OGJ Newsletter

 GENERAL INTEREST Quick Takes

EIA: Strong demand for diesel leads to high prices going into winter

Strong demand for ultra-low sulfur diesel (ULSD, the most widely consumed form of distillate fuel oil) in October, combined with reduced global production, has resulted in higher ULSD prices and lower inventories in the US, the US Energy Information Administration (EIA) said.

“Current inventories and our current estimate of future demand can be combined into a metric called days of supply, which is calculated by dividing the inventory (in bbl) by the estimated demand (in b/d) to get the number of days that inventories alone could meet demand. In October 2022, the US had 25 days of supply of distillate, the fewest since 2008. US days of supply between 2017 and 2021 averaged 34 days. US inventories of distillate fuel oil have been below the previous 5-year (2017–21) low since the start of 2022,” EIA said.

Days of supply, however, is not a complete snapshot of distillate fuel oil availability because it doesn’t consider production, imports, or any sources of supply other than inventories, EIA noted.

In October 2022, the New York Harbor spot price for ULSD averaged $4.36/gal, the highest monthly price since May 2022. The increase in diesel prices, both in the US and globally, has been the result of several factors, such as tight global inventories, reduced refinery production in Europe following labor strikes, and the start of seasonal demand for distillate as a home heating fuel.

Reduced refining capacity in the US and globally since 2020 is one of the main reasons for low distillate inventories in the US. Distillate fuel consumption this year, through August, remained below pre-pandemic levels but was higher than in 2020. More distillate consumption combined with less distillate production contributed to the lower inventories. Increasing demand in October, measured as product supplied, contributed to greater pressure on those inventories and resulted in a decrease in October days of supply relative to September.

“The Northeast—the combined New England and mid-Atlantic regions—has had even tighter inventories than the US average. Lower inventories have contributed to rising prices in the region. US distillate demand is seasonal; specifically, consumption increases in the winter because it is used for home heating, mostly in the Northeast,” EIA said.

Marathon Oil to double Eagle Ford position through Ensign acquisition

Marathon Oil Corp., Houston, has agreed to acquire the assets of Ensign Natural Resources LLC, Houston, an exploration and production company operating in the Eagle Ford shale in South Texas, for total cash consideration of $3 billion.

The deal nearly doubles Marathon’s Eagle Ford shale position with inventory adjacent to its legacy position and immediately competes for capital, the operator said in a release Nov. 2.

Marathon will gain 130,000 net acres (99% operated, 97% working interest) that span Live Oak, Bee, Karnes, and Dewitt Counties across the condensate, wet gas, and dry gas phase windows of the Eagle Ford, and an estimated 600 undrilled locations. Estimated fourth-quarter 2022 production is 67,000 net boe/d (22,000 net b/d of oil).

Marathon Oil believes it can hold fourth quarter production flat with 1 rig and 35-40 wells to sales per year.

The deal also includes 700 existing wells, most completed pre-2015 with early generation completion designs, which offers redevelopment potential, none of which was considered in the asset valuation or inventory count, Marathon Oil said.

Post-closing, expected by yearend, Marathon Oil will hold 290,000 net acres in the Eagle Ford.

Hokchi Energy to farm out interest offshore Mexico to Wintershall

Hokchi Energy, the Mexican subsidiary of Pan American Energy, has agreed to farmout a 37% non-operated interest in Hokchi block in Sureste basin offshore Mexico to Wintershall Dea.

The deal includes a conditional option for Wintershall to increase its participation up to 40% at a later stage, Wintershall said in a release.

The block was awarded in Mexico’s licensing round 1.2 and is operated by Hokchi Energy. The shallow-water block is developed as a subsea tie-back to two offshore platforms, Satellite and Central, and was brought on-stream in May 2020 following an appraisal campaign.

The well stream is piped over 24 km from the two offshore platforms to an onshore processing plant where oil and gas is separated and treated for further sale to Mexican state company Pemex. The block currently produces around 26,000 boe/d with a planned ramp-up to a gross production of 37,000 b/d by 2023.

In Mexico, Hokchi Energy and Wintershall Dea are already partners in Block 2, in the southeast of the Gulf of Mexico.

The deal is expected to close before the end of first-quarter 2023 subject to government approvals, including from Mexico’s National Hydrocarbons Agency and antitrust agency.

 Exploration & Development Quick Takes

Equinor postpones Wisting investment decision to 2026

Equinor Energy AS and partners have postponed an investment decision on the Barents Sea Wisting project to end-2026 from December 2022.

The operator cited cost increases from global inflation and cost growth in the supply industry nationally and internationally as reasons for the delay, as well as uncertainty surrounding framework conditions and execution capacity in the supplier market.

The operator and partners will further mature the development concept and the power-from-shore solution, as well as consider new supplier models, Equinor said in a release Nov. 10.

