OGJ Newsletter

March 1, 2021


US annual LNG exports to exceed pipeline exports by 2022

US LNG exports will exceed natural gas exports by pipeline in the first and fourth quarters of 2021 and on an annual basis in 2022, according to the US Energy Information Administration’s (EIA) February 2021 Short-Term Energy Outlook (STEO). EIA forecasts that monthly US LNG exports exceeded natural gas exports by pipeline by nearly 1.2 bcfd in November 2020. LNG exports have only exceeded natural gas exports by pipeline once since 1998—in April 2020—by 0.01 bcfd.

US LNG exports set consecutive monthly records of 9.4 bcfd in November and of 9.8 bcfd in both December 2020 and January 2021, according to EIA’s estimates based on the shipping data provided by Bloomberg Finance LP. EIA forecasts that US LNG gross exports will average 9.7 bcfd in February 2021 before declining to seasonal lows in the shoulder months of the spring and fall seasons. EIA forecasts LNG exports to average 8.5 bcfd in 2021 and 9.2 bcfd in 2022, compared with average gross pipeline exports of 8.8 bcfd in 2021 and 8.9 bcfd in 2022.

Since November 2020, all six US LNG export facilities have been operating near full design capacity. In December, Cheniere Energy’s Corpus Christi LNG plant in Texas commissioned its 5-million tonne/year third and final liquefaction train 6 months ahead of schedule, bringing total US liquefaction capacity to 9.5 bcfd baseload (10.8 bcfd peak) across six plants.

The November–January increase in US LNG exports has been driven by rising international natural gas and LNG prices, particularly in Asia, and lower global LNG supply because of unplanned outages at several LNG export sites worldwide.

US pipeline exports to Mexico increased by 6.4% in the first 11 months of 2020 compared with the same period in 2019 as a result of the completion of a new segment of the Wahalajara pipeline system and Centro de Control del Gas Natural’s (Cenagas) Cempoala compressor station. The completion of Grupo Carso’s Samalayuca-Sásabe pipeline (470 MMcfd) in January 2021 and the expected completion of TC Energy’s Tula-Villa de Reyes pipeline (886 MMcfd) later in 2021 are expected to further increase US pipeline exports to Mexico.

Energy Transfer to acquire Enable Midstream

Energy Transfer LP has agreed to acquire Enable Midstream Partners LP in an all-equity transaction valued at $7.2 billion.

The deal strengthens Energy Transfer’s NGL infrastructure by adding natural gas gathering and processing assets in the Anadarko Basin in Oklahoma and integrates assets with Energy Transfer’s existing NGL transportation and fractionation assets on the US Gulf Coast, the company said. The acquisition also provides gas gathering and processing assets in the Arkoma basin across Oklahoma and Arkansas, as well as the Haynesville Shale in East Texas and North Louisiana.

Energy Transfer expects the combined company to generate more than $100 million of annual run-rate cost and efficiency synergies, excluding potential financial and commercial synergies.

Enable’s assets include 14,000 miles of natural gas, crude oil, condensate and produced water gathering pipelines, 2.6 bcfd of natural gas processing capacity, 7,800 miles of interstate pipelines (including Southeast Supply Header LLC of which Enable owns 50%), 2,200 miles of intrastate pipelines, and seven natural gas storage facilities comprising 84.5 bcf of storage capacity.

Under the terms of the agreement, Enable common unitholders will receive 0.8595 ET common units for each Enable common unit. In addition, each outstanding Enable Series A preferred unit will be exchanged for 0.0265 Series G preferred units of Energy Transfer. The transaction will include a $10 million cash payment for Enable’s general partner.

Santos targets September FID for Moomba CCS project

Santos Ltd., Adelaide, is expecting a final investment decision (FID) for its proposed carbon capture and storage (CCS) project at Moomba in South Australia by September (OGJ Online, Mar. 4, 2020).

The company’s chief executive officer, Kevin Gallagher, offered the target date as part of a yearend results presentation and said that Santos is waiting for the South Australian government and the Clean Energy Regulator to establish an appropriate carbon trading scheme.

FID on the Moomba project is awaiting the methodology statement that will support accreditation of CCS projects, he said. An FID before then would eliminate the possibility of the project being eligible for carbon credit.

The project aims to capture 1.7 million tonnes of CO2 that is currently separated from the natural gas stream at the Moomba gas plant each year. The CO2 will be reinjected into the same geological formations in the Cooper basin that reservoir the oil and gas resources in the region.

A final reinjection trial of 100 tonnes of CO2 into depleted Cooper basin reservoirs was successfully completed in October 2020.

Gallagher said the Cooper basin can take up to 20 million tonnes/year of CO2 for the next 50 years.

Exploration & Development Quick Takes

ConocoPhillips unit awarