GENERAL INTEREST Quick Takes
LUKOIL to increase ownership in Caspian Sea Shah Deniz project
PJSC LUKOIL agreed to acquire a 15.5% interest in the Shah Deniz natural gas project in the Azerbaijan sector of the Caspian Sea from Petronas in a deal valued at $2.25 billion.
Following completion of the sale, LUKOIL’s interest in the bp-operated (28.8%) project will increase to 25.5% from 10%. Other partners are TPAO (19%), SOCAR (10%), NICO (10%), and SGC (6.7%).
Shah Deniz gas-condensate field, bp’s largest gas discovery, was found in 1999 and is estimated to hold 1 trillion cu m of gas. It covers 860 sq km and lies in water depths up to 500 m. The first phase of field development, Shah Deniz 1, began production in 2006, delivering more than 10 billion cu m/year (bcmy) (OGJ Online, Dec. 8, 2006). The second phase, which started in 2018, increase the designed production level by 16 bcmy (OGJ Online, July 2, 2018).
In first-half 2021, the field produced 10 billion standard cu m (bcm) of gas and around 1.9 million tonnes (15.1 million bbl) of condensate in total from Shah Deniz Alpha and Shah Deniz Bravo platforms.
Recovered gas is delivered to buyers via the South-Caucasus pipeline Baku-Tbilisi-Erzurum, while recovered liquid hydrocarbons are delivered via the Baku-Tbilisi-Ceyhan oil pipeline. Commissioning of the Trans-Adriatic Pipeline (TAP) gas pipeline at end 2020 allowed the start of commercial gas deliveries to Europe via the Southern Gas Corridor pipeline system (OGJ Online, Nov. 16, 2020).
During the first 6 months of the year, Shah Deniz field continued to provide deliveries of gas to markets in Azerbaijan (to SOCAR), Georgia (to GOGC and SOCAR), Turkey (to BOTAS), and to BTC Co. in multiple locations. Gas deliveries to buyers in Europe that started on Dec. 31, 2020, also continued during first-half 2021.
The existing Shah Deniz facilities’ production capacity is currently over 58 million st cu m/d of gas.
Completion of the deal is subject to conditions, including approval by SOCAR, the State Oil Co. of the Azerbaijan Republic.
Northern Oil and Gas adds Williston basin assets in Comstock deal
Northern Oil and Gas Inc. has agreed to acquire non-operated interests across the Bakken shale in the Williston formation from Comstock Resources for $154 million in cash.
The properties include over 400 producing wells (65.9 net) primarily in Williams, McKenzie, Mountrail, and Dunn Counties, ND.
October production on the assets is expected to be over 4,500 boe/d (2-stream, ~65% oil) and Northern expects average production of more than 4,100 boe/d in 2022 (2-stream, ~65% oil). Northern expects negligible capital expenditures on the assets.
The acquired assets include 65.9 net producing wells. The assets are operated by multiple operators in the Williston Basin, and Northern holds existing ownership positions in 84% of the wellbores acquired.
The deal is expected to close in this year’s fourth quarter.
Comstock expects to recognize a pre-tax loss of $130-140 million on the divestiture.
Comstock plans to re-invest the proceeds from the property sale into its Haynesville shale development program, including the acceleration of completing 13 (9.4 net) drilled and uncompleted wells which were originally budgeted to be completed in 2022. The company may also use a portion of the proceeds to acquire additional leasehold and to fund additional drilling activity in 2022.
Southwest Gas to acquire Questar Pipeline from Dominion
Southwest Gas Holdings Inc. has agreed to acquire Dominion Energy Questar Pipeline LLC, its subsidiaries, and certain associated affiliates, including Overthrust Pipeline, White River Hub, and Questar Field Services (Questar Pipelines) from Dominion Energy Inc.
Questar Pipelines is a Rocky Mountain energy hub with 2,160-miles of highly contracted, FERC-regulated interstate natural gas pipelines providing transportation and underground storage services in Utah, Wyoming, and Colorado.
Under the terms of the agreement, Southwest Gas will acquire 100% of Questar Pipelines for $1.545 billion in cash. Southwest Gas Holdings also will assume $430 million of Questar Pipelines’ debt.
The transaction is expected to close on or about Dec. 31, 2021. Following the close, Questar Pipelines will operate as a standalone subsidiary of Southwest Gas Holdings.
Callon agrees to Eagle Ford acreage sale
Callon Petroleum Co., Houston, entered into an agreement to sell non-core, South Texas Eagle Ford shale acreage to an undisclosed buyer for cash proceeds of about $100 million, subject to customary closing adjustments. The deal is expected to close in November.
The properties include about 22,000 net acres in northern LaSalle and Frio counties. Net daily production from the properties was about 1,900 boe/d (66% oil) on average in the third quarter through Aug. 31, the company said in a release Oct. 6.
