OGJ Newsletter
GENERAL INTEREST Quick Takes
EIA: Crude oil exports may pass through Russian infrastructure
In March, President Biden banned US imports of crude oil refined petroleum products, natural gas, coal, and coal products that originate in Russia. The President’s executive order, however, does not restrict US energy imports originating in other countries that transit through Russia or depart from Russia’s ports, the US Energy Information Administration (EIA) noted.
Crude oil exported from countries including Kazakhstan, Azerbaijan, and Turkmenistan moves through Russia’s energy export infrastructure. Crude oil from Russia can be imported into the US, provided it is marketed and loaded with a certificate of origin verifying that the crude oil is of non-Russian origin.
Crude oil exported from Kazakhstan moves primarily through the Caspian Pipeline Consortium (CPC) system. The CPC travels around the north side of the Caspian Sea and through Russia, transporting crude oil produced in Kazakhstan to the Russian Black Sea port of Novorossiysk. Some crude oil produced in Russia is transported in the same pipeline as CPC grade crude oil, but it represents around 10% of the crude oil exported through the CPC system.
Crude oil is also exported from Kazakhstan through Russia’s Transneft pipeline system to Novorossiysk and the Russian Baltic Sea port of Ust Luga, as well as through the Kazakhstan-China Pipeline to China. Most exports originating in Kazakhstan travel by pipelines through Russia or are shipped out of Russia’s ports.
Exports of crude oil from Azerbaijan are largely transported through the Turkish port of Ceyhan through the Baku-Tbilisi-Ceyhan (BTC) pipeline, which does not pass through Russia. However, small amounts of crude oil are exported from Azerbaijan through Russia. Significant volumes of crude oil are not exported from Turkmenistan, but it can travel west to Ceyhan through the BTC pipeline or travel north to Novorossiysk from the Russian Caspian port of Makhachkala through the Baku-Novorossiysk pipeline. In 2021, 25,000 b/d was exported from Azerbaijan, and 43,000 b/d was exported from Turkmenistan through Russia, according to data from Argus Media.
In 2021, most exports of crude oil from Kazakhstan went to Europe, but some were received in the US. Ports on the US East Coast received 18,000 b/d of light, sour crude oil imports from Kazakhstan—representing less than 0.3% of US crude oil imports that year. Crude oil from Azerbaijan has not been imported into the US since 2018, and crude oil from Turkmenistan has never been imported into the US.
Northern Lights CCS project awards MWS contract, gets EU PCI status
Northern Lights JV DA has awarded Global Maritime a marine warranty surveying contract for its planned CO2 transportation and storage infrastructure. The JV consists of Equinor ASA, Shell PLC, and TotalEnergies SE.
Equinor last year awarded an engineering, procurement, construction, and installation contract for Northern Lights to Subsea 7 SA and a subsea control system contract for the project’s Oseberg A platform to Aibel AS (OGJ Online, Jan. 28, 2021).
Northern Lights is developing infrastructure that will transport CO2 by ship from capture sites across Europe to a terminal in western Norway for intermediate storage, before transporting it by pipeline for permanent storage in Johansen formation, 2,600 m under the Norwegian North Sea’s bed. This infrastructure will enable the mitigation of industrial process emissions for which there is currently no scalable solution, the JV said.
The first development phase of Northern Lights, supported by Norwegian authorities, will be completed by mid-2024, and be able to store 1.5 million tonnes/year of CO2, according to the JV. As demand from industrial sectors in Europe grows, Northern Lights will increase storage capacity. Construction of an onshore receiving terminal in Øygarden, Norway, is under way.
The European Union (EU) has designated Northern Lights a project of common interest (PCI). PCI projects and participants can benefit from simplified permitting and the right to apply for EU funding from the Connecting Europe Facility program.
Pandion Energy to acquire ONE-Dyas Norway operations
Pandion Energy AS has signed an agreement with ONE-Dyas Holdings BV to acquire ONE-Dyas Norge AS. The transaction includes a 10% share of Wintershall Dea-operated Nova field and interest in 11 exploration licenses.
Nova, in the northern part of the North Sea primarily in the PL418 license area, is being developed with two subsea templates tied back to the existing Gjøa platform. Nova (previously Skarfjell) was discovered in 2012. The reservoir contains oil and gas in the Late Jurassic Heather formation. The plan for development and operation was approved in 2018. The use of existing infrastructure enables effective extraction of resources and Nova will be operated with hydro power from shore through Gjøa. Nova is expected to start production in second-half 2022.
Pandion Energy currently produces over 5,000 boe/d through its 10% ownership in Valhall and Hod fields. This is set to increase when the new Hod B platform comes on stream in 2022. The Valhall area has been fully electrified from shore since 2013.
