GENERAL INTEREST Quick Takes
Devon Energy acquires Williston basin assets
Devon Energy Corp. has agreed to acquire leasehold interest and related assets of RimRock Oil and Gas LP in Williston basin for total cash consideration of $865 million.
The transaction adds a contiguous position of 38,000 net acres (88% working interest) all within the Fort Berthold Indian Reservation in Dunn County, ND, directly offsetting and overlapping Devon’s existing position.
In 2017, RimRock acquired operation of 100 producing wells and currently has 181 operated wells. The company’s first-quarter 2022 production was about 15,000 boe/d (78% oil), with volumes expected to increase to an average of 20,000 boe/d over the next year.
Devon expects to incur about $100 million of capital expenditures post-closing in 2022. The transaction also adds more than 100 highly economic undrilled inventory locations.
The transaction is subject to customary terms and conditions and is expected to close in this year’s third quarter.
UK NSTA launches carbon storage licensing round
UK’s North Sea Transition Authority (NSTA) is launching the country’s first-ever carbon storage licensing round. The process will include 13 new carbon storage areas off the coast of Aberdeen, Teesside, Liverpool, and Lincolnshire and made up of a mixture of saline aquifers and depleted oil and gas fields. First injection of carbon dioxide (CO2) could come as early as 4-6 years after the license award.
There are already six carbon storage licenses on the UK Continental Shelf, which could meet up to 20% of storage needs if they reach their maximum potential of 40-million tonne/year (tpy) injection rates by the mid-2030s. At this stage, they offer the potential to make a very significant contribution to decarbonization of the UK.
Capacity estimates of the areas offered in the current round are uncertain but, combined with the previously issued licenses, the sites will contribute to the UK’s goal of storing 20-30 million tpy of CO2 by 2030. NSTA estimates that as many as 100 CO2 stores could be required to meet the country’s net zero by 2050 target, making the new round likely the first of many.
Carbon capture and storage will play a crucial role in decarbonizing the UK’s major industrial hubs such as Teesside and Humberside, according to NSTA. CO2 will be transported from where it was produced, via ship or in a pipeline, and stored offshore in geological formations.
NSTA said it fully considered issues including colocation with offshore wind, environmental issues, potential overlaps with existing or future petroleum licenses, and other activities in ensuring key technologies can be taken forward.
The application window closes Sept. 13, 2022, with any new licenses expected to be awarded in early 2023. In addition to being awarded a license from the NSTA, successful applicants will also need to obtain a lease from The Crown Estate or Crown Estate Scotland, depending on location, before they can progress a project.
Vintage wins approval for Beach permit interest
Vintage Energy Ltd. has received ministerial approval for acquisition of Beach Energy Ltd.’s 15% interest in Cooper basin retention lease PRL221 in South Australia.
The lease contains Odin gas field that straddles the permit border with the group’s ATP 2021 Vali field permit in Queensland.
At closing, Vintage will be operator with 50% interest. Bridgeport (Cooper Basin) Pty Ltd. and Metgasco Ltd. each will hold 25%.
Interests in PRL221 and ATP2021 are now aligned allowing transition to development and production mode.
Vali gas is expected to come on stream in September-October 2022 while the Odin-1 discovery well is to be completed as a gas producer and added to production infrastructure.
OPEC+ alliance to boost July, August oil production
OPEC and participating non-OPEC oil producing countries including Russia (OPEC+) agreed during the 29th Ministerial Meeting June 2 to raise production by 648,000 b/d in July and August, which is expected to moderately mitigate soaring energy prices and the resulting inflation.
The OPEC+ group has been steadily adding 432,000 b/d per month. In the meeting, OPEC+ decided to advance the planned overall production adjustment for the month of September and redistribute equally the 432,000 b/d production increase over the months of July and August 2022. Therefore, July production will be adjusted upward by 648,000 b/d.
The move comes as Russian oil production is expected to plummet in response to sanctions targeting the country’s energy exports, especially given the decision by the European Union to stop most Russian oil purchases by yearend. OPEC+ considered the most recent reopening from lockdowns in major economic centers like China, and noted the expected global refinery intake increase after seasonal maintenance.
The meeting also extended the compensation period until end December 2022 as requested by some underperforming countries. Underperforming countries were asked to submit compensation plans in accordance with the statement of the 15th OPEC and non-OPEC Ministerial Meeting by June 17, 2022.
The 30th OPEC and non-OPEC Ministerial Meeting will be held June 30, 2022.
