OGJ Newsletter

Aug. 16, 2021


ESAI: NGLs’ era of peak demand growth nears end

NGLs’ era of “peak demand growth” will come to an end by 2025, according to ESAI Energy. Between 2021 and 2025, Asia’s LPG import requirement will grow less than 100,000 b/d annually and the global market will flip back to surplus, according to ESAI Energy’s newly published Global

NGL 5-Year Outlook. Developments in both China and India will slow the growth of imports to Asia’s two biggest LPG markets.

In the LPG market, fast expansion of the natural gas network in China will roll back household LPG use in that country, according to ESAI Energy. Meanwhile, higher prices and reduced subsidies have slowed growth in India. If in the period leading up to 2020 Asian demand grew by more than 100,000 b/d annually, going forward the growth rate will be half that amount.

Separately, ESAI Energy submits that demand for US ethane will decelerate after 2023 due to a relative lack of investment in new ethane crackers in the US. While 2021 is seeing a record increase in deliveries to overseas crackers, export growth will moderate. Consequently, global demand for US ethane will grow at a slowing pace.

“Demand growth for both LPG and ethane will slow,” explains ESAI Energy Principal Andrew Reed. “Given that the NGL fundamentals are usually shaped by supply, it is striking that we do not foresee a supply crunch that would price ethane or LPG out of the petrochemical feed slate. To the contrary, in a year or so we anticipate the LPG market flipping back to surplus. China is a microcosm of Asian demand growth. We think about China in bullish terms due to its climbing petrochemical demand. Due to other bearish factors, however, China may disappoint exporters.”

Callon to acquire Primexx to build Delaware basin position

Callon Petroleum Co., Houston, has agreed to acquire the leasehold interests and related oil, gas, and infrastructure assets of Primexx Energy Partners and its affiliates.

Primexx is a private Delaware basin operator with 35,000 net contiguous acres in Reeves County and second-quarter 2021 net production of 18,000 boe/d (61% oil). The acquisition consideration includes $440 million in cash and 9.19 million shares of Callon stock issued for a total deal value of $788 million.

The deal will increase Callon’s Delaware basin position to over 110,000 net acres. The company intends to add Primexx’s current two-rig program into its multi-year development plans. With some 300 identified core net locations, about two-thirds of which are 2-mile laterals, the acquired assets will support Callon’s continued shift to larger, more capital efficient development projects in the Delaware basin, the company said Aug. 4.

Primexx has invested in a gathering and water management infrastructure that includes 80,000 b/d of water recycling capacity and 60 miles of water transfer lines, more than doubling Callon’s current water recycling capacity.

Callon expects to finance the cash portion of the purchase with available capacity under the current credit facility with near-term repayment coming from forecasted free cash flow and proceeds from in-process divestiture initiatives. The company also will look to the debt capital markets to term out all or a portion of the cash payment in lieu of credit facility borrowings, it said.

Kimmeridge Energy has agreed to convert its remaining portion of the Callon second lien senior notes that were issued in 2020 into common shares after the close of the Primexx transaction, expected in this year’s fourth quarter subject to conditions and approvals.

Callon entered into an agreement with Chambers Investments LLC, a private investment vehicle managed by Kimmeridge, to exchange $197 million of its outstanding second lien notes for $223.1 million of company common stock. The exchange is contingent upon closing of the Primexx acquisition as well as a shareholder vote.

APA Q2 production benefits from Permian DUC program

APA Corp. had net income attributable to common stock of $316 million for second-quarter 2021, compared to $388 million in first-quarter 2021. When adjusted for items that impact comparability, APA’s second-quarter earnings were $266 million, compared to first-quarter 2021 earnings of $346 million. Net cash provided by operating activities was $969 million.

“A combination of strong well performance in the US, continued capital and cost discipline, and a favorable price environment enabled free cash flow generation of nearly $400 million during the quarter,” said John J. Christmann IV, APA’s chief executive officer and president.

Second-quarter reported production was 395,000 boe/d, and adjusted production, which excludes Egypt noncontrolling interest and tax barrels, was 342,000 boe/d.

US production of 242,000 boe/d benefitted from well performance throughout the company’s Permian basin drilled but uncompleted (DUC) completion program. This more than offset slightly lower international adjusted volumes of 100,000 boe/d, which were impacted by lower cost recovery barrels in Egypt due to higher oil prices and extended operational downtime in the North Sea, the company said.

The company exceeded its US oil production guidance provided in May by 6% with better-than-expected performance from the DUC completion program. The company brought online 27 wells in the Permian basin, 5 of which were at Alpine High. The company drilled three Austin Chalk wells in Brazos and Washington counties and added a second rig in the Permian basin in late June as planned.

APA’s second-quarter upstream capital investment was $257 million, which was below guidance primarily due to timing.

APA, excluding Altus Midstream, had total debt of $8.0 billion, cash and cash equivalents of $1.2 billion, and $3.2 billion available capacity under its undrawn revolving credit facility at the end of the quarter.

For third-quarter 2021, the company expects upstream capital investment of $280 million and US production of 233,000 boe/d and international production of 102,000 boe/d.

 Exploration & Development Quick Takes

Woodside revises Scarborough project cost estimate

Woodside Petroleum has increased its cost estimate for the proposed Scarborough gas development offshore Western Australia by 5%.

The updated estimate is US$12 billion ($5.7 billion offshore and $6.3 billion onshore), and follows finalization of technical work carried out to support execution readiness in the lead-up to a final investment decision expected this year.

There is a 3% cost increase in the onshore component, including modifications to Pluto Train 1 on the Burrup Peninsula, while there is an 8% increase in the offshore estimate, including an increase in offshore production capacity from 6.5 million tonnes/year (tpy) to 8 million tpy of LNG plus an additional well.

“The cost up-date includes value accretive scope changes to deliver around 20% increase in offshore processing capacity and to modify Pluto Train 1 to enable increased Scarborough gas processing,” said Meg O’Neill, acting chief executive officer. “It also reflects the work undertaken with our contractors to optimize the execution schedule and manage costs in preparation for FID.”

Woodside has also begun the formal process of selling down its interest in Pluto Train 2 and Scarborough.

Libra Consortium commits to fourth FPSO in Santos basin

Petróleo Brasileiro SA (Petrobras) and partners in Libra block have taken final investment decision for the fourth phase of the Mero project, 180 km offshore Rio de Janeiro, Brazil, in the presalt area of Santos basin.

SBM Offshore signed a letter of intent for a 22.5-year lease and operating contract for the Mero 4 FPSO Alexandre de Gusmão. It will produce 180,000 b/d and treat 12 million std cu m/d gas. The unit will have a water injection capacity of 250,000 b/d and a minimum storage capacity of 1.4 million bbl crude oil. The FPSO will be spread moored in about 1,900 m water depth.

Start-up is expected by 2025. It follows investment decisions for Mero 1 (start-up expected in 2022), Mero 2 (start-up expected in 2023) and Mero 3 (start-up expected in 2024) FPSOs (OGJ Online, Aug. 17, 2020). All have a liquid processing capacity of 180,000 b/d.

Mero field has been in pre-production since 2017 with the 50,000-b/d Pioneiro de Libra FPSO.

The Libra consortium is operated by Petrobras (40%) as part of an international partnership including TotalEnergies SE (20%), Shell Brasil (20%), CNOOC Ltd. (10%), and CNPC (10%). Pre-Sal Petróleo (PPSA) manages the Libra production sharing contract.

Tyra redevelopment advances

Redevelopment of the North Sea Tyra redevelopment project advanced with sailaway of the three Tyra East wellhead and riser topsides, partner Norwegian Energy Co. ASA (Noreco) said late July.

The topsides were fabricated at Sembcorp Marine Ltd. in Singapore and will be transported directly to Tyra field by HTV (heavy transport vessel). The voyage is expected to take 1 month followed by an offshore installation in late August or early September.

The platforms will, in part, replace ageing equipment and sustain output of 60,000 boe/d at Tyra field for the next 25 years. It is expected that Tyra’s transformation will reduce CO2 emissions by 30% and flaring by 90%.

Following a COVID-19-related delay from 2022, first gas is expected in second-quarter 2023 (OGJ Online, Nov. 6, 2020).

Tyra is the largest gas condensate field in the Danish Sector of the North Sea. Its facilities process more than 90% of gas produced in Denmark, as well as the entire gas production of the Danish Underground Consortium (DUC) comprised of operator TotalEnergies 43.2%; Noreco 36.8%, and Nordsøfonden 20%.

 Drilling & Production Quick Takes

Lundin produces first oil from Rolvsnes field

Lundin Energy AB produced first oil from the extended well test (EWT) at Rolvsnes field in the North Sea, the first subsea tieback development for the Edvard Grieg platform.

Rolvsnes is in PL338C on the southern side of Edvard Grieg and is a weathered and fractured granite basement reservoir. Horizontal appraisal well 16/1-28, drilled and flow tested to 7,000 b/d in 2018, was converted to a development well and tied back 3 km to the Edvard Grieg platform.

The objective of the EWT is to gain a better understanding of the reservoir properties, reservoir connectivity, and long-term production performance of Rolvsnes. If successful, this test could lead to full field development, further extending the plateau production period for Edvard Grieg.

