GENERAL INTEREST Quick Takes
Continental Resources increases spending 47%
Continental Resources Inc. expects to raise spending by 47% in 2022 and oil production by about 25%, it said as part of its Feb. 15 earnings statement.
The operator is projecting a $2.3 billion capital expenditures budget, excluding Franco Nevada’s share of mineral costs. About $1.8 billion is allocated to drilling and completions activities and an additional $500 million is being allocated primarily for leasehold, mineral acquisitions, workovers, and facilities.
The capital expenditures budget includes a 15% increase to legacy spending in the Bakken and Anadarko basins combined with a $500-million increase attributed to the company’s recently acquired positions in the Permian and Powder River basins (OGJ Online, Nov. 4, 2021; Mar. 15, 2021).
With that, Continental expects annual crude oil production of 195,000-205,000 b/d. Annual natural gas production expected to be 1,040-1,140 MMcfd. At year-end 2022, Continental projects a working backlog of about 175 gross operated wells in progress in various stages of completion.
Full-year 2021 total production averaged 329,600 boe/d. Full-year 2021 oil production averaged 160,600 boe/d. Full-year 2021 natural gas production averaged 1,014 MMcfd. Fourth-quarter 2021 total production averaged 340,200 boe/d, up slightly from third-quarter’s 331,400 boe/d. Fourth-quarter 2021 oil production averaged 166,700 b/d. Fourth-quarter 2021 natural gas production averaged 1,041 MMcfd.
The company reported full-year 2021 net income of $1.66 billion. Adjusted net income for full-year 2021 was $1.70 billion. Net cash provided by operating activities for full-year 2021 was $3.97 billion.
The company reported net income of $742.7 million for fourth-quarter 2021, up from $369.3 million in third-quarter 2021. Adjusted net income for fourth-quarter 2021 was $651 million. Net cash provided by operating activities the quarter was $1.25 billion.
Whiting increases Sanish field interests in separate acquisitions
Whiting Petroleum Corp., Denver, entered into two separate agreements to acquire non-operated oil and gas assets in the Williston basin of North Dakota from unnamed sellers.
The assets are being acquired from two private companies for total cash consideration of $273 million, before closing adjustments. The assets are in Mountrail County, ND, and increase the average operated working interest to 74% from 61% throughout Whiting’s Sanish field, impacting many of the drilling units included in the company’s current 2022 development program.
The assets include 14,563 net acres, 4 gross / 0.2 net drilled and uncompleted well interests, and 277 gross / 32 net undrilled locations. Whiting expects to develop the undeveloped locations near term. The assets should contribute about 4,500 boe/d (67% oil) at closing.
The smaller transaction closed in fourth-quarter 2021, and the larger acquisition is scheduled to close first-quarter 2022.
The company last year acquired Williston basin assets in Mountrail County, ND, from an unnamed private company for $271 million (OGJ Online, July 22, 2021).
Whiting’s 2022 capital plan includes operating two drilling rigs and one completion crew in the Williston basin for most of the year. The 2022 budget was designed with higher working interests and slightly greater activity. A delay on a five-well pad in January will impact the timing of production until later in the year. While Whiting has shifted operations to Sanish field, the company’s continued focus on sustainability through increasing its high gas capture percentage will result in production volumes not entirely replacing those lost by the delay, the company said. The rigs will operate in Mountrail, McKenzie, and Williams Counties, ND. Whiting plans to drill additional three-mile laterals further west in McKenzie County, ND during the year, the company said.
Denbury, NRP to evaluate CO2 sequestration on Alabama coast
Denbury Carbon Solutions LLC, a Denbury Inc. subsidiary, together with a subsidiary of Natural Resource Partners LP (NRP), agreed to jointly evaluate potential development of a permanent CO2 sequestration site on Alabama’s Gulf Coast.
The agreement provides Denbury with the exclusive rights to develop a CO2 sequestration site on 75,000 acres of pore space controlled by NRP in Baldwin County, near Mobile, Ala. Denbury estimates total CO2 storage potential to be over 300 million metric tons. Depending on the pace and scale of regional CCUS development, Denbury may consider expanding its existing Gulf Coast CO2 pipeline network to connect to this site.
Subject to title diligence, Denbury plans to complete a technical site evaluation to ensure suitability for CO2 sequestration, while pursuing agreements to transport and store CO2 emissions from nearby existing or planned industrial facilities. The site could be ready to receive CO2 by 2026.