Exploration & Development Quick Takes
Santos finds oil in Pavo wildcat
Santos Ltd. made a significant oil discovery at Pavo-1 in Bedout subbasin offshore Western Australia that could add value to the existing Dorado oil and gas discovery 46 km to the west.
Pavo-1, in permit WA-438-P, was drilled on the northern culmination of the overall Pavo structure and encountered a 60 m gross thickness of oil column in the primary Caley member reservoir.
Wireline data confirmed 46 m of net oil pay with an oil-water contact intersected at 3,004 m, Santos said.
Reservoir quality is interpreted from logs to have an average porosity of 19% and permeabilities in the 100-1,000 milidarcy range. Hydrocarbon saturations average 80%, similar to those encountered at Dorado field.
Santos, as operator, has completed wireline logging operations to collect pressure, sample and rock data across the Caley reservoir. Rig site analysis indicates the oil is a light, sweet variety with an API value of about 52 degrees and a low gas-oil ratio.
A 2C contingent resource for the Pavo northern accumulation has been assessed at 43 million bbl of oil.
The result derisks the potential of the separate southern culmination in the structure.
The well result is expected to support a potential tie-back to the first phase of the proposed Dorado development with Pavo north having an estimated breakeven cost of less than US$10/bbl, said Kevin Gallagher, Santos managing director and chief executive officer.
Pavo also derisks nearby prospects including the next well in the program, Apus-1, in WA-437-P, which lies 31 km southeast of Dorado.
Pavo-1 is being drilled by jackup rig Noble Tom Prosser in water depth of 88 m. The well is drilling ahead to planned total depth of about 4,200 m to focus on early Triassic and upper Permian stratigraphy not previously drilled in the basin.
Upon final logs at total depth the rig will be moved to Apus-1 about 20 km southwest.
Santos has 70% interest in Pavo. Carnarvon Energy Ltd. has 30%.
SENER finalizes Zama unitization process
Mexican authorities reiterated Petróleos Mexicanos’s (Pemex) role as operator of Zama field offshore Mexico, a move partner Talos Energy Inc. has contested (OGJ Online, Sept. 7, 2021).
Talos received the final Unitization Resolution from Mexico’s Ministry of Energy (SENER) regarding, among other things, that Pemex would serve as operator of field development, it said in a release Mar. 28.
The Houston-based exploration and production company will participate in activities related to reaching final investment decision (FID), while also continuing to evaluate various strategic and legal options, according to the release.
Unitization of Zama was required as the field was determined to lie within both Talos-operated Block 7 and the adjacent AE-0152-Uchukil Asignación in the Cuencas del Sureste, in the Bay of Campeche in Mexico, operated by Pemex, providing for joint development of the entire reservoir instead of each party developing its own block.
Talos will maintain a 17.35% participating interest in the field, and the company anticipates submission of a unit development plan for approval by the working interest partners within 6-12 months. FID is expected in 2023.
Talos, as operator and 35% partner in the Block 7 lease, discovered Zama field in 2017 as the first private sector consortium to enter Mexico following the country’s energy reforms (OGJ Online, July 7, 2017). An independent third-party reserves auditor estimated discovered recoverable resource volumes of 735-950 MMboe, and Zama could produce over 160,000 boe/d once fully developed.
Talos has invested some $104 million in Zama since 2015 and these past investments are subject to cost recovery under the production sharing contract, it said.
ExxonMobil drills dry hole offshore Brazil
ExxonMobil Corp. drilled a dry hole at Cutthroat-1 exploration well in Sergipe-Alagoas basin, offshore Brazil, according to a press release by partner Enauta Participações SA.
Logging and final evaluation of the well concluded without verifying hydrocarbons in the well. The partner group will continue to integrate the exploration well data into its regional subsurface interpretation efforts to better understand the exploration potential of its deepwater blocks in the basin.
Cutthroat-1 was drilled by the Seadrill West Saturn drillship in Block SEAL-M-428, nearly 90 km offshore in 3,094 m of water. It is one of multiple prospects that the partner group has mapped in the basin.
ExxonMobil is operator (50%) in nine offshore SEAL blocks spanning over 6,800 sq km. Enauta holds 30% and Murphy Oil Corp. holds 20% working interest in the partnership.
Drilling & Production Quick Takes
Energy Resources delivers record Permian gas flow at Lockyer Deep-1
Energy Resources Ltd. noted record gas flow at Lockyer Deep-1 from the Permian-age Kingia Sandstone reservoir during initial testing. The well lies in North Perth basin permit EP368 onshore Western Australia.
