GENERAL INTEREST Quick Takes
Companies to evaluate CO2 storage on Danish North Sea licenses
TotalEnergies has been awarded two licenses to explore CO2 storage potential in the Danish North Sea and will carry out evaluation and appraisal work to develop a project that could transport and store over 5 million tonnes/year (tpy) of CO2 through repurposed and new infrastructure.
The licenses, awarded by the Danish Minister for Climate, Energy, and Utilities, lie about 250 km off the west coast of Denmark and cover an area of 2,118 sq km. The acreage includes TotalEnergies-operated Harald gas fields, which are currently being assessed for CO2 storage opportunities, TotalEnergies said in a release Feb. 6.
“With the Northern Lights project under construction in Norway and projects under development in the Netherlands and the UK, the North Sea area will be the main contributor to our objective of 10 million tpy of CO2 storage by 2030,” said Arnaud Le Foll, senior vice-president, new business - carbon neutrality, TotalEnergies.
The awards were two of three granted by the Danish regulator. A consortium of INEOS and Wintershall Dea was also awarded a license. The applications were the only two received in the first of an annual tender round for licenses for exploration of full-scale CO2 storage on the Danish continental shelf held in August 2022. Work programs include an exploration well and a seismic survey. State-owned Nordsøfonden is participating in all three licenses with 20%.
Together, the licenses project a storage of upwards of 13 million tpy of CO2 in the Danish underground from 2030, the Danish Minister for Climate, Energy, and Utilities said in a release Feb. 6.
License permissions are initially granted for up to 6 years. If a suitable CO2 storage location is found, the permit can be extended for up to 30 years for storage operations, Danish Energy Agency said in a separate release Feb. 6.
Energy Resources JV offered exploration permits onshore Carnarvon basin
Energy Resources Ltd. (EnRes), Perth, and its joint venture partner Buru Energy Ltd. have been offered two new exploration permits in the onshore North Carnarvon basin of Western Australia to the south of Onslow.
The permits, L22-2 and L22-4, lie immediately south of the existing EnRes-Buru permit EP510.
The new permits were part of a recent Western Australian Government petroleum acreage release and have been offered to EnRes as operator and 75% interest holder with Buru holding the remaining 25%. Granting of the permits is subject to completion of the Native Title agreements.
L22-2 covers an area of 4,908 sq km and contains the southern extension of petroleum plays in EP510. The permit is prospective for both oil and gas.
L22-4 overlies the northern extent of the under-explored Merlinleigh subbasin and covers an area of 6,444 sq km. Several potentially large structures have been identified prospective for gas.
The JV is planning to drill two exploration wells in EP510 in 2024. The addition of the two new permits makes the JV to largest acreage holder in the onshore Carnarvon basin and Merlinleigh subbasin and is expected to facilitate optimization of exploration activities in the region.
All permits are near the Dampier-Bunbury natural gas trunkline.
TotalEnergies, QatarEnergy enter farmout for blocks offshore Lebanon
TotalEnergies expects to begin drilling offshore Lebanon “as soon as possible in 2023,” the company said following a farmout deal with Eni SPA and Qatar Energy.
TotalEnergies, operator of exploration Blocks 3 and 9 offshore Lebanon, and block partner Eni signed a deal whereby QatarEnergy will acquire 30% interest in the blocks.
The operator plans to begin drilling in Block 9 this year, said Patrick Pouyanné, TotalEnergies chairman and chief executive officer, in a release Jan. 29, noting that the company has teams “mobilized to conduct these operations.”
The decision to move ahead with drilling comes after a maritime boundary decision was reached between Israel and Lebanon on Oct. 27, 2022 (OGJ Online, Dec. 12, 2022).
The purchase and sales agreements were endorsed in Beirut on Jan. 29, 2022. Pursuant to the terms of the agreements, TotalEnergies (operator) and Eni will each retain 35% interest in the blocks.
Exploration & Development Quick Takes
Comstock increases proved reserves 9% year-over-year
Comstock Resources Inc. said it increased its yearend 2022 proved natural gas and oil reserves 9% to 6.7 tcfe from 2021 proved reserves of 6.1 tcfe.
The 2022 proved reserves were primarily natural gas, 38% developed, and 98% operated by Comstock, the company said in a release Feb. 1.