Exploration & Development Quick Takes
ExxonMobil plans multi-well Canje block drilling campaign
ExxonMobil Corp. subsidiary Esso Exploration & Production Guyana Ltd. (EEPG) plans to begin a multi-well drilling campaign on Canje block, offshore Guyana, in this year’s fourth quarter with the conclusion expected by first-quarter 2025.
The operator applied to the Guyana Environmental Protection Agency for a 12 well exploration and appraisal program on the block, about 180 km offshore in 1,700-3,000 m of water, adjacent to Stabroek block.
The well program aims to gather data on reservoir characteristics, hydrocarbon presence, pressures, and temperatures, according to the filing. If presence of hydrocarbons is discovered, wells will be tested to establish the limits of the reservoir. Productivity of wells and oil or gas properties present will also be tested. Once proposed drilling operations are complete, the exploration well will be permanently plugged and abandoned.
Based on the water depths in Canje block, multiple dynamically-positioned drill ships will be used for drilling.
EEPG is operator (35%) at Canje block. Partners are Total (35%), JHI (17.5%), and Mid-Atlantic Oil & Gas Inc. (12.5%).
TotalEnergies to withdraw from North Platte
TotalEnergies E&P USA Inc. will not sanction the North Platte deepwater project in the US Gulf of Mexico. The decision to withdraw from the project was taken as the company decided to allocate its capital to other portfolio opportunities.
North Platte field straddles four blocks of the Garden Banks area, 275 km off the coast of Louisiana in 1,300 m of water.
In 2020, Total E&P USA Inc. let a front-end engineering and design contract to Worley for the development (OGJ Online, Jan. 24, 2020). At the time, the operator said the reservoir was of high quality, both in porosity and permeability, with thickness in places exceeding 1,200 m and a development plan was based on eight subsea wells and two subsea drilling bases connected via two production loops to a newbuild, lightweight floating production unit. Oil production had been expected to average 75,000 b/d at plateau level.
TotalEnergies holds a 60% operated interest in North Platte, alongside its joint-interest owner Equinor (40%). The company has duly notified its partner and relevant authorities of its immediate withdrawal from the project, and of its resignation as operator which will be effective following a short transition period to ensure an orderly hand-over of operatorship.
Dragon Oil makes discovery in Gulf of Suez
United Arab Emirates company Dragon Oil Co. discovered oil in the Gulf of Suez. The field contains potential reserves of around 100 million bbl, inside the northeastern region of Ramadan, according to a Feb. 15 statement from the Egyptian Minister of Petroleum and Mineral Resources.
Details on a possible development plan were not reported, but reserve numbers could expand, the ministry said.
The oil field is the first discovery by Dragon Oil since it acquired 100% of bp’s Gulf of Suez Petroleum Co. assets in 2019 (OGJ Online, June 5, 2019).
Badria Ahmed Khalfan, chief human resources officer at Dragon Oil, said at the ongoing Egypt Petroleum Show (EGYPS) in Cairo that the company “aims to reach production rates of 65,000-70,000 b/d, compared to an average of 60,000 b/d in 2021,” according to international media.
Dragon Oil holds 100% interest in East Zeit Bay off the southern Gulf of Suez region. The 93-sq km block lies in shallow waters of 10-40 m.
Dragon Oil is 100% owned by Emirates National Oil Co.
Equinor drills dry well northwest of Norwegian Sea Draugen field
Equinor Energy AS collected data from a recent Norwegian Sea exploration well before plugging. The well is dry, without traces of petroleum.
Well 6407/9-13—the first in production license 1060—was drilled by the West Hercules drilling rig about 148 km north of Kristiansund and about 8 km northwest of Draugen field to a vertical depth of 2,319 m subsea. It was terminated in the Ror formation from the Early Jurassic. Water depth at the site is 270 m.
The primary exploration target was to prove petroleum in reservoir rocks from the Late Jurassic (the Rogn and Melke formation), while the secondary exploration target was to prove petroleum in reservoir rocks from the Middle Jurassic (the Garn and Ile formation).
In the primary target in the Melke formation, sandstone rocks totaling 27 m were encountered, with very good reservoir quality. The well did not encounter reservoir rocks belonging to the Rogn formation.
In the secondary exploration target, the well encountered sandstone rocks totaling 76 m in the Garn formation and sandstone rocks totaling 17 m in the Ile formation. The reservoir rocks in both formations are of good to very good reservoir quality.
The drilling rig will now proceed to Canada for new assignments.
Eni discovers gas offshore Abu Dhabi
Eni ASA has discovered natural gas offshore the Emirate of Abu Dhabi. Interim results from the first exploration well in Abu Dhabi’s Offshore Block 2 Exploration Concession indicate 1.5–2 tcf of raw gas in place.