The planned 6-day test program began Mar. 25 across a 25-m interval. The initial test was run for several hours during which flow rate was increased through a number of choke settings resulting in a maximum sustained flow rate of 102 MMcfd through a 76/64-in. choke.
The maximum instantaneous gas flow rate was 117 MMcfd—one of the highest rates recorded onshore Australia and the highest rate seen in the Perth basin gas play.
Well head pressure was 3,618 psi with the well capable of higher rates of delivery. The main flow period was halted due to indications of sand being produced to surface.
The flow contained CO2 impurities of 2-2.5% and hydrogen sulphide of 3-7 ppm. Condensate was recovered to surface with a preliminary condensate-gas ratio of 5-6 bbl/MMcf.
The test program is designed to determine well deliverability, reservoir quality, and gas composition, all of which were described as excellent. The well will be completed as a future producer.
The JV plans to drill additional wells in the exploration/appraisal program and acquire additional seismic data in the next 12-18 months to better define the resource.
Energy Resources is operator with 80% interest. Norwest Energy NL holds 20%.
Shell starts production from PowerNap
Shell PLC started production of the PowerNap subsea development in the Mars corridor, south-central Mississippi Canyon, about 150 miles from New Orleans in the US Gulf of Mexico.
The deepwater oil and gas field is tied back to the Shell-operated Olympus tension leg platform (71.5%) in about 4,200 ft of water. It has three production wells producing through a single insulated 19-mile flowline with high-pressure gas lift capability. PowerNap production will be transported to market through the Mars pipeline, operated by Shell Pipeline Co. LP and co-owned by Shell Midstream Partners LP (71.5%) and BP Midstream Partners LP (28.5%).
Estimated peak production from the field is 20,000 boe/d. Final investment decision was made in August 2019. Shell Offshore Inc. is operator with 100% interest.
Mubadala Petroleum starts production at Pegaga gas field
Mubadala Petroleum LLC started gas production from Pegaga gas field in Block SK 320, Central Luconia province, offshore Sarawak, Malaysia, in 108 m of water.
The development concept comprises of an integrated central processing platform (ICPP) consisting of an 8-legged jacket. The infrastructure is designed for gas throughput of 550 MMscfd plus condensate. Produced gas will be evacuated through a new 4 km, 38-in. subsea pipeline tying into an existing offshore gas network and subsequently to the onshore Petronas LNG complex in Bintulu.
The jacket and wellhead deck were constructed in Lumut and Kuching fabrication yards and were installed in April 2020 followed by the Pegaga development drilling campaign. The ICPP floatover and installation was completed in August 2021.
Mubadala is operator of the block with 55%. Partners are Petronas (25%) and Sarawak Shell Berhad (20%).
PROCESSING Quick Takes
Chevron Phillips adding new unit at Cedar Bayou plant
Chevron Phillips Chemical Co. LLC has let a contract to MHI Compressor International Corp. (MCO-I) to supply compressor train equipment for a new propylene unit to be added at the operator’s Cedar Bayou plant in Baytown, Tex., in the Houston Ship Channel, 28 miles east of Houston.
MCO-I’s scope of delivery will include an API 612 steam turbine and associated API 617 heat pump compressor, as well as all associated compressor train auxiliary equipment for a new 1-billion lb/yr C3 splitter designed to convert a refinery-grade mixture of propylene and propane into a high-purity propylene product, the service provider said on Mar. 29.
MCO-I said compressor train manufacturing, assembly, testing, and packaging will be performed by its fabrication sites in Hiroshima, Japan, and Pearland, Tex.
Chevron Phillips has yet to reveal any further details regarding the proposed new unit addition at Cedar Bayou, which currently produces ethylene, high-density polyethylene, low-density polyethylene, linear low-density polyethylene, normal alpha olefins, polyalphaolefins, and on-purpose 1-hexene, according to the company’s website.
This latest contract for work at the Baytown plant follows Chevron Phillips’ recently reached settlement with the US Environmental Protection Agency and the US Department of Justice to resolve a series of claims alleging the operator violated the US Clean Air Act and associated state air pollution control laws by illegally emitting thousands of tonnes of harmful pollutants via flaring at three of its Texas petrochemical manufacturing plants, including Cedar Bayou.
Russian refineries operating under capacity, sharpening European diesel shortage
Russian refineries are operating under capacity and are unlikely to recover in the short term, which could lead to more acute diesel shortage in Europe, according to a research note from Rystad Energy.
“There are presently 44 active refineries in Russia with a total capacity of about 7 million b/d. However, about 900,000 b/d of refining capacity is currently not being used. This is due to a range of factors including demand impacts from the Russia-Ukraine conflict, transportation bottlenecks, planned maintenance and/or scheduled turnarounds,” said Rystad analysts Annette Smith and Janiv Shah.