The transaction increases total cash proceeds from the 2021 divestiture program to over $140 million to date, within the guidance of $125-225 million for the year.
In the release, Callon noted closing of its acquisition of leasehold interests and related oil, gas, and infrastructure assets of Primexx Energy Partners and its affiliates in the Delaware basin, increasing Callon’s Delaware basin position to over 110,000 net acres (OGJ Online, Aug. 4, 2021).
Production in the third quarter has been above previous expectations due to strong well performance in Delaware and Midland basins, the company said. Callon raised its production guidance to 98,500-99,500 boe/d (64% oil) from 95,500-97,500 boe/d (64% oil). Operational capital for the quarter is currently estimated at $120-125 million.
Exploration & Development Quick Takes
ExxonMobil makes discovery offshore Guyana, increases Stabroek resource estimate
ExxonMobil increased its estimate of the discovered recoverable resource for Stabroek block offshore Guyana to about 10 billion boe following a new discovery at Cataback that builds confidence in the greater Turbot area, the operator said in a release Oct. 7.
The updated resource estimate includes the Cataback-1 well discovery, which brings the total significant discoveries to more than 20 within the block.
Cataback-1 encountered 243 ft (74 m) of net pay in high quality hydrocarbon bearing sandstone reservoirs. It lies about 3.7 miles (6 km) east of Turbot-1 and was drilled in 5,928 ft (1,807 m) of water by the Noble Tom Madden.
The Stabroek block is 6.6 million acres (26,800 sq-km). ExxonMobil affiliate Esso Exploration and Production Guyana Ltd. is operator with 45% interest. Hess Guyana Exploration Ltd. holds 30% and CNOOC Petroleum Guyana Ltd. holds 25%.
Shell wins five blocks in Brazil’s 17th bid round
Shell Brasil Petroleo Ltda, a subsidiary of Royal Dutch Shell PLC, was awarded five exploration blocks in two sectors of the Santos basin off Brazil as part of the country’s 17th bid round conducted by the National Agency of Petroleum, Natural Gas, and Biofuels (ANP) Oct. 7.
ANP said investments of at least R$136 million will be generated in the first years of the contracts for the five blocks awarded.
Shell will serve as operator of blocks SM-1709, SM-1707, SM-1715, SM-1717, and SM-1719 and will pay R$35.1 million in signing bonuses. In block SM-1709, Shell will have a 70% stake, in partnership with Ecopetrol, with a 30% stake.
With the acquisition of the new blocks, Shell’s total presence in Brazil reaches 28 exploratory blocks, 1 field under development, and 14 fields in production.
The round offered 92 blocks in 11 high-potential sectors and new frontiers in four Brazilian maritime sedimentary basins: Campos, Pelotas, Potiguar, and Santos.
OKEA proposes to halt certain North Sea developments
OKEA ASA decided to propose to Vette license holders to not develop the North Sea discovery further.
The project, in PL 972, lacks financial robustness, the company said in an Oct. 12 release. OKEA took over operatorship of the project earlier this year and had been maturing the discovery towards a development decision (OGJ Online, Dec. 18, 2020).
Additionally, the company has worked to improve economics of the Greyling-Storskrymten discoveries over the last few years. Reductions in breakeven costs have been achieved, but it is deemed insufficient to warrant a stand-alone field development, OKEA said. Because the operator was targeting a joint serial development of the Vette discovery with the Greyling-Storskrymten discoveries, the decision to halt further development of Vette implies that the operator is likely to halt further development of Grevling-Storskrymten.
OKEA is operator at PL972 (40%) with partners ONE-Dyas Norge AS (30%) and M Vest Energy AS (30%). OKEA is operator of Grevling in PL038 D (35%) with partners Chrysaor Norge AS (35%) and Petoro AS (30%). OKEA also is operator of Storskrymten in PL974 (60%) with license partner Chrysaor Norge AS (40%).
Drilling & Production Quick Takes
Equinor granted extension for Sygna field
Equinor Energy AS has been given consent by the Petroleum Safety Authority Norway for extended operation of Sygna field to Aug. 10, 2026.
The field is in the Tampen area northeast of Statfjord Nord field in the Norwegian North Sea in 300 m of water. It has been developed with one subsea template with four well slots connected to the Statfjord C facility. Production started in 2000 (OGJ Online, Aug. 3, 2000).
Equinor is operator at Sygna (30.71%) with partners Petoro AS (30%), Vår Energi AS (20.99%), Spirit Energy Norway AS (12.72%), Idemitsu Petroleum Norge AS (4.32%), and Wintershall Dea Norge AS (1.26%).
Talos production operations returning to normal after Hurricane Ida
Talos Energy Inc. estimates third-quarter 2021 average daily production of 56,000-56,500 boe/d following operational disruptions caused by Hurricane Ida in August.