Comstock produced 501.1 bcf natural gas equivalent in 2022. In fourth-quarter 2022, Comstock’s production averaged 1,445 MMcfed, an increase of 7% over fourth-quarter 2021. Comstock added 1.1 tcfe to its proved reserves in 2022 through its Haynesville and Bossier shale drilling activities, which replaced 216% of the company’s 2022 production, it said.
Comstock spent $1.032 billion on drilling and other development activities in 2022. The company drilled 115 (60.4 net) new horizontal Haynesville and Bossier shale wells and put 104 (55.4 net) wells on sales during 2022. Comstock also spent $18 million acquiring a 145-mile pipeline and processing plant, $54.1 million on acquiring unproved acreage primarily for the company’s Western Haynesville play, and $500,000 on acquiring producing properties.
Trillion Energy discovers Black Sea gas
Trillion Energy International Inc. discovered gas from the Guluc 2 well at SASB gas field, offshore Turkey in the Black Sea.
The well, the third in a multi-well program, reached 3,910 m total measured depth and true vertical debt of 1,623 m on Jan. 26 and discovered an abundance of gas pay, the company said in a release Feb. 2.
Logging while drilling (LWD) results suggest 73 m of potential natural gas pay within 14 separate sands in the Akcakoca Member (SASB production zone). There are three gas sand reservoirs greater than 9 m thick each, and the LWD identified gas sands correlated with natural gas detected at surface in drilling mud, the company said.
Initial perforation intervals are currently being selected to bring the well into production. It is expected that only the lower zones of Guluc 2 will be perforated initially. Completion and flow testing will occur over the first weekend of February.
After completion of the well, the rig will be skid to the West Akcakcoa-1 well, which has 1,008 m of drilled surface hole.
Trillion Energy owns 49% of SASB field.
ConocoPhillips plans Otway exploration drilling program
ConocoPhillips Australia plans to undertake exploration activities in Australia offshore permits VIC/P79 and T/49P. The proposed activities are a continuation of the operator’s exploration program in the offshore Otway basin off the coast of Victoria and King Island, Tasmania, which aims to identify commercially viable natural gas reserves.
The proposed exploration program will involve seabed surveys and drilling up to a maximum of six exploration wells and commences no earlier than January 2024, subject to an accepted Environment Plan (EP), rig availability, and a conducive investment and regulatory environment, the company said.
The company is preparing an EP to submit to the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) for public comment and assessment.
A two-well drilling campaign is planned in late 2024/2025 subject to rig availability with a further four optional wells depending on success.
“The targeted exploration area is ideally located in Bass Strait in proximity to existing production facilities and infrastructure that predominantly supplies the east coast gas market and where the historical gas exploration success rate has been close to 100% for almost two decades,” said Noel Newell, executive chairman of 3D Oil. The company holds 20% interest in the permits after a farmout agreement with ConocoPhillips in 2020 (OGJ Online, June 16, 2020).
Final drill targets will be selected upon finalization of a risked and ranked prospect inventory across both permits, following completion of the Sequoia 3D MMS processing and interpretation, as well as 3D seismic reprocessing and interpretation activities in VIC/P79, 3D Oil said in a release Feb. 3.
ConocoPhillips Australia is operator of the permits with 80% interest.
Talos Energy lets modification contract for Ram Powell
Talos Energy Inc. has let a topside modification contract to EDG Inc. for the Ram Powell tension leg platform in the US Gulf of Mexico.
Modifications will accommodate the Venice and Lime Rock subsea tiebacks (OGJ Online, Jan. 4, 2023). EDG will be responsible for the engineering and design of the Viosca Knoll area platform additions, including all equipment integration, piping, structural, instrumentation, and electrical additions and modifications.
Lime Rock was acquired in Lease Sale 256 in November 2020 and is about 9 miles from the platform. The Upper Miocene discovery is expected to produce first oil in first-quarter 2024. The Upper Miocene Venice prospect was identified within the existing Ram Powell unit acreage about 4 miles from Ram Powell. First oil is expected in this year’s fourth quarter.
Talos originally held 100% working interest in both prospects prior to farmouts leaving 60% working interest.
Drilling & Production Quick Takes
Neptune spuds fourth well at Adorf Carboniferous development
Neptune Energy spudded the Adorf Z18 gas production well in the Adorf Carboniferous gas field, Georgsdorf, northwestern Germany.
