From wildcat successes to a call for bids, below is a compilation of the latest headlines in the E&P space. 

Activity headlines

Shell’s Pierce Field Goes Back Online

Natural gas is now flowing following upgrades at the Pierce Field in the U.K. North Sea, Shell announced on April 18. 

Discovered in 1975, Pierce had produced only oil since 1999. In 2019, Shell decided to upgrade the Haewene Brim FPSO and install a new subsea gas-export line that connected to the SEGAL pipeline routing gas to St. Fergus. The Bluewater-owned-and-operated FPSO stopped production in 2021 and spent six months in drydock for upgrades that would allow it to produce gas previously reinjected into the reservoir.

Peak production is expected at 30,000 boe/d, more than doubling output before the upgrade. More gas than oil will be produced. The field is located in 262-ft water depth.

Shell operates the field with a 92.5% stake on behalf of Ithaca Energy with 7.5%.

Bauge Begins Production 

Equinor Bauge
Bauge template picked up by Ocean Installer at Randaberg Industries. (Source: Ørjan Richardsen / Equinor)

Equinor and Neptune Energy announced  April 17 that production had begun from the Bauge subsea tieback to the Njord platform in the Norwegian Sea.

Equinor estimates recoverable reserves at Bauge are 50 MMboe. Bauge has two production wells. 

Equinor carried out extensive upgrades at the Njord A and Njord Bravo FSO.

“The Njord upgrading enables us to tie in new, valuable discoveries such as Bauge,” said Grete Haaland, Equinor senior vice president for exploration and production. “By utilizing existing infrastructure, we can realize profitable development of small-size discoveries in line with the company's strategy. We are planning further exploration activity in the area.”

Neptune said the Njord platform is preparing to receive production from its Fenja Field later this month.
Equinor operates the Bauge license with 42.5% interest on behalf of partners Wintershall Dea with 27.5%, Vår Energi with 17.5% and Neptune with 12.5%.

Aker BP, OMV Wildcats Find Oil

Deepsea Yantai
The well was drilled by the drilling rig Deepsea Yantai. (Source: Odfjell Drilling)

The Norwegian Petroleum Directorate (NPD) reported OMV and Aker BP will consider producing wildcat wells alongside other nearby North Sea discoveries.

The NPD reported April 20 that OMV’s 15/2-2 S well in PL 817 found 75 ft of thin sandstone layers with poor reservoir properties.

The Deepsea Yantai drilled the well in about 365 ft water depth about 3 miles from the Gudrun Field in the North Sea.

The well was not formation-tested, but data acquisition and sampling were undertaken. Due to the limited thickness of the sandstone layers and uncertainty in their dispersion, the preliminary estimate of the size of the discovery is between 0.95 MMcm to 5.55 MMcm of recoverable oil equivalent.

The licensees will evaluate the well result to define the volume potential in different reservoir zones and will assess the discovery alongside other prospects in the production license, the NPD said.

The NPD reported April 13 that Aker BP’s 25/4-15 wildcat well in PL 919 found a 103-ft oil column. The Scarabeo 8 drilled the well in 390 ft water depth about 3 miles west of the Vilje Field in the North Sea. Small-scale formation tests were conducted, and data acquisition and sampling also were also carried out. The well has now been permanently plugged and abandoned.

Preliminary calculations of the size of the find were between 0.5 MMcm and 0.8 MMcm of recoverable oil. The licensees will assess the discovery together with others in the vicinity in regard to a possible development.

Trintes Bravo Back Online after Fire

Trinity Exploration & Production has resumed oil production at its Bravo platform in the Trintes Field offshore Trinidad and Tobago following an April 10 fire, the operator announced on April 20.

The generator-related fire was quickly extinguished. Four operators were onboard Trintes Bravo at the time, and all four suffered from smoke inhalation. Two received minor burns. Damage at the Bravo facility was limited to the generator.

Trinity received approval from the Ministry of Energy and Energy Industries on April 17 to resume production on the Bravo platform, restarting the next day. Production had resumed at the Alpha and Delta platforms on April 11. 

The Trintes Field produces approximately 1,000 bbl/d.

C-NLOPB Calls for Bids

The Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) issued calls for bids for exploration licenses for 47 parcels in the Eastern Newfoundland and South Eastern Newfoundland regions, the board announced April 17.

Sealed bids are due at noon Newfoundland Time on Nov. 1, 2023, and awards to successful bidders are expected in early 2024.

The sole criterion for selecting a winning bid will be the total amount of money the bidder commits to spend on exploration of the parcel during the first period of the nine-year license, and the minimum bid for the parcels offered is $10 million in work commitments.

Contracts and company news

Woodmac: FIDs of Up to $185B in 2023 

Woodmac Pre FID project
Reserves associated with FIDs expected in 2023. (Source: Wood Mackenzie)

Wood Mackenzie projects up to $185 billion in upstream oil and gas final investment decisions (FID) to recover 27 Bboe to be made in 2023.

“Achieving FID on oil and gas projects is harder than it used to be, but with fewer sanctioned in 2022 than was expected, we believe we will see a slight uptick in activity this year, with over 30 of the 40 most viable projects likely to reach this milestone,” said Fraser McKay, vice president and head of upstream analysis for Woodmac.

“Most operators will remain disciplined, and carbon mitigation will remain a key part of many FID projects.”
National oil companies will control the largest investment opportunities this year, according to Woodmac. 

“International oil companies (IOCs) will be focusing largely on higher-cost, but higher-return deepwater developments,” said McKay. “All will be acutely aware of how oil and gas project sanctions are playing out in the public domain and the scrutiny to which their associated emissions will be subject.”

The average unit development cost of $7/boe in 2023 is down slightly from 2022. In 2023, projects will require an average of $49/bbl of crude to generate a breakeven 15% internal rate of return. Rapid paybacks will be a key economic indicator as well, with the average for this year’s projects at nine years.

Drilling Systems Wins Petronas Work

Drilling simulation company Drilling Systems, part of the 3t Energy Group, won a three-year contract from Malaysia’s Petronas.

Drilling Systems announced April 12 it will provide its drilling well on a simulator (DWOS) solution to support Petronas’ training and development program.

Chevron Surrenders Canadian Permits

Chevron Canada Ltd. said April 13 it was relinquishing 19 offshore oil and gas permits on Canada's west coast within the Scott Islands marine National Wildlife Area and the Hecate Strait and Queen Charlotte Sound Glass Sponge Reefs Marine Protected Area. 

The 19 offshore oil and gas permits cover an estimated 5,700 sq km that overlap portions of federal marine-protected areas offshore British Columbia. 

Aquanaut Commissioning Begins

Nauticus Robotics announced April 13 that commissioning exercises of the first of three second-generation Aquanauts, dubbed the Mark 2 (MK2), had begun. Following commissioning, Nauticus expects to send the initial Aquanaut MK2 units to the North Sea and the Gulf of Mexico.

New Pre-Salt R&D Lab Planned

Petrobras is teaming up with Shell and Senai CIMATEC to further pre-salt research and development, the Brazilian operator announced April 19.

The $50.3 million production development laboratory will enable safe operating conditions similar to the Brazilian pre-salt for testing integrated systems. It will enable evaluation of new equipment before it is used in the field. A 300-m deep well will be drilled in the complex, and connected to a flow loop.

The laboratory is being built inside Senai CIMATEC Park in the Petrochemical Camaçari Cluster, and is expected to begin operations in 2024.

The project is funded by Petrobras and Shell with resources from the research, development and innovation clause of the National Agency of Petroleum, Natural Gas and Biofuels. The laboratory is expected to start operating in 2024.

Nabors, Corva Team Up

Corva and Nabors Industries announced April 20 a technology partnership to simplify the execution of automation on alternating current (AC) rigs.

Integrating Corva’s App Store and Dev Center with Nabors’ SmartROS universal drilling rig controls and automation system is expected to deliver solutions that scale process and machine automation, enhance remote project oversight, and streamline data exchange and collaboration across any AC rig fleet.

SmartROS helps to digitize and automate drilling processes. Current deployments of SmartROS are used in more than 124 Nabors rigs in the Lower 48, Latin America and the Middle East, as well as 15 non-Nabors rigs.

Nabors' RigCLOUD enables edge computing for remote operations. This provides additional flexibility in deploying advisory automation apps to non-SmartROS enabled rigs.

Corva features more than 100 apps and dashboards that automate, monitor and optimize drilling processes. This suite encompasses a number of cutting-edge applications including predictive drilling, a state-of-the-art machine learning technology that enhances rotary drilling performance.

Leveraging the power of artificial intelligence, Corva's predictive drilling applications have provided meticulously designed data visualizations to 27,000 wells, covering 596 million ft. Using SmartROS, Corva extends rig control and real-time data pipelines from the wellsite to the E&P company’s back office and mobile devices, enabling customers to drill safer and more effectively. Equipped with Nabors’ Smart Suite of drilling automation products, RigCLOUD Edge infrastructure, and Corva Apps and Dev Center, this integration empowers onsite and remote users to interact, analyze and collaborate in new ways.

Eni Extends Santorini Contract

Saipem announced April 19 it had received a two-year contract extension from Eni for the seventh-generation Santorini drillship. The extension, valued at $280 million, starts August 2023.

Enteq Sells XXT MWD

Enteq Technologies announced April 13 it had sold its XXT MWD intellectual property and associated assets to Rime Downhole for a multimillion-dollar sum.

The sale comes as Enteq expands into new U.S. headquarters in Houston to continue developing the SABER (Steer-At-Bit Enteq Rotary) tool.

SABER is Enteq’s alternative to traditional rotary steerable systems (RSS) for directional drilling.  SABER had its first round of testing earlier this year and is undergoing development ahead of further testing in the U.S. this summer.

“The sale of XXT doesn’t mean an exit from MWD for Enteq,” Enteq CEO Andrew Law said. “In fact, it reflects our focus on developing differentiated specialist MWD products and rotary steerable technologies, where there is a larger addressable market.”

C-Innovation Expands in Port Fourchon

C-Innovation, an affiliate of Edison Chouest Offshore, expanded into a new facility in Port Fourchon, Louisiana, providing an additional dock facility for subsea inspection, maintenance and repair, and riserless light well intervention services. 

The dedicated docks, along with C-I’s current docking location, will provide the company’s clients with faster mobilization, demobilization and between-wells maintenance times.

The second facility offers vessel loading, project-system integration testing, and mobilization and demobilization services. With 1,500 sq ft of linear dock space and 400,000 sq ft of yard space, the location features a Manitowoc 888 crane and a Taylor 36,000-lb forklift. 

Jotun Launches All-Climate Coating

Jotun announced April 20 it had launched the Jotachar JF750 XT all-climate, fire-protection coatings.

Jotun spent five years on internal testing at its Svalbard test facility and third-party testing on the coating, which is certified to NORSOK M501 (2022) and UL2431. It is also third-party tested and certified to key industry fire and cryogenic spill protection standards, including listing to UL1709 in addition to Lloyds Register and DNV Type Approvals for pool fire, jet fire and cryogenic-spill protection.

“Oil, gas and petrochemical companies are increasingly investing in facilities located or constructed in some of the world’s most challenging environments,” Andy Czainski, global category manager of hydrocarbon fire and jotun performance coatings, said. “They need to be confident that their assets will have certified protection in the event of fire or cryogenic spill in such harsh conditions.”

New Oil Sludge Treatment Technology Launched

Envorem has developed a new greentech that uses a property of water to rapidly and inexpensively process oil-production sludges, the company announced April 20.

The technology uses very little energy to disassemble sludges, clean the solids and recover the entrained oil for recycling, according to Envorem.

The core technology combines established techniques with hydraulic shock and cavitation, creating bubbles through vaporization of water. Cavitation can be generated ultrasonically, electrically or physically.

Envorem recently completed a successful pilot in Oman to treat sludge and oil-contaminated soil. The pilot proved the technology generates a fraction of the emissions of thermal treatment and is both cheaper and faster, and 99% of the oil was removed from sludge as crude of usable quality.

The oil and maritime industries discard the equivalent of more than 1 MMbbl/d of oily sludge, according to Envorem.

In Western Europe, sludges are usually thermally treated, either by incineration or thermal desorption, which are costly. Incineration releases about 1.5 mt of CO2 per metric ton of sludge. Desorption consumes immense amounts of energy, usually burning the oil it recovers as fuel to reduce costs and generate similar emissions. 

Regulatory updates

BSSE Revises Decommissioning Requirements

The U.S. Bureau of Safety and Environmental Enforcement published decommissioning requirements for rights-of-use and easement grant holders in the Federal Register.

On April 17, BSEE announced the revised requirements and formalized BSEE’s policies regarding performance by predecessors ordered to decommission Outer Continental Shelf facilities. 

“If not properly decommissioned, offshore oil and gas infrastructure can become safety hazards, cause environmental harm, or become obstructions by interfering with navigation, fishing or other uses of the Outer Continental Shelf,” said BSEE Director Kevin Sligh. “The revised regulations provide the certainty requested by industry about how BSEE pursues decommissioning compliance from affected lessees and grant holders, helping operators to plan for future decommissioning actions and improving industry’s compliance with decommissioning obligations.”

BOEM Updates Spill Damages Liability Limits

The U.S. Bureau of Ocean Energy Management (BOEM) announced April 13 it will increase the limit of liability for oil spill-related damages from $137.66 million to $167.8 million for offshore oil and gas facilities.  

The inflation adjustment is mandated by the Oil Pollution Act of 1990 (OPA) and is based on the increase in the Consumer Price Index between 2016 and 2022. The increase is needed to keep pace with inflation and goes into effect in mid-May. 

The increase applies to facilities handling oil and gas in federal and state waters seaward of the coastline. The limit-of-liability cap applies to damages that result from oil spills, but does not apply to other liabilities such as oil spill-removal costs, which remain unlimited.