Further exploration activity aiming to increase the resource base in the area is planned, added Aker BP chief executive officer Karl Johnny Hersvik in a separate release. Aker BP holds 35% non-operated interest in the project.

The project, with an updated investment estimate of NOK 104 billion, lies in production license (PL) 537 in the Hoop area 310 km north of Hammerfest in water depth of 390-418 m.

Equinor is operator with 35% interest. Partners are Aker BP AS (35%), Petoro AS (20%), and INPEX Idemitsu Norge AS (10%).

ExxonMobil discovers hydrocarbons offshore Angola

ExxonMobil discovered hydrocarbons in Block 15, about 365 km northwest off the coast of Luanda, Angola, in 1,100 m of water.

Bavuca South-1, part of the Angola Block 15 redevelopment project, marks the eighteenth discovery in the block and the first in nearly 20 years, the company said in a release Nov. 7. The exploration well, drilled by the Valaris DS-9 rig, encountered 30 m of high-quality, hydrocarbon-bearing sandstone.

The redevelopment project is expected to deliver around 40,000 b/d of oil (OGJ Online, June 15, 2019).

There have been 17 previous discoveries on Block 15: Hungo, Kissanje, Marimba, and Dikanza in 1998; Chocalho and Xikomba in 1999; Mondo, Saxi, and Batuque in 2000; Mbulumbumba, Vicango, and Mavacola in 2001; Reco Reco in 2002; and Clochas, Kakocha, Tchihumba, and Bavuca in 2003.

ExxonMobil affiliate Esso Exploration Angola (Block 15) Ltd. is operator of Block 15 (36%) with partners BP Exploration (Angola) Ltd. (24%), ENI Angola Exploration BV (18%), Equinor Angola Block 15 AS (12%), and Sonangol P&P (10%). The National Agency for Petroleum, Gasand Biofuels (ANPG) is the Block 15 Concessionaire. In March, bp PLC and Eni SPA agreed to form a new 50-50 independent company, Azule Energy, through the combination of the two companies’ Angolan businesses (OGJ Online, Mar. 11, 2022).

TotalEnergies to develop Block 9 offshore Lebanon

TotalEnergies SE signed a framework agreement with the State of Israel for exploration of a prospect which might extend both into Block 9 and Israel waters south of the recently established Maritime Border Line.

A maritime boundary was reached between Israel and Lebanon on October 27, 2022. Under the agreement, the border line will straddle the Qana prospect gas field. Production and exploration will be based on the Lebanese side, but Israel will be compensated for any gas extracted from its side, according to The National.

Preparation of exploration activities will start immediately with mobilization of teams, purchase of required equipment, and procurement of a drilling rig.

TotalEnergies is operator of Block 9 (60%) with partner ENI SPA (40%).

 Drilling & Production Quick Takes

CNOOC begins production at MDA gas field offshore Indonesia

Husky-CNOOC Madura Ltd. (HCML) started production at MDA field, the largest gas field of the 3M project in shallow waters offshore Indonesia, CNOOC Ltd. said in a release Nov. 15.

The 3M project lies some 75 km southeast of Madura Island in the Madura Strait, East Java, with an average water depth of around 80 m. The project contains three dry gas fields with a total of nine gas-producing wells.

Gas is produced through a floating production unit (FPU) with design capacity of 175 MMcfd.

MBH gas field, also part of the 3M project, began production in October. Once the five gas-producing wells of MDA field are put on stream, a peak daily production from the 3M project of about 127MMcfd is expected.

The 3M project is operated by HCML. As a joint venture partner, CNOOC Southeast Asia Ltd., a wholly owned subsidiary of CNOOC Ltd., holds 40% interest. Cenovus Energy Inc. holds 40%, and Samudra Energy Ltd. holds 20% interest.

Equinor granted consent to operate Mikkel field through 2039

Equinor Energy AS was granted consent by the Petroleum Safety Authority Norway to extend operation of Mikkel gas and condensate field in the Norwegian Sea.

Consent for extended operation has been granted until Dec. 31, 2039, from the previous expiration date of July 3, 2023.

Pressure decline in the reservoir has been less than anticipated, resulting in increased recoverable volumes compared to PDO estimates of 20 bcm of dry gas and 35 million bbl of condensate. Installation of the Åsgard subsea gas compressor has accelerated and prolonged gas production.

Mikkel field lies in the eastern part of the Norwegian Sea on Halten Bank, 30 km north of Draugen field in water depth of 220 m. It was discovered in 1987 and the plan for development and operation was approved in 2001. The field is developed with two subsea templates tied back to the Åsgard B semisubmersible floating platform. Production began in 2003.

Mikkel produces gas and condensate from Jurassic sandstone in the Garn, Ile, and Tofte formations. The field consists of six structures separated by faults, all with good reservoir quality. It has a 300-m thick gas-condensate column and a thin underlying oil zone. The reservoir depth is 2,500 m.