The well is being drilled by KCA Deutag, with final depth of about 4,700 m expected to be reached in June this year.
The field was discovered in 2020 and the first well, Adorf Z15, was brought into production in October the same year. A second well, Adorf Z16, increased Neptune’s production from the license to around 4,000 boe/d at the beginning of 2022. The third well - Adorf Z17 - reached its final depth at the end of 2022 and will be tested for production this quarter (OGJ Online, June 30, 2022). The construction of a modern treatment plant for natural gas from Adorf Z17 and Z18 is ongoing.
Neptune Energy is operator and 100% owner of the field.
Elixir Energy reaches milestone in Mongolian CSG project
Elixir Energy Ltd., Adelaide, has reached pilot production of 100,000 cu f/d of gas and stable and low water rates of 180 b/d from its coal seam gas pilot project in the Nomgon IX production sharing contract in the South Gobi basin of Mongolia.
The two-well pilot program (Nomgon-8 and Nomgon-9) began in November 2022 and has been in operation for 83 days.
Nomgon-9 began producing gas from the first day of pumping with flow rates increasing steadily over the period, Elixir said. It has now reached 80,000 cu ft/d. The produced water has remained steady at 160 b/d.
Nomgon-8 experienced initial technical difficulties, necessitating a workover to flush and clean the production interval. Production has reached 20,000 cu ft/d of gas and water flow of 20 b/d. Elixir believes the flow rates will steadily increase.
The company has started interpretation of the ongoing Nomgon-9 production history and hopes to assess project commerciality in the coming months.
Elixir’s exploration and appraisal program for 2023 at Nomgon is expected to begin in this year’s second quarter. It will comprise drilling a minimum of nine wells (four appraisals, five exploration).
88 Energy to drill North Slope well
88 Energy Ltd. has been granted a drilling permit by the Alaska Oil and Gas Conservation Commission (AOGCC) to drill (PTD) in Project Phoenix (formerly Icewine East) on the North Slope of Alaska.
The Hickory-1 well is designed to appraise up to six conventional reservoir targets within the SMD, SFS, BFF, and KUP reservoirs and 647 million bbl oil. The well is permitted to a total depth of 12,500 ft.
A drilling location has been selected adjacent to the Dalton Highway directly adjacent to the Trans-Alaska Pipeline System (TAPS) utilizing data including interpretation of the Icewine-1 well logs, mapping and AVO analysis of the modern Franklin Bluffs 3D seismic data, and publicly available information from recent drilling and flow tests carried out on adjacent acreage by Pantheon Resources PLC.
Construction of the Hickory-1 ice-pad is set to begin soon. Mobilization of the Nordic Calista Rig-2 is scheduled to begin mid-February from the Pantheon Resources Co. Alkaid-2 well location. The company expects to spud the well early March.
Hickory-1 project manager Fairweather LLC has completed the tendering and contracting program for drilling operations. Well cost is estimated at about $13.5 million gross (about $10 million net to 88 Energy). Flow testing is planned for the 2023-2024 winter season.
Project Phoenix encompasses about 82,846 gross acres. It lies on-trend to recent discoveries by Pantheon Resources in multiple play types across top, slope, and bottom-set sands of the Mid Schrader Bluff, Canning, and Seabee formations. It holds an estimated unrisked conventional prospective oil resource of 647 million bbl.
88 Energy holds 75.2% working interest in the project.
PETRONAS signs production sharing contracts for clusters offshore Malaysia
PETRONAS signed production sharing contracts (PSCs) for three discovered oil and gas resource clusters marketed under the Malaysia Bid Round (MBR) 2022.
The A cluster was awarded to Ping Petroleum Sdn Bhd (PPSB) and Petroleum Sarawak Exploration & Production Sdn Bhd (PSEP). The A cluster lies 290 km off the coast of Miri, Sarawak, offshore Malaysia. PPSB will serve as operator with 70% participating interest. PSEP holds the remaining 30%.
The Meranti cluster, 80 km offshore Kuala Terengganu, Malaysia, was awarded to PPSB in partnership with Duta Marine Sdn Bhd. PPSB is operator with 60% participating interest. Duta Marine holds 40%.