North Hudson Resource Partners acquires LOGOS
Energy investment firm North Hudson Resource Partners LP, Houston, has acquired LOGOS Resources II LLC from affiliates of ArcLight Capital Partners LLC for $402 million.
LOGOS’ assets include over 230,000 net acres in the San Juan basin, current net production of 106 MMcfed, and an inventory of drilling locations in Mancos shale and Gallup oil play in northwest New Mexico, North Hudson said in a June 2 release.
LOGOS recently began its 2022 drilling program and anticipates increasing net production to 130 MMcfed by yearend.
LOGOS will continue to be led by existing management, including Jay Paul McWilliams as chief executive officer.
North Hudson’s portfolio comprises non-operated and operated oil and gas assets with interests in over 4,500 wells mostly in the Permian basin, Denver-Julesburg basin, San Juan basin, and Haynesville shale.
Exploration & development Quick Takes
Shell begins Santos basin FPSO procurement
Shell Brasil Petróleo Ltd. (Shell) has let a limited notice to proceed (LNTP) to BW Offshore Co. for early-stage engineering and supplier reservations for an FPSO for Gato do Mato oil and gas field in Block S-M-518 of the Santos basin presalt, offshore Brazil.
Upon completion, Shell and its partners expect to award a lease and operating contract to a consortium of BW Offshore and Saipem SPA, which will be jointly responsible for engineering, procurement, construction, and installation (EPCI) of the FPSO with expected delivery in 2026.
The FPSO lease and operate contract will have a firm period of 18 years with 7 years of options.
The award is subject to the parties finalizing commercial and pricing terms and a final investment decision by Shell and its partners.
BW Offshore awarded an LNTP to Saipem for early-stage engineering services for the FPSO unit. The LNTP is valued up to $50 million. Saipem’s share is about $25 million.
Shell is operator at Gato Do Mato (50%) with partners Ecopetrol (30%) and TotalEnergies (20%).
Chevron lets contract for GoM Ballymore development
Chevron has let a contract to Subsea 7 SA for development of the Ballymore project offshore US Gulf of Mexico, in water depths of up to 6,550 ft.
The deepwater project, sanctioned by the operator in May, has a design capacity of 75,000 b/d of crude oil and will be developed as a three-mile subsea tieback to the existing Blind Faith platform (OGJ Online, May 17, 2022). Through Ballymore, Chevron could potentially recover over 150 million bbl of oil in its first Norphlet reservoir development, according to the company website.
The project covers the installation of a Steel Catenary Riser (SCR), flowline, and control system, the service provider said in a release June 1. Subsea 7 supported Chevron with early engineering prior to the award.
The offshore scope will be executed in 2023. Project management and engineering will take place in Subsea 7’s office in Houston, Tex.
The service provider values the contract at $50-150 million.
VAALCO discovers hydrocarbons in South Tchibala 1HB-ST well
VAALCO Energy Inc. discovered multiple hydrocarbon-bearing sands in the South Tchibala 1HB-ST well from the Avouma platform in Etame field, offshore Gabon. The well is expected to be online this month, the company said in a June 2 statement.
The well was completed in the Dentale D1 sand interval (18 m net hydrocarbons), which is analogous to Deep Dentale producing field in North Tchibala with similar porosity and permeability, VAALCO added.
The Dentale D9 interval (15 m net hydrocarbons) was cased for future testing and completion. A thin section of Gamba sand was penetrated but is not economically viable to complete in this wellbore, the company said.
This well follows the Avouma 3H-ST development well completed in April (OGJ Online, Apr. 26, 2022).
VAALCO is operator in Etame Marin block (63.6%) with partners Addax Petroleum Co. (33.9%) and PetroEnergy Resources Corp. (2.5%).
Shell receives approval for Jackdaw
Shell PLC received approval from the North Sea Transition Authority (NSTA) and the Offshore Petroleum Regulator for Environment & Decommissioning (OPRED) to develop Jackdaw gas and condensate field in the UK North Sea. First production is expected in second-half 2025.
OPRED rejected plans in 2021 for development of the field—which contains an ultra-high pressure, high temperature reservoir—due to environmental concerns. An updated proposal, submitted in March, amended plans for gas processing at Shearwater hub. Instead of removing CO2 from the gas offshore, Shell will export some of it to the onshore St Fergus terminal for further treatment (OGJ Online, Mar. 18, 2022).