The estimate represents 10,000-11,000 boe/d of hurricane downtime compared to the company’s projections for the quarter pre-hurricane, the operator said in a release Oct. 12. Production for the quarter was about 69% oil and 77% liquids.
Production disruptions following Hurricane Ida were prolonged due to complications affecting third-party downstream service providers, the company said. Key refiners, crude oil terminals, and pipelines were not fully returned to operation for several weeks due to a mix of storm-related damage and lack of power. The company’s assets did not experience significant damage and the majority have been returned to normal operations, producing an average of 66,500 boe/d in the last week of September.
Some 4,000 boe/d of production remains offline across various assets, primarily due to repairs being made to pipelines and other downstream facilities. Talos expects the remaining impacted assets to return to production over the coming weeks and months as the third-party repairs are finalized.
Despite the disruptions, Talos continues to expect annual production near the lower end of the previously guided annual range, and expects production for fourth-quarter 2021 of 64,000-66,000 boe/d.
Lundin drills dry well west of Stavanger
Lundin Energy Norway AS drilled a dry hole in production license (PL) 981, about 1 km west of Solveig field in the North Sea and 190 km west of Stavanger in 100 m of water. Data acquisition has been carried out, and the well will be permanently plugged.
Well 16/4-12, the first in the license, was drilled by the Deepsea Stavanger drilling rig to a vertical depth of 2,141 m below sea level. It was terminated in the Zechstein Group from the Permian age.
The primary exploration target was to prove petroleum in sandstones in the Ty formation from the Palaeocene. The secondary exploration target was to prove petroleum in porous dolomite in the Zechstein Group.
The well encountered 58 m of sandstone in the Ty formation with good to very good reservoir quality. In the secondary exploration target, the well encountered 12 m of dolomitic rocks in the Zechstein Group with poor to moderate reservoir quality.
The well also encountered two intervals of sandstone from an undefined age between the Cretaceous and Triassic. The upper interval has a thickness of 16 m with moderate to good reservoir quality. The lower interval has a thickness of 15 m with good to very good reservoir quality.
Deepsea Stavanger will now drill wildcat well 17/8-1 in PL 976 in the North Sea, where Lundin Energy Norway AS is operator.
Lundin is operator at PL 981 (60%) with partner Aker BP ASA (40%).
PROCESSING Quick Takes
Rompetrol achieves partial restart of Petromidia refinery
Rompetrol Rafinare SA—jointly owned by Kazakhstan’s state-owned JSC NC KazMunayGas (KMG) subsidiary KMG International NV (54.63%) and Romania’s Ministry of Economy, Energy & Business Environment (44.69%)—has initiated the phased restart of operations at its 5-million tonne/year Petromidia refinery in Na˘vodari, Romania, on the Black Sea, following works to repair damages caused by an early July explosion and subsequent fire that led to the plant’s sitewide shutdown (OGJ Online, July 7, 2021).
After completing most of the repairs, turnaround works, and technical inspections required to safely restore partial operations by the end of September, Rompetrol Rafinare by Oct. 7 increased production capacity of unidentified plants within the refinery to a combined 12,700 tonnes/day, KMG said in a statement.
Alongside repairs and inspections, renovation works also included replacement of associated pipes; control, measuring, and automation equipment; and electrical cables. Additional measures ahead of restart included verifying all elements and equipment related to operational safety were in working order at each installation, as well as requiring retraining and recertification of all operating staff, according to KMG.
“The teams of specialists within [Rompetrol Rafinare], together with those from Rominserv and supported by companies with expertise, managed between July-September, to verify, repair, and test production assets, all [as part of the company’s objective to] constantly improve technical and operational safety performance [at the site],” said Felix Crudu Tesloveanu, Rompetrol Rafinare’s general manager.
While Rompetrol Rafinare said it will continue to restart various operating units within the refinery in stages to achieve optimal operating efficiencies by the end of October, the company confirmed the site’s diesel hydrotreating unit—its most damaged installation and source of the July 2 explosion—remains “technologically isolated” for completion of its reconstruction and subsequent restart in 2022.
Without offering further details, KMG separately stated repairs on the diesel hydrotreater are scheduled to occur in April 2022.
Rompetrol Rafinare previously said it expected to return the Petromidia refinery to normal operational capabilities during the fourth quarter (OGJ Online, Aug. 17, 2021).
SIBUR, KazMunayGas outline Atyrau integrated gas-to-chemicals project JV plans
PJSC Sibur Holding has signed additional agreements with Kazakhstan’s state-owned JSC NC KazMunayGas (KMG) and JSC National Welfare Fund Samruk-Kazyna to further explore joint ownership and development of grassroots petrochemical projects to be built as part of an integrated gas-to-chemicals complex (IGCC) at the National Industrial Petrochemical Technopark (NIPT) in Kazakhstan’s western Atyrau region.