Dialog Resources Sdn Bhd and PSEP won the bid for the Baram Junior cluster. Dialog will serve as operator with 70% participating interest, while PSEP will hold 30%. The agreement spans 14 years, including a 2-year pre-development phase and 2-year development phase. The agreement includes pre-development phase feasibility studies through 3D seismic data reprocessing, studies, and resource assessment.
All three PSCs were awarded under the Small Field Asset terms introduced in 2020.
PETRONAS plans to sign new PSCs with the MBR 2022 winning bidders for the exploration opportunities.
MBR 2023 is scheduled to be held Feb. 15, 2023.
PROCESSING Quick Takes
Diamond Green Diesel takes FID on Port Arthur SAF project
Valero Energy Corp. and Darling Ingredients Inc. have reached positive final investment decision (FID) to advance development of a sustainable aviation fuel (SAF) project at 50-50 joint venture (JV) Diamond Green Diesel Holdings LLC’s (DGD) 470-million gal/year renewable diesel and 20 million gal/year renewable naphtha plant near Valero’s 395,000-b/d refinery in Port Arthur, Tex. (OGJ Online, Feb. 8, 2021).
Scheduled for completion in 2025, the planned $315-million project will enable DGD’s Port Arthur plant to upgrade about 50% of its current 470-million gal/year production capacity to SAF, Valero said on Jan. 31.
Part the operator’s growth strategy focused on innovation in renewables, the project supports increased demand for SAF as an economic path to further reducing the carbon intensity of DGD’s products while expanding its long-term competitive advantage, said Joe Gorder, Valero’s chairman and chief executive officer.
DGD commissioned its Port Arthur renewable diesel plant in late 2022, which raised the operator’s total renewable diesel production capacity from its Port Arthur and Lake Charles, La., plants to 1.2 billion gal/year (OGJ Online, Jan. 26, 2023).
Parkland Burnaby refinery begins 2023 turnaround
Calgary-based Parkland Corp. has started a previously scheduled planned maintenance turnaround at subsidiary Parkland Refining (B.C.) Ltd.’s 55,000-b/d refinery on Burrard Inlet in North Burnaby, near North Vancouver, BC.
Beginning on Feb. 1, the scheduled maintenance event involves temporary shutdown of unidentified process units to enable cleaning, inspection, and routine servicing of equipment to ensure the refinery continues operating safely, reliably, and optimally, Parkland said.
While the operator did not reveal further details of specific units or works involved in the turnaround, Parkland confirmed the scope of planned activities during the maintenance event will require about 600 people on site per shift, or roughly 200 more than during regular operation of the refinery.
In addition to elevated visible flaring beginning on Jan. 31 that could last 6-8 days as units come offline for maintenance, Parkland advised local communities surrounding the refinery of potentially increased noise levels during daytime hours due to industrial vacuuming, high-pressure water cleaning, and jackhammering.
Parkland said it expects the turnaround to run through early spring but that a precise timeframe for the maintenance period would depend on its assessment of equipment status after works begin.
In its 2023 guidance issued in early December 2022, Parkland told investors the Burnaby refinery’s first-quarter 2023 planned turnaround would run for 8 weeks and require an estimated $100 million (Can.) to complete.
Parkland’s Burnaby refinery executed its last scheduled maintenance event during October-November 2021, the company said.
Refinery overview
The Burnaby refinery processes light and synthetic Canadian crudes such as Edmonton Par 80% and Syncrude 20% into gasoline, diesel, jet fuel, asphalt, heating fuel, heavy fuel oil, butane, and propane for distribution throughout British Columbia.
Parkland Fuel purchased the Burnaby refinery—which was the first in Canada to use existing infrastructure and equipment to coprocess biofeedstocks such as canola oil and oil derived from animal fats (tallow) alongside crude oil to produce low-carbon fuels— and related downstream assets from Chevron Canada Ltd. in 2017 (OGJ Online, Apr. 20, 2017).
In 2022, the operator announced it is also considering investments at the refinery that would include expanding its existing renewable coprocessing capabilities as well as adding a grassroots renewable diesel complex at the site.