Once sufficient data and production experience has been gathered, a plan for development and operation (PDO) could be submitted by end 2022, benefitting from the temporary tax regime in Norway, the company said.

Gross resource estimate for Rolvsnes is 14-78 MMboe.

Lundin Energy is operator at 338C with 80% interest. OMV (Norge) AS holds the remaining 20%.

Equinor boosts Vigdis production with new subsea pumping station

Equinor Energy AS improved oil recovery by around 16 million bbl from existing wells in Vigdis oil field with a new subsea multiphase boosting station. The pump came on stream in May.

The field lies in the Tampen area in North Sea block 34/7 (PL 089) in 280 m of water. The boosting station is connected to the existing pipeline between Vigdis and Snorre A and helps bring the well stream from the subsea field up to the platform and reduces wellhead pressure.

The contract for supplying the boosting system, including the template and trawl protection, was awarded to OneSubsea, with engineering in Bergen and assembly at Horsøy near Bergen.

In addition to the subsea boosting station, smaller modifications have been made to Snorre A, which receives oil from Vigdis, and Snorre B, which supplies the new boosting station with power from a new umbilical supplied by Nexans. Wood has been the main supplier for the modifications and the marine operations have been carried out by Deep Ocean.

Subsea pumps are particularly important to deepwater fields with long distances between subsea facilities and platforms, Equinor said. Other examples of such projects are Tordis subsea separation and boosting, Gullfaks subsea compression, and Åsgard subsea compression.

When Vigdis field came on stream in 1997, recoverable resources were estimated at 200 million bbl. So far, the field has produced 413 million bbl and estimated recoverable resources have increased to 475 million bbl.

License partners invested around NOK 1.4 billion in the Vigdis boosting project.

Equinor is operator of PL089 (41.5%) with partners Petoro AS (30%), Vår Energi AS (16.1%), Idemitsu Petroleum Norge AS (9.6%), and Wintershall Dea Norge AS (2.8%).

Santos achieves record flow from new Van Gogh well

Santos Ltd., Adelaide, achieved a record oil flow rate from the first of three planned production wells at Van Gogh field in the Carnarvon basin offshore Western Australia.

Following completion and tie-in, the well produced at a peak rate of 23,200 b/d—the highest initial rate from an individual well in the field’s history.

The new wells are part of the field’s Phase 2 infill development program (OGJ Online, Mar. 26, 2021). First oil from the project has come 16 months after final investment decision.

Drilling of the second horizontal, dual-lateral well is now under way.

The program is being undertaken by the Valaris MS1 jack up drilling rig. The remaining two wells are expected to be completed during the next 2 months and brought on stream before yearend.

Van Gogh field, in production license WA-35-L, is one of three subsea developments which tie into the floating production, storage and offtake (FPSO) vessel Ningaloo Vision.

Production from Van Gogh began in 2010. Nearby Coniston and Novara fields were tied back to the FPSO in 2015 and 2016, respectively.

Santos is operator with 52.5% interest. Inpex Corp. holds the remaining interest.


Marathon completes startup of North Dakota renewable diesel refinery

Marathon Petroleum Corp. (MPC) has fully commissioned a grassroots renewable diesel production unit built as part of the operator’s conversion of its former conventional crude oil refinery in Dickinson, ND, into a renewables manufacturing site.

Following operational startup in late-2020 and based on Haldor Topsoe AS’s proprietary HydroFlex technology, the new Dickinson unit is now producing 100% renewable diesel from soy and corn oil at its full design capacity of 12,000 b/d, MPC and Haldor Topsoe said in separate announcements on Aug. 4-5.

Commissioning of the Dickinson refinery’s HydroFlex unit follows MPC’s late-2019 decision to convert the refining site into a renewable diesel production plant as part of the operator’s plan to increase output of fuels that align with objectives of California’s Low Carbon Fuel Standard (LCFS) as well as MPC’s own greenhouse gas (GHG)-reduction targets.

MPC also has selected Haldor Topsoe’s HydroFlex technology to be implemented as part of the operator’s conversion of its now permanently idled 161,000-b/d refinery in Martinez, Calif., into a renewable fuels production site (OGJ Online, Oct. 5, 2020).

With final engineering on the project now under way, the reconfigured Martinez renewables refinery is scheduled to achieve first-phase production rates of 17,000 b/d of renewable diesel by second-half 2022 before ramping up to its full production capacity of 47,000 b/d by 2023, MPC said on June 8, 2021.