Equinor is operator with 43.97%. Partners are Var Energi ASA (48.38%) and Repsol Norge AS (7.65%).

Laredo Petroleum guides production lower quarter-over-quarter

Laredo Petroleum expects fourth-quarter 2022 production of 72,500-75,500 boe/d (32,000-34,000 bo/d) and capex (excluding non-budgeted acquisitions) of $135-145 million.

The guidance has incorporated increased expectations for production downtime associated with offset operator completions. The Permian basin-focused company is currently operating two drilling rigs and one completions crew and expects to complete 13 wells and turn-in-line 11 wells in this year’s fourth quarter.

For this year’s third quarter, the company reported net income of $337.5 million and cash flows from operating activities of $182.6 million. Adjusted net income was $89.2 million.

Laredo’s total and oil production during the period averaged 79,613 boe/d and 34,994 b/d, respectively.

The company completed 11 wells and turned-in-line 12 wells during third-quarter 2022. Total incurred capital expenditures were $140 million, excluding non-budgeted acquisitions and leasehold expenditures. Investments included $120 million in drilling and completions activities, inclusive of $6 million of non-operated activities, $2 million in land, exploration, and data related costs, $10 million in infrastructure, including Laredo Midstream Services investments, and $8 million in other capitalized costs. Non-budgeted acquisitions and leasehold expenditures totaled $4 million.

 PROCESSING Quick Takes

Shell commissions Pennsylvania petrochemical complex

Shell Chemical Appalachia LLC has officially started operations at its long-planned Shell Polymers Monaca (SPM) petrochemical complex atop a 386-acre site southwest of Monaca, Pa., along the Ohio River in Potter and Center Townships, Beaver County, 30 miles northwest of Pittsburgh.

Commencing operation as of Nov. 15, SPM will produce about 1.6 million tonnes/year (tpy) of polyethylene upon ramping up to its full nameplate capacity, which is scheduled to occur by second-half 2023, Shell said in a release.

First proposed as a potential investment project in 2012, Shell began construction on SPM in April 2017 following the operator’s final investment decision (FID) to move forward with the development in June 2016.

Upon announcing official commercial operation, Shell confirmed SPM contracted at FID for most of the complex’s required natural gas feedstock from regional gas operators in nearby Utica and Marcellus basins.

While details about feedstock supply agreements were not revealed, Shell previously said the Monaca complex will receive the entirety of its regionally-sourced ethane feedstock via Shell Pipeline Co. LP’s Falcon ethane pipeline system, a 97-mile common carrier ethane pipeline that—stretching across southwestern Pennsylvania, West Virginia, and eastern Ohio—connects Monaca with three major ethane source points in the rich-gas portions of Marcellus and Utica shale reservoirs: Houston, Pa.; Scio, Ohio; and Cadiz, Ohio.

Designed to produce ethylene, high-density polyethylene (HDPE), and linear low-density polyethylene (LLDPE) from Marcellus and Utica shale ethane, Shell’s Monaca site houses a dual 1.5-million tpy ethylene and 1.6-million tpy polyethylene complex, which features seven tail gas and natural gas-fired ethane cracking furnaces with a heat input rating of 620 MMbtu each to support the ethane cracker and three polyethylene units.

The complex’s two gas-phase polyethylene manufacturing lines each are equipped to produce 550,000 tpy of either HDPE or LLDPE-grade pellets, while a third manufacturing line outfitted with INEOS AG’s slurry-loop reactor polyethylene technology will produce 500,000 tpy of HDPE pellets. Alongside installations for steam generation, storage, logistics, cooling water, and wastewater treatment, the complex also houses a 250-Mw cogeneration power unit that uses natural gas and steam to meet the site’s full electricity requirement, according to project documents.

SPM is part of Shell’s strategy to reduce its production of traditional fuels and accelerate its transition by 2050 to net-zero emissions. The strategy includes consolidating the company’s refinery footprint to five core energy and chemicals parks that maximize integration benefits of conventional fuels and chemicals production while also offering new low-carbon fuels and performance chemicals.

Lukoil commissions Kstovo refinery’s deep-processing complex

PJSC Lukoil subsidiary LLC Lukoil Nizhegorodnefteorgsintez (NNOS) has completed construction and initiated startup of the operator’s long-planned deep conversion, delayed coking complex at its 17-million tonne/year (tpy) Kstovo refinery in central Russia’s Nizhny Novgorod region (OGJ Online, Mar. 24, 2021).

Once fully operable, the new 2.11-million tpy delayed coking plant will increase the refinery’s production of Euro 5-quality diesel production by 1.1 million tpy, as well as slash its production of fuel oil by 2.6 million tpy, Lukoil said.