TRANSPORTATION Quick Takes
EPP 2022 income up nearly 20%, $3.6 billion of projects set for 2023
Enterprise Products Partners LP (EPP) reported net income attributable to common unitholders of $5.5 billion for 2022, compared with $4.6 billion for 2021. Quarterly net income of $1.45 billion was up from $1.06 billion in fourth-quarter 2021, supported by a 17% increase in EPP’s gross operating margin for its NGL pipelines and services segment to $1.3 billion.
The company has $5.8 billion of major projects under construction, roughly $3.6 billion of which will be completed this year. Permian basin natural gas gathering additions will be occurring over the course of the year. Other projects set to be completed in 2023 include:
- Acadian Expansion II, 400 MMcfd incremental pipeline capacity, Haynesville shale-to-Louisiana Gulf Coast (Q2).
- PDH 2, 1.65 billion lb/year polymer grade propylene, Mont Belvieu, Tex. (Q2).
- Midland Basin Poseidon Plant 6, 300,000 b/d (Q3).
- Frac 12, 150,000 b/d fractionation, Mont Belvieu, Tex. (Q3).
- Mentone II, 300,000-b/d cryogenic natural gas processing plant, Loving County, Tex., Delaware basin (Q4).
- Texas Western Products System, 60,000-b/d batched refined products pipeline using both new and existing assets between Mont Belvieu, Tex., and Grand Junction, Colo. (Q4).
- Ethylene Export Expansion, 500,000 tonnes/year, Morgan’s Point, Tex., Houston Ship Channel (2H).
Tennessee Gas Pipeline gets draft EIS for Cumberland powerplant spur
Tennessee Gas Pipeline Co., a subsidiary of Kinder Morgan Inc., has received a draft environmental impact statement (EIS) from the US Federal Energy Regulatory Commission (FERC) for its 245-MMcfd Cumberland project. The 32-mile pipeline would run through Dickson, Houston, and Stewart Counties, Tenn., supplying the Tennessee Valley Authority’s (TVA) 1,450-Mw Cumberland natural gas combined-cycle powerplant, currently under development.
FERC concluded that—with implementation of Tennessee’s proposed impact avoidance, minimization, and mitigation measures, as well as adherence to Commission staff’s recommendations—project effects would be reduced to less than significant levels, except for climate change impacts that were not characterized in the EIS as significant or insignificant. The draft EIS comment period closes Mar. 27, 2023.
Cumberland will use 30-in. OD pipe and connect at Tennessee’s existing Line 100-3 and Line 100-4. It will also include a new bidirectional back-pressure regulation station in Dickson County at milepost 0.0 of the proposed Cumberland pipeline where it meets Line 100-3 and Line 100-4, and a new meter station at lines-end within TVA property in Stewart County.
TVA earlier this year decided to retire its Cumberland fossil plant and build the combined-cycle plant by 2026. The two-unit Cumberland fossil plant will retire in two stages, one unit by end-2026 and the second by end-2028. TVA says that construction of the combined-cycle natural gas plant—for replacement of one of the retiring Cumberland units—will reduce carbon emissions by as much as 60%.
Bulgaria starts building natural gas interconnector with Serbia
Interconnector Bulgaria-Serbia (IBS) has begun building the 62-km, 28-in. OD Bulgarian section of the 1.8-billion cu m/year (174-MMcfd) natural gas pipeline, running from the border between the two countries to Novi Iksar, Bulgaria. Total length of the reverse-flow capable pipeline is 170 km. The project will also include automated gas-regulating stations at Slivnitsa and Dragoman, Bulgaria, and a gas-metering station at Kalotina.
In a video message, European Union (EU) commissioner for energy, Kadri Simson, said: “The beginning of the works on IBS marks another critical milestone in the region’s pathway toward diversification of sources and routes. It is now crucial that both governments and operators closely cooperate to ensure that the pipeline is ready and operational in the second half of 2023.”
IBS is recognized as an EU project of common interest and was described by the Union as “part of a broader process of diversification of gas supplies and a steppingstone for energy secutiry enhancement. The project is necessary to reduce import dependence on Russian gas and provide alternative supply routes in southeast Europe, the EU said.
The EU co-funded the Bulgarian section of the €76.7-million pipeline segment with €27.6 million under the Connecting Europe Facility Energy program and €6 million from structural funds. Bulgartransgaz EAD is heading the project in Bulgaria. The EU also funded the Serbian section of the pipeline with a grant of €49.6 million through the Instrument of Pre-Accession scheme.