Well XF-002, in 115 ft of water, discovered gas in place in multiple good quality reservoirs of the Jurassic exploration targets. Drilling operations will continue to reach the deeper exploration targets of Khuff and Pre-Khuff formations. After completing drilling in the second quarter, final findings will be assessed.
Eni is operator with 70% interest in the 4,033 sq-km block, awarded in January 2019 in the first-ever competitive bid round for exploration blocks launched by Abu Dhabi National Oil Co. (ADNOC) (OGJ Online, Jan. 14, 2019). PTTEP holds the remaining 30%.
Eni is operator of three exploration licenses in Abu Dhabi and participates with ADNOC in three offshore development and production concessions, Lower Zakum (5%), Umm Shaif and Nasr (10%), and Ghasha (25%).
This discovery marks the first from Abu Dhabi’s offshore exploration concessions.
Drilling & Production Quick Takes
Santos spuds Pavo-1 wildcat in Bedout subbasin
Santos Ltd. has spudded Pavo-1, the first of two wildcats to the east and southeast of the Dorado and Roc oil and gas discoveries in Bedout subbasin offshore Western Australia.
The Noble Tom Prosser jack up rig is drilling ahead in 12.25-in. hole.
Pavo-1 is targeting potential recoverable reserves of around 80 million bbl of liquids and 108 bcf of gas in the Caley formation which flowed gas at equipment limits of 11,000 b/d of oil at Dorado-3.
The well lies in permit WA-438-P and about 160 km north-northeast of Port Hedland and about 40 km east of Dorado field. Water depth is 90 m.
The JV believes the trapping mechanism in the target reservoir is a top seal of Hove formation shale with lateral seals provided by canyon-fill shales and is similar to Dorado field.
The Pavo structure is broader than Dorado and has northern and southern highs separated by a saddle. Pavo-1 is targeting the larger northern high.
After drilling the Caley primary target, the JV has an option to drill into deeper stratigraphic horizons including the Lower Archer formation Dumont Member sands and Permian-age carbonates.
The well is expected to take 2 months to drill and test. It will be followed by the Apus-1 wildcat in a structure that straddles the WA-438-P/WA-437-P boundary about 20 km southwest of Pavo-1.
Santos is operator of WA-438-P with 70% interest. Carnarvon holds 30%. Santos is operator of WA-437-P with 80% interest. Carnarvon holds 20%.
ExxonMobil starts Liza Phase-2 production at Stabroek block
ExxonMobil Corp. started production at Liza Phase 2, Guyana’s second offshore oil development on Stabroek block, bringing total production capacity to more than 340,000 b/d in 7 years since the country’s first discovery.
The Liza Unity floating, production, storage, and offloading (FPSO) vessel arrived in Guyana in October 2021 and is moored in about 1,650 m of water. It will be able to store around 2 million bbl of crude. Production at the Liza Unity is expected to reach its target of 220,000 bbl later this year.
The FPSO adds to the more than 120,000 b/d of capacity at the Liza Destiny FPSO, which began production in December 2019 and is delivering at better than design capacity.
Stabroek block’s recoverable resource base is estimated at more than 10 billion boe and has the potential to support up to 10 projects. ExxonMobil anticipates that four FPSOs with a capacity of more than 800,000 b/d will be in operation on the blocl by yearend 2025.
Payara, the third project in the block, is expected to produce about 220,000 b/d using the Prosperity FPSO vessel, which is currently under construction. The field development plan and application for environmental authorization for the Yellowtail project, the fourth project in the block, have been submitted for government and regulatory approval.
ExxonMobil affiliate Esso Exploration and Production Guyana Ltd. is operator at Stabroek block (45%) with partners Hess Guyana Exploration Ltd. (30%) and CNOOC Petroleum Guyana Ltd. (25%).
RCMA gains regulatory approval to drill wildcat onshore North Perth basin
The joint venture led by RCM Australia (RCMA) Pty Ltd. received regulatory approval to drill the proposed Cervantes-1 wildcat in the onshore North Perth basin production permit L14 in Western Australia.
The prospect is within the producing Jingemia oil field license and lies on the coast to the southwest of Jingemia field and between Hovia and Cliff Head (offshore) oil fields. Together, the three fields have produced over 27 million bbl of oil from the main Permian-age reservoirs in North Perth basin.
The Cervantes feature is a high-side fault trap of multiple Permian reservoir units and shares a similarity with the surrounding discovered fields.