PKN ORLEN lets contract for proposed new plant at Plock refinery

Polski Koncern Naftowy SA (PKN ORLEN) has let multiple contracts to KBR Inc. to provide various process technologies for the operator’s proposed project to add an integrated solvent deasphalting (SDA) and residue fluid catalytic cracking (RFCC) plant at its 16.3-million tonnes/year dual refining and petrochemical manufacturing site in Plock, Poland.

As part of the contracts, KBR will deliver basic engineering design and technology licensing for the SDA and RFCC units, the service provider said on July 27.

The SDA unit will be outfitted with KBR’s supercritical solvent recovery ROSE technology to help PKN ORLEN produce cleaner, upgraded bottom-of-the-barrel (BOTB) feedstock for the new RFCC unit, which in turn will use KBR’s dual-riser MAXOFIN technology that—using a combination of conventional FCC operating conditions as well as KBR’s proprietary catalyst additives and equipment—will allow the operator to maximize propylene production from traditional FCC feedstocks and naphtha streams.

Still in its planning phase, the proposed BOTB processing project at Plock is an initiative to advance a pillar under PKN Orlen’s ORLEN2030 strategy specifically involving maximizing profitability of its existing operations to increase overall competitiveness, according to Daniel Obajtek, PKN ORLEN’s president.

The SDA-RFCC plant would enhance flexibility of the Plock refinery to enable the possibility of adapting production between fuel and petrochemical products to meet existing customer needs based on current demand, PKN Orlen said in a separate July 27 release.

During the coming months, PKN ORLEN said it plans to undertake basic design of the integrated SDA-RFCC project and, if approved, begin the process of selecting a general contractor for construction of the plant.


Wintershall commissions Emlichheim crude export line

Wintershall DEA Deutschland has commissioned a new crude oil export pipeline between Emlichheim and Osterwald, Lower Saxony, Germany. The 14.4-km oil pipeline connects Wintershall’s processing site in Emlichheim oil field with its Osterwald operations, replacing rail shipment. With immediate effect, treated oil will be transported from Emlichheim via Osterwald to BP Europa’s 97,000-b/d Lingen refinery.

The pipeline, made of fiberglass-reinforced resin, is designed to carry as much as 600 tonnes/day (4,200 b/d). The 6,500-cu m rail loading tank at Emlichheim will be taken out of service.

Wintershall has been extracting crude oil in Emlichheim for more than 75 years. The company drilled four new wells in 2019—two production and two steam injection—to keep production stable at roughly 2,500 b/d.

Williams to provide services for Whale development

Williams, Tulsa, Okla., reached an agreement with Shell Offshore Inc. and Chevron USA Inc. to provide offshore natural gas gathering and crude oil transportation services as well as onshore natural gas processing services for the US Gulf of Mexico Whale development.

Whale, which lies 10 miles from the Shell-operated Perdido host platform, is expected to reach peak production of 100,000 boe/d and currently has an estimated recoverable resource volume of 490 MMboe. Shell made final investment decision (FID) for the deepwater development in July (OGJ Online, July 26, 2021).

Williams plans to expand its existing Gulf of Mexico offshore infrastructure via a 25-mile gas lateral pipeline build from the Whale platform to the existing Perdido gas pipeline and a new 125-mile oil pipeline to the existing Williams-owned GA-A244 junction platform. Natural gas will be transported to Williams’ Markham gas processing plant in Matagorda, Tex. First production is expected in 2024.

Williams owns and operates 3,500 miles of natural gas and oil gathering and transmission pipeline, along with 1.8 bcfd of cryogenic processing capacity and 60,000 b/d of fractionation capacity that span the Gulf of Mexico. The company has ownership in two floating production platforms, multiple fixed leg utility platforms, and other related infrastructure.

Nigeria LNG Train 7 to use Air Products liquefaction

Nigeria LNG (NLNG) LLC engineering, procurement, and construction contractor SCD JV Scarl—a joint venture of Saipem SPA, Chiyoda Corp., and Daewoo Engineering & Construction Co.—signed Air Products Inc. to provide liquefaction technology for the NLNG Train 7 expansion. Train 7 will add 8 million tonnes/year (tpy) to the Bonny Island plant’s 22-million tpy capacity, with Air Products targeting 2023 delivery.

The project includes one complete LNG train and one combined liquefaction unit. Air Products will provide the main cryogenic heat exchangers (MCHEs) and process technology for both. Air Products will build the LNG heat exchangers at its Port Manatee, Fla., manufacturing plant.

The company provided the MCHEs and process technology for the first six NLNG trains with production beginning in 1999 for the first and 2007 for the sixth. All six LNG trains continue production.

The NLNG joint venture includes NNPC (49%), Shell Gas BV (25.6%), Total Gaz Electricite Holdings France (15%), and Eni International NA NV Sarl (10.4%)