Estimated reserves at Jackdaw are 120-250 MMboe. At its peak, the field is expected to deliver 6.5% of UKCS gas production and produce energy equivalent to heating over 1.4 million UK homes.
BG International, an affiliate of Shell UK, is operator at Jackdaw (76%) with partner ONE-Dyas E&P holding the remaining 26%.
Drilling & Production Quick Takes
Strike produces historically strong gas flow at South Erregulla-1 test
Strike Energy’s South Erregulla-1 gas discovery in the onshore North Perth basin permit EP503 has recorded one of the highest sustained flow rates in the region’s history with a sustained rate of 78 MMcfd over a 5-hour test of the key Kingia Sandstone reservoir, the company said.
The flow was recorded through a 78/64-in. choke with a flowing wellhead pressure of 2,590 psi.
Production at higher rates was limited by pipework in the testing packages. Strike said the results indicated high potential to produce at unrestricted rates over 100 MMcfd.
The company has been testing the producibility from 15 m of perforations across the reservoir at 4,844 m measured depth.
No sand or formation water has been observed to date and the gas stream comprises a low impurity dry gas with no hydrocarbon liquids produced during the test—in line with gas compositions from the Greater Erregulla region.
Strike is running a final flow period prior to shutting the well in for pressure build-up, which will be monitored by downhole gauges recording subsurface pressure.
Once testing equipment is demobilized, the company will begin preparations for production testing the shallower over-pressured Wagina Sandstone discovery in the same well, requiring mobilization of a workover rig to isolate and reset the tubing at the Wagina level.
South Erregulla is 100%-owned and operated by Strike.
Equinor plugs dry well in Norwegian Sea
Equinor Energy AS has plugged a dry Norwegian Sea wildcat well and will proceed with drilling of a second area well, the Norwegian Petroleum Directorate said in a June 15 release.
Well 6305/5-C-3 H was drilled about 137 km west-northwest of Kristiansund by the Transocean Barents drilling rig to a vertical depth of 4,320 m subsea. It was terminated in the Shetland Group from the Turonian age. Water depth at the site is 925 m.
The objective was to prove petroleum in reservoir rocks in the Lange formation and the Lysing formation in the Upper Cretaceous (Turonian and Coniacian Ages, respectively). The well encountered mainly siltstone with thin layers of sandstone and dolomite stringers in both formations.
Data acquisition has been carried out. Attempts to collect pressure data and sampling indicate that the formations have low permeability and are partly tight.
The exploration well was the sixth in production license 209.
The rig will now continue in the same location to drill production well 6305/5-C-3 AH (OGJ Online, Jan. 27, 2022).
Equinor is operator of production license 209 with 40% interest. Partners are Petoro AS (35%), A/S Norske Shell (15%), and Vår Energi ASA (10%).
PTTEP begins Algeria Hassi Bir Rekaiz project production
PTT Exploration and Production Public Co. Ltd. (PTTEP) started Phase 1 production at the Algeria Hassi Bir Rekaiz project, onshore People’s Democratic Republic of Algeria.
Development of the oilfield cluster began in March 2019 (OGJ Online, Mar. 20, 2019). The production target is 13,000 b/d. In Phase 2, production capacity will ramp up to about 50,000-60,000 b/d in 2026-2027.
The project, in the eastern part of Algeria, contains Blocks 443a, 424a, 414ext, and 415ext. PTTEP and partners found oil and gas in 10 out of 11 exploration wells drilled in the 1,916-sq-km area during 2013-16 (OGJ Online, Aug. 19, 2016).
PTTEP is operator (49%) with consortium partner SONATRACH (51%).
Sasanof-1 gas wildcat offshore Australia comes up dry
The Sasanof-1 wildcat operated by Western Gas Corp., Perth, in permit WA-519-P on the Exmouth Plateau offshore Western Australia is a dry hole. The well, 200 km northwest of Onslow, was drilled to a total depth of 2,390 m by semisubmersible rig Valaris MS-1.
The prospect was a seismic amplitude-supported structural-stratigraphic trap, but the anticipated reservoir sands at the top of the Cretaceous Lower Barrow group formation target contained no hydrocarbons. Pre-drill estimates suggested the prospect could contain up to 7 tcf of natural gas and more than 170 million bbl of condensate.
While disappointed with the result, Western Gas still has ownership of the adjacent Equus gas discoveries, collectively estimated to contain around 2 tcf of gas and more than 40 million bbl of oil according to consultant Gaffney Cline.
Interests in the Sasanof well are Western Gas with 52.5% and operatorship, Global Oil & Gas with 25%, Prominence Energy 12.5%, and Clontarf Energy 10%.
PROCESSING Quick Takes
Incident damages crude unit at OMV’s Schwechat refinery
OMV Aktiengesellschaft, Vienna, will delay restart of its 9.6-million tonnes/year refinery at the operator’s integrated complex in Schwechat, Austria, following an early June upset that occurred at the tail end of the 2022 turnaround.
An unidentified mechanical incident occurred on June 3 that damaged the refinery’s main crude oil distillation unit and caused slight injuries to two individuals at the site, OMV said in a release.
As a result, scheduled maintenance at the refinery, which has been ongoing since Apr. 19, will be partially delayed, according to the operator.
An assessment of damage remains under way, and a definitive timetable for duration of the extended shutdown has yet to be determined, OMV said.
Without disclosing further details surrounding the incident, the operator said it will work closely with its customers and suppliers to mitigate any impact on product availability.
Confirmation of the incident follows OMV’s end-May announcement that it was completing final works and checks of the turnaround and preparing systems for restart.
In a May 31 release, the operator said refinery staff was in the process of slowing returning equipment to operation at the site, which potentially would result in flaring.
At the time, overall production was scheduled to resume once all system parts were safely in “warm” mode and integrated back into the production process.
According to OMV’s website, the 2022 turnaround only involved the refining portion of the Schwechat complex, which also produces ethylene, propylene, butadiene, and aromatics. In addition to maintenance and inspection of the refining plants, OMV said it also was using the turnaround period to execute modernization works that would prepare the refinery—Austria’s only—for a reduced-emissions future.
Schwechat’s petrochemical plants are scheduled for routine turnaround activities in 2023, the operator said.
Ecuador seeks strategic partner for Esmeraldas refinery upgrade
Ecuador’s state-owned Petroecuador is seeking proposals from domestic and international companies interested in becoming a partner in the rehabilitation, modernization, and integral operation of its 110,000-b/d Esmeraldas refinery on the Pacific Coast.
As part of the first-phase selection process, companies that wish to be considered as a potential strategic partner are to submit letters of interest to Petroecuador between June 13-24 to receive a data pack containing relevant technical, economic, and legal information, the operator said in a release.
Petroecuador said modernization and rehabilitation plans as part of the proposed partnership will involve construction and startup of a high-conversion unit to
process residues currently produced at the refinery as part of the operator’s plan to improve fuel quality for the domestic market.
Further details regarding the planned strategic partnership and upgrading project were not disclosed.
Consortium confirms, details contract award for Petrobras’s Replan refinery
A consortium of Toyo Setal Empreendimentos Ltda. (TSE) and Toyo Engineering Corp. has confirmed and provided further details regarding its scope of delivery under its recently awarded contract to build a new diesel hydrotreater at Petróleo Brasileiro SA’s (Petrobras) 434,000-b/d Refinaria de Paulínia (Replan) refinery in Paulínia, São Paulo, Brazil (OGJ Online, May 11, 2022).
Alongside providing engineering, procurement, and construction (EPC) services for the proposed $458-million diesel hydrotreating unit, Consórcio Toyo Setal HDT Paulínia’s scope will also cover EPC for an associated 150,000-cu m/d hydrogen recovery unit, as well as commissioning services for both new units, Toyo Engineering said in a June release.
Confirmation of the EPCC contract follows Petrobras’s May announcement of the contract award for Replan’s proposed diesel hydrotreater that, scheduled for startup in 2025, will enable the refinery to produce 100% low-sulfur Diesel S10 (10 ppm sulfur), as well as increase the refinery’s current production volumes by 63,000 b/d.
The planned unit also will increase Replan’s production of jet fuel by 12,500 b/d to help meet more stringent specifications and increased future demand for economically and sustainably produced cleaner fuels, Petrobras said previously.
Replan’s diesel hydrotreating project comes as part of the planned $6.1 billion Petrobras intends to spend on its refining business under the company’s 2022-26 strategic plan, as well as its previously announced RefTOP program, which aims to prepare the operator’s remaining refining assets both for an open, more competitive market in the country and the transition to a low-carbon economy.
Alongside expanding existing refining capacity, refining-related investments will focus on initiatives to increase efficiency and operational performance of Brazilian refineries not involved in operator’s divestment portfolio, which in addition to Replan, include the:
- 239,000-b/d Duque de Caxias (Reduc) refinery in the Baixada Fluminense area of Brazil’s Rio de Janeiro state.
- 252,000-b/d Refinaria Henrique Lage (Revap) refinery in São José dos Campos, São Paulo.
- 170,000-b/d Refinaria Presidente Bernardes (RPBC) refinery in Cubatão, São Paulo.
- 57,000-b/d Refinaria de Capuava (Recap) in Mauá, São Paulo (OGJ Online, Mar. 9, 2021).
TRANSPORTATION Quick Takes
Full return of Freeport LNG operations expected late 2022
Freeport LNG Development LP has extended the timeline for a return to operations at its liquefaction plant on Quintana Island, Tex., following a fire that broke out June 8.
Currently, completion of all necessary repairs and a return to full plant operations is not expected until late 2022. A return of partial operations is expected in about 90 days once regulatory clearances are obtained and safety can be assured, the company said in an update June 14.
The 15-million tonne/year liquefaction plant was initially expected to be shut for at least 3 weeks following a fire at the plant resulting from an incident that caused the release of LNG (OGJ Online, June 9, 2022). No injuries were reported.
The vapor cloud fire was contained within the fence line of the liquefaction plant, and lasted about 10 seconds, the company said. The fire and associated smoke visible thereafter were from the burning of materials in and around the location where the incident occurred, such as piping insulation and cabling. That fire was extinguished about 40 minutes after the initial incident. While the burning of those materials resulted in carbon monoxide, nitrous oxide, particulate matter, sulfur dioxide, and volatile organic compound emissions, these were of limited quantity due to the short duration of the fire and not at levels that posed any immediate risk to Freeport LNG personnel or the surrounding community, and no other chemicals or substances were released from the plant during the event, the company continued.
Water used to suppress the subsequent fire was captured on site and will be tested for harmful contaminants before being released or removed for proper disposal.
The incident occurred in pipe racks that support the transfer of LNG from the plant’s LNG storage tank area to the terminal’s dock infrastructure located on the intracoastal side of Freeport LNG’s dock basin. None of the liquefaction trains, LNG storage tanks, dock facilities, or LNG process areas were impacted, the company said.
Preliminary observations suggest that the incident resulted from the overpressure and rupture of a segment of an LNG transfer line, leading to the rapid flashing of LNG and the release and ignition of the natural gas vapor cloud, the company said.
An additional investigation is under way to determine the underlying events that enabled the overpressure conditions.
Venture Global to supply 1 million tpy of LNG to Petronas
Venture Global LNG Inc. and Petronas LNG Ltd., a subsidiary of Malaysian state-owned oil and gas company, Petronas, have executed a 20-year agreement for Petronas to purchase 1 million tonnes/year (tpy) of LNG from Venture Global’s 20-million tpy Plaquemines LNG plant.
The company has now announced 20-year sales agreements for 16 million tpy of Plaquemines LNG’s capacity: 4 million tpy, China Petroleum & Chemical Corp. (Sinopec); 2 million tpy, CNOOC Gas & Power Group Co. Ltd.; 2 million tpy, Shell NA LNG LCC; 2 million tpy, ExxonMobil LNG Asia Pacific (OGJ Online, May 10, 2022); 2 million tpy, New Fortress Energy Inc.; 1 million tpy, Électricité de France SA (EDF); and Polish Oil & Gas Co. (PGNiG) taking the balance.
Venture Global is developing Plaquemines LNG on a 630-acre site in Plaquemines Parish, La., about 20 miles south of New Orleans. The plant will use as many as 36 0.626-million tpy trains configured in 18 two-train blocks and will include up to three berths capable of handling LNG carriers as big as 185,000 cu m.
Earlier this year, Venture Global awarded Baker Hughes Co. a contract to provide the modular liquefaction units for the plant’s first phase. First deliveries are expected in 2023 to meet a 2024 startup date (OGJ Online, Mar. 9, 2022).
Canes Midstream acquires Cogent Midstream
Canes Midstream LLC, Dallas, closed a deal to acquire Cogent Midstream LLC, Dallas, the company said in a release May 25.
The Cogent assets, in the Southern Midland basin, include 520 MMcfd of processing capacity, over 800 miles of pipelines, 42 compressor stations, a crude oil gathering system, and acreage dedications from a group of Midland basin-focused producers, Canes said.
The Cogent system spans 10 counties in the basin with a large portion of the infrastructure in Reagan and Irion counties.
Canes is a portfolio company of EIV Capital and Denham Capital.