The prospective reservoirs of Dongara, Kingia, and High Cliff sandstones could contain up to 15 million bbl on a best (2U) estimate.
Cervantes-1 will be operated by RCMA with drilling management services supplied by Aztech Well Construction Pty Ltd. The estimated spud date is mid-March depending on the release of the rig currently drilling Strike Energy’s South Erregulla-1 further to the east.
The well is to be 50% funded by Vintage Energy Ltd., Adelaide, and 50% by Metgasco Ltd., Sydney, both of which farmed into the permit in late 2019 to participate in the Cervantes wildcat (OGJ Online, Nov. 18, 2019).
The resulting interests are RCMA 40% and operatorship, Vintage 30%, and Metgasco 30%.
PROCESSING Quick Takes
RusGazDobycha’s Baltic Chemical lets EP contract for Ust-Luga complex
JSC RusGazDobycha subsidiary Baltic Chemical Complex LLC (BCC), through its contractor, has let a contract to Samsung Engineering Co. Ltd. to provide engineering and procurement (EP) for the ethane cracker of BCC’s $13-billion ethane-cracking complex, or gas chemical complex (GCC) portion, of the larger PJSC Gazprom-RusGazDobycha combined gas processing, liquefaction, and chemical complex for processing ethane-containing gas (CPECG) under construction at the Gulf of Finland near the seaport of Ust-Luga, Leningrad Oblast, Russia, 110 km southwest of St. Petersburg (OGJ Online, June 10, 2020).
Samsung Engineering’s scope of work under the €1-billion contract awarded directly by main contractor China National Chemical Engineering & Construction Corp. Seven Ltd. will include EP services on the GCC’s two-trained ethane cracker unit that, upon startup, will have a combined design capacity of 2.8 million tonnes/year (tpy), the service provider said on Feb. 9.
Officially awarded on Feb. 8, this latest EP contract for the GCC portion of the CPECG follows BCC’s previous €1.17-billion contract award to DL E&C Co. Ltd. in early January for unidentified EP services on the GCC project.
Alongside BCC’s GCC, the CPECG—which officially began construction in May 2021—also includes RusKhimAlyans’—a 50-50 special-purpose venture of Gazprom and RusGazDobycha—integrated natural gas processing and liquefaction complex (GPC of the CPECG), which will have 13-million tpy liquefaction capacity and initially process 45 billion cu m/year (bcmy) of wet natural gas feedstock it receives from Gazprom’s Achimov and Valanginian deposits in the Nadym-Pur-Taz region of the Yamal Peninsula (OGJ Online, May 24, 2021).
Once operable, the GPC will produce as much as 4 million tpy of ethane, and more than 2.2 million tpy of LPG, with ethane from the complex to feed nearby BCC’s ethane cracking project that will produce more than 3 million tpy of polymers. About 18 bcmy of gas remaining after processing at GPC—including ethane extraction, LPG, and 13 million tpy of LNG—will be exported from the site via Gazprom’s gas transmission lines (OGJ Online, Mar. 29, 2021).
RusGazDobycha most recently said it expects to wrap first-phase construction of the GCC during fourth-quarter 2023, with second-stage construction to be completed in fourth-quarter 2024.
Tüpras¸ adding alkylation capacity to Turkish refineries
Türkiye Petrol Rafinerileri AS¸ (Tüpras¸) has let a contract to Honeywell UOP LLC to deliver alkylation technology for new units to be installed at its four Turkish refineries as part of the operator’s plan to boost production of cleaner gasoline in tow with its broader energy transition goals.
As part of the Feb. 9 contract, Honeywell UOP will license the Chevron USA Inc.-developed ISOALKY alkylation technology that uses a nonaqueous liquid salt, or ionic liquid, instead of hydrofluoric acid (HF) or sulfuric acids as a liquid alkylation catalyst to produce a high-octane alkylate blending component for production of clean-burning fuels, the service provider said.
Alongside enabling safety and performance advantages over other alkylation processes—including simpler handling procedures and on-site regeneration of ionic liquids— ISOALKY technology will allow Tüpras¸ refineries to produce low-sulfur, zero-aromatics, high-octane alkylate to help lower emissions and tailpipe pollution from light-duty, gasoline-powered vehicles in Turkey, Honeywell UOP said.
Neither Tüpras¸ nor Honeywell UOP revealed additional details of the newly awarded contract, including information regarding the number or capacities of ISOALKY units to be installed, or a general timeframe for implementation of the proposed units.