Previously scheduled for startup in fourth-quarter 2021, Nizhny Novgorod’s new deep conversion, delayed coking complex also includes a:

• 2.11-million tpy delayed coker.
• 1.5-million tpy combined diesel fuel and gasoline hydrotreater.
• 50,000-cu m/hr hydrogen production unit.
• 425,000-tpy gas fractionator.
• 81,000-tpy combined elemental sulfur-sulfuric acid production unit (OGJ Online, Apr. 6, 2022).

 TRANSPORTATION Quick Takes

Coral Sul loads first LNG cargo offshore Mozambique

Eni SPA, operator of the Coral South project offshore Mozambique, has loaded the 3.4-million tonne/year (tpy) Coral Sul floating LNG (FLNG) plant’s first cargo. bp Shipping Ltd.’s 174,000-cu m British Sponsor LNG carrier picked up the LNG and is enroute to the Suez Canal for likely delivery to Europe.

bp has a 20-year agreement to purchase 100% of Coral South’s output. Eni introduced feed gas to Coral Sul in June 2022 (OGJ Online, June 20, 2022). The FLNG plant is fed by natural gas from ultradeepwater Coral field, Area 4, Rovuma basin. Eni estimates Coral’s reserves at 16 tcf.

The start of shipments from Coral South will add supply to a global natural gas market expected to remain tight in the medium term. Last month, the 24th Ministerial Meeting of the Gas Exporting Countries Forum (GECF) predicted gas market tightness will start easing only after 2025 when additional new projects start coming online (OGJ Online, Oct. 27, 2022). GECF also said that geopolitical tensions had exacerbated the supply-demand imbalance, with Europe becoming the preferred destination for LNG cargoes in the wake of Russia’s invasion of Ukraine. 

Area 4 is operated by Mozambique Rovuma Venture SPA, an incorporated joint venture owned by Eni, ExxonMobil Corp., and China National Petroleum Corp., which holds a 70% interest in the Area 4 exploration and production concession. Other shareholders in Area 4 are Galp Energia SGPS SA, Korea Gas Corp. and Mozambique-state Empresa Nacional de Hidrocarbonetos EP, each with 10%. Eni is the delegated operator of both Coral South and all upstream activities in Area 4.

Russia to finance, help build Iranian products pipeline

Sina Energy Gostar Holding and Russian-state Promsyrieimport have agreed to construct a 150,000-b/d refined products pipeline from Rafsanjan to Mashhad, Iran. The 948-km pipeline will include two pump stations and three terminals, according to Iranian oil ministry news agency Shana.

The two companies will build the Tabash pipeline under an engineering, procurement, construction, and finance contract, with Russia paying for it. Shana said the project will take 4 years to complete.

WBI gets draft EIS for North Dakota natural gas pipeline

WBI Energy Transmission Inc. received a draft environmental impact statement from the US Federal Energy Regulatory Commission for its 60.5-mile, 12-in. OD Wahpeton Expansion natural gas pipeline project in Cass and Richland Counties, ND, stating that its effects would not be significant. The pipeline will ship 20.6 MMcfd of gas to Kindred and Wahpeton, ND.

Wahpeton Expansion would include:

• A new 60.5-mile, 12-in. OD natural gas pipeline.
• Minor modifications to WBI’s existing Mapleton compressor station.
• A new Montana Dakota Utilities (MDU)-Wahpeton border station.
• A new MDU-Kindred border station.
• Seven new block valve settings.
• Four new pig launcher-receiver settings.

WBI plans to begin construction in early 2024, pending regulatory approvals, to meet an in-service date of November 2024.

Transco asks FERC for expansion approval by Nov. 30

Williams Cos. Inc. unit Transcontinental Gas Pipe Line Co. LLC (Transco) has asked the US Federal Energy Regulatory Commission (FERC) to approve its 829-MMcfd Regional Energy Access (REA) expansion by Nov. 30, 2022. Transco said that delay beyond that point would cause it to miss “construction windows established to protect certain threatened and endangered species,” postponing the project by as much as 12 months. The company had planned to place the expansion in service in time for the 2023-24 heating season (OGJ Online, May 6, 2021).

Transco filed its application for REA on Mar. 26, 2021, and received its final environmental impact statement from FERC on July 29, 2022. Williams says the project will maximize use of existing infrastructure and be built “in a manner that is adaptable to future renewable energy sources like clean hydrogen and renewable natural gas blending.”

Renewable Energy Access includes:

• New electric-driven Compressor Station 201 in Gloucester County, NJ.
• 22.3 miles of 30-in. lateral in Luzerne County, Pa.
• 13.8 miles of 42-in. loop in Monroe County, Pa.
• Modifications to five existing compressor stations in New Jersey and Pennsylvania.
• Modifications to existing meter stations.