Prior to Russia’s invasion of Ukraine, around 320,000 b/d was already offline due to maintenance or scheduled turnaround at five Russian refineries. Since then, another five have reduced runs, taking an additional 550,000 b/d of crude distillation unit (CDU) capacity offline. Russian crude refining runs are poised to drop by about 400,000 to 500,000 b/d from previous estimates as the impact of the Russia-Ukraine war impacts demand.
“The likelihood of refineries in maintenance mode returning to full utilization or even restarting operations is low. The loss of Russian refinery is going to make diesel shortages in Europe more acute,” the analysts said.
“The ICE gasoil-Brent crack in Europe is trading around unprecedented levels of $25/bbl, higher than even the memorable gasoil crack spike in 2008. Russia currently exports around 800,000 b/d of diesel/gasoil to Europe. As Europe imports 1.5-2 million b/d of diesel/gasoil, an effective ban on Russia’s oil product exports could increase the gasoil crack further. It is important to note that diesel imports from the rest of the world were on a declining trend before the Ukraine crisis was instigated, and thus makes a potential loss of Russian ultra-low-sulfur diesel (ULSD) even more acute,” they continued.
The analysts also noted that refineries are already operating in diesel maximization mode vs. gasoline. The diesel strength could be a precursor for a stronger rally in gasoline ahead as the market is approaching summer months.
TRANSPORTATION Quick Takes
Canacol to select Colombia gas pipeline contractor this month
Canacol Energy Ltd. plans by mid-April to select a contractor for its 300-km, 100 MMcfd Jobo-Medellin natural gas pipeline, having received final binding bids from four companies. The pipeline would enter service by December 2024, carrying gas from a processing plant in Jobo, Colombia, to local utility Empresas Publicas de Medellin (EPM) and distribution companies.
Canacol has a contract in place with EPM for 55 MMcfd and is negotiating with three local gas distribution companies for the balance of the initial 100 MMcfd. Pipeline design will allow expansion to 200 MMcfd with additional compression.
All bids under consideration are build, own, operate, maintain agreements, with Canacol not planning to take a stake in the project. The company expects the pipeline to cost $560 million.
Canacol also plans to test a deep new gas play in Middle Magdalena basin via the Pola-1 well. New production could be tied into Transportadora de Gas Internacional SA ESP’s 730-MMcfd pipeline system, which has 260-MMcfd spare capacity, according to Canacol, and a branch 10 km from the Pola-1 wellsite.
The company last year published total Middle Magdalena mean estimated unrisked prospective gas resources of 5.25 tcf, in which it would have a 1.05-tcf working interest.
NOPSEMA grants approval for Shell Prelude FLNG restart
Australia’s National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) granted approval for Shell to restart operations on the Prelude floating LNG vessel moored 475 km offshore from Broome in Western Australia.
Prelude’s production was suspended following a fire and power outage in December 2021, following which NOPSEMA visited the vessel. (OGJ Online, Dec. 28, 2021).
Inspectors found that the power failures on the vessel directly impacted emergency response capabilities, the operation of safety critical equipment, the habitability of the vessel, and the functionality of process equipment required to effectively manage the LNG inventory.
Shell reportedly completed repairs in March, but has not said when it would bring the vessel back online. The company’s chief executive Ben van Beurden said in February that Prelude would probably be offline for most of the first quarter as the company works through the stages to prepare for hydrocarbon restart with safety and stability foremost in mind.
The $24 billion, 488 m-long vessel has capacity to produce 3.6 million tonnes per year (tpy) of LNG, 1.3 million tpy of condensate, and 0.4 million tpy of LPG.
Prelude was first brought on stream in 2018. After delays, it shipped its first cargo of LNG in June 2019.
Shell is operator with 67.5% interest. Inpex has 17.5%, Kogas 10%, and CPC 5%.
Tellurian begins Driftwood LNG construction
Tellurian Inc. issued a limited notice to proceed to Bechtel Energy Inc. under its executed engineering, procurement, and construction contract to begin construction of phase one of the 27.6-million tonne/year (tpy) Driftwood LNG liquefaction plant in Calcasieu Parish, La. First LNG is expected in 2026.
Bechtel’s first activities include demolition, civil site preparation, and construction of critical foundations. Baker Hughes will progress manufacturing two of the natural gas turbines required for phase one of the project.
Driftwood LNG would use 20 1.38-million tpy trains developed in five 4-train blocks to reach its maximum planned capacity. Phase 1 (11 million tpy) includes the first two of these blocks, two (of three planned) 235,000-cu m storage tanks, and the first of three planned loading berths.