Tüpras¸’s selection of the technology follows FJ Management Inc. subsidiary Big West Oil LLC’s late-2021 contract award to Honeywell UOP for licensing of the process as part of the conversion of an existing HF alkylation unit at Big West’s 33,000-b/d refinery in North Salt Lake City, Utah, into an ISOALKY alkylation unit (OGJ Online, Nov. 11, 2021).
Gazprom Neft’s Omsk refinery nearing startup of new clean-diesel plant
PJSC Gazprom Neft subsidiary JSC Gazpromneft-ONPZ is progressing with startup activities for a new diesel production plant as part of the second phase of the operator’s ongoing modernization program to reduce environmental impacts and improve processing capacities, conversion rates, energy efficiency, and production qualities at its 22-million tonnes/year Omsk refinery in Western Siberia (OGJ Online, Mar. 20, 2020).
With precommissioning testing initiated in late January and still under way, the new diesel hydrotreating and dewaxing plant, once online, will process 2.5 million tpy of crude to increase the refinery’s current production of environmentally friendly Euro 5-quality diesel by one third, enabling Gazpromneft-ONPZ to decommission two outdated plants to help further reduce overall emissions from processing activities at the site, Gazprom Neft said.
At a total cost of 17.5 billion rubles and equipped with unspecified technology to improve low-temperature properties of its finished product, the soon-to-be-commissioned diesel production plant will yield diesel that will be able to operate efficiently at temperatures as low as -40° C. Advanced digital control systems included at the plant also will provide Gazpromneft-ONPZ flexibility to adjust proportional output of summer or winter diesel grades without interrupting operations based on seasonal and market demand, according to the operator.
While Gazprom Neft did not disclose a timeframe official startup, the company did confirm Gazpromneft-ONPZ is nearing the test-run phase to produce a trial diesel batch ahead of fully commissioning the companion units.
TRANSPORTATION Quick Takes
Gazprom, CNPC sign gas supply agreement
Gazprom and China National Petroleum Corp. (CNPC) signed a long-term sales and purchase agreement for natural gas to be supplied via the Far Eastern route.
When the project reaches full capacity, Russian pipeline gas supplies to China will grow by 10 billion cu m (bcm), totaling 48 bcmy (including deliveries via the 4,000 km Power of Siberia gas trunkline).
This is the second long-term sales and purchase agreement for gas to be signed by the companies. In 2014, Gazprom and CNPC signed a 30-year agreement for 38 bcm via the eastern route (Power of Siberia pipeline) and 30 bcm via the western route (Altai pipeline) (OGJ Online, Nov. 11, 2014).
In January 2022, a feasibility study was completed for the Soyuz Vostok gas trunkline construction project. The trunkline will become an extension of Russia’s Power of Siberia 2 gas pipeline in Mongolian territory and will make it possible to supply up to 50 bcm to China.
Venture Global to load first Calcasieu Pass LNG cargo
Venture Global LNG Inc. requested US Federal Energy Regulatory Commission (FERC) permission to introduce hazardous fluids at its 10-million tonne/year (tpy) Calcasieu Pass liquefaction plant’s south jetty and to load its first commissioning cargo on or after Feb. 9, 2022. The plant, in Calcasieu Parish, La., produced its first LNG on Jan. 19.
Calcasieu Pass LNG will use 18 0.6-million tpy liquefaction trains arranged in two-train production modules. Commercial operations are expected to begin mid-2022.
Venture Global expects its 20-million tpy Plaquemines LNG plant to begin operations in 2024. The company has two other 20-million tpy plants under development in Louisiana: Delta LNG in Plaquemines and CP2, adjacent to Calcasieu Pass in Calcasieu Parish.
Cedar LNG awards FEED to Black & Veatch, Samsung
Cedar LNG, a partnership between the Haisla Nation and Pembina Pipeline Corp. on Douglas Channel in Kitimat, BC, has signed Black & Veatch and Samsung Heavy Industries Co. Ltd. for front-end engineering and design of the project’s proposed 3-million tonne/year floating LNG plant.
The partnership also applied for an environmental assessment certificate with the British Columbia Environmental Assessment Office, moving the project into the 180-day application review phase. The application follows studies, engineering, and engagement with Indigenous and local communities.
Cedar LNG expects to make a final investment decision (FID) in 2023 following completion of the EAC process. Subject to additional factors, including regulatory and other approvals, the expected in-service date for the project is 2027.
The partnership has already secured 400 MMcfd of long-term transportation on TC Energy Corp.’s 420-mile Coastal GasLink pipeline. Pending regulatory approvals and FID by Cedar LNG, work on the 10-km Cedar Link project, connecting Coastal GasLink to the plant could start as early
as 2025.