Documents signed on Oct. 7 outline basic terms and conditions for creation of the IGCC’s two joint ventures that would cover future construction of a 1.25-million tonnes/year (tpy) polyethylene plant as well as Kazakhstan Petrochemical Industries Inc. (KPI) LLP’s 500,000-tpy polypropylene plant currently nearing completion, SIBUR and KazMunayGas said in releases.
While SIBUR’s participation remains contingent on receipt of all necessary regulatory approvals for the projects as well as commissioning of KPI’s Atrayu IGCC polypropylene plant, the operator said, if realized, it plans to take a 40% ownership interest in both JVs.
The October agreements follow the parties’ initial trilateral agreement under which SIBUR announced its initial consideration of joining as an Atyrau IGCC partner.
While Atyrau IGCC’s second-phase polyethylene development program continues to await results of SIBUR’s study on its economic efficiency due by yearend, Alik Aidarbayev, chairman of KMG’s board, said construction of KPI’s polypropylene plant is progressing as planned, with startup still on schedule for early 2022.
TRANSPORTATION Quick Takes
EPIC completes Gulf Coast NGL pipeline
EPIC Y-Grade LP has completed a 165-mile pipeline from its Robstown, Tex., fractionator to the Sweeny fractionation and storage complex, which also includes Phillips 66 Co. and Chevron Phillips Chemical Co. LLC. Sweeny has storage for both Y-Grade and purity products and EPIC also placed into service a 175-mile propane pipeline delivering to the complex.
The company also has connectivity to the Corpus Christi, Tex., export market via its fractionation complex there. It recently completed an ethane pipeline delivering to Gulf Coast Growth Ventures (GCGV) LLC’s complex in neighboring Portland, Tex. The plant, which just reached mechanical completion, will include a 1.8-million tonne/year ethane steam cracker. GCGV is an ExxonMobil Corp. and Saudi Basic Industries Corp. (SABIC) joint venture.
EPIC also said it has begun shipping NGLs under transportation agreements reached following cancellation in 2020 of the Belveiu Alternative NGL pipeline (BANGL). BANGL was a joint venture of WhiteWater Midstream LLC and MPLX LP designed to ship NGL from Delaware and Midland basins to Sweeny for fractionation.
EPIC Y-Grade LP operates a 700-mile, 24-in. OD NGL pipeline delivering Permian and Eagle Ford NGL production to the Gulf Coast. The company’s combined Robstown and Sweeny fractionation capacity is 240,000 b/d.
Wintershall to study repurposing North Sea pipelines for CO2
Wintershall Dea is working with the OTH Regensburg University of Applied Sciences on how existing natural gas pipelines in the southern North Sea can be used for future CO2 transport. Results obtained so far suggest that the offshore pipelines could be safely and efficiently repurposed for transport of liquid CO2. As the study progresses, technical feasibility will be tested, and certification will take place.
There are more than 4,800 km of pipelines in the southern North Sea, of which 1,200 km are operated by Wintershall Noordzee, a 50-50 joint venture between Wintershall Dea AG and Gazprom EP International BV. Parts of this network could be used for CO2 transport.
Wintershall Noordzee also operates numerous depleted reservoirs, potentially suitable for storing CO2. Experts estimate that around 800 million tons of CO2 could be stored in the Dutch Continental Shelf. That’s enough to store the entire annual emissions of all Dutch industry thirty times over, or by comparison, 8 years of German industrial emissions, based on 2018 International Energy Agency data.
“Wintershall Dea is investing in CCS because we are convinced that it is a safe and affordable technology for decarbonization. We have the technological know-how and the depleted offshore reservoirs required for CCS, as well as access to the pipeline network for transport,” said Klaus Langemann, senior vice-president of carbon management and hydrogen at Wintershall.
ExxonMobil, Sentinel form Houston crude pipeline joint venture
ExxonMobil Pipeline Co. and Sentinel Midstream Texas LLC have formed a joint venture, Enercoast Midstream LLC, to provide last-mile delivery of Permian, Gulf of Mexico, and other crude oil into the Houston market.
For the joint venture, ExxonMobil will contribute two existing crude oil pipelines: a 16-in. OD pipeline originating at its Webster Terminal with delivery points at ExxonMobil’s 584,000-b/d Baytown refinery and Magellan Midstream Partners’ Seabrook export terminal and a 20-in. OD pipeline between Moore Road station and the Baytown plant.
Sentinel contributed cash for a majority equity position and will operate the joint venture. Sentinel intends to further expand its operating footprint by building or acquiring new pipelines.
Enercoast began serving shippers as a common-carrier pipeline Oct. 1, 2021.
