fourth Circuit Court of Appeals heard oral arguments Oct. 25, 2022, relating to Section 401 water quality certification in West Virginia.

The company said that it remains engaged in the federal permitting process but that a combination of the court’s perceived hostility and uncertainty regarding the timelines on which other permitting is proceeding were threatening its ability to meet Mountain Valley’s targeted second-half 2023 in-service date and $6.6-billion total cost. MVP received its Section 401 stream-crossing permit from West Virginia in January 2022, but the permitting has faced nearly continuous legal challenges since.

“There continues to be significant, bipartisan support for federal energy infrastructure permitting reform legislation,” Equitrans chief executive officer Thomas Karam said in a release. “However ... the same panel of judges in the US Fourth Circuit Court of Appeals has again been assigned and appears hostile in a (Mountain Valley) permitting case,” Karam said. The Fourth Circuit has already vacated multiple project permits.

Equitrans has an approximate 48.1% ownership interest in Mountain Valley and will operate the pipeline. Its partners in MVP LLC are NextEra Energy Inc., Consolidated Edison Inc., AltaGas Ltd., and RGC Resources Inc. 

Equitrans also said the Mountain Valley JV continues to evaluate its 300-MMcfd MVP Southgate project, including engaging in discussions with anchor shipper Dominion Energy North Carolina regarding likely changes to the project design, scope, and timing. MVP LLC last month filed a voluntary dismissal of eminent domain proceedings regarding the 73-mile pipeline (OGJ Online, Oct. 24, 2022).

On Sept. 30, 2022, the US Federal Energy Regulatory Commission issued a draft environmental impact statement for Equitrans’s 350-MMcfd Ohio Valley Connector Expansion Project (OVCX). OVCX is designed to meet growing gas demand through existing interconnects in Clarington, Ohio, with long-haul pipelines. Equitrans is targeting first-half 2024 in-service.

Targa to build new Permian basin NGL pipeline

Targa Resources Corp. plans to build the Daytona NGL pipeline as an addition to its common-carrier 550,000-b/d Grand Prix NGL pipeline system. Daytona will transport NGLs from the Permian basin to the 30-in. OD Grand Prix segment in North Texas for further delivery to Targa’s 963,000-b/d fractionation and storage complex in Mont Belvieu, Tex.

The company expects Daytona to be in service by end-2024 at a cost of $650 million. Grand Prix Pipeline LLC, of which Targa owns 75% and Blackstone Energy Partners LP 25%, will own the Daytona pipeline and each will fund its respective share of the pipeline’s cost based on ownership percentage. Targa will build and operate the pipeline and expects to fund construction through operating cash flows and available liquidity.

During third-quarter 2022, Targa began operations at its new 275-MMcfd Legacy plant in Midland basin and its new 230-MMcfd Red Hills VI plant in Delaware basin. Construction continues on Targa’s 275-MMcfd Legacy II plant and 275-MMcfd Greenwood plant in Midland basin, its 275-MMcfd Midway plant in Delaware basin, and its 120,000-b/d Train 9 fractionator in Mont Belvieu (OGJ Online, Aug. 9, 2022).

Earlier this month, Targa announced plans for the new 275-MMcfd Wildcat II cryogenic natural gas processing plant in Delaware basin, expected to begin operations first-quarter 2024.

Enbridge launches open season for T-North BC Pipeline segment expansion

Enbridge Inc., Calgary, launched an open season to gauge shipper support for expanded natural gas capacity on the T-North segment of its 3.6 bcfd BC Pipeline system in British Columbia. T-North runs from the Fort Nelson area and transports natural gas south to the T-South segment of the company’s 2,953-km BC pipeline system and east to interconnecting pipelines at the British Columbia-Alberta border.

The expansion could provide an additional 500 MMcfd capacity at a capital cost of up to $1.9 billion (Can.) to serve growing regional demand for natural gas, West Coast LNG exports, and downstream demand, the company said in a press statement Nov. 4.

The open season began Nov. 4 and is expected to end on Jan. 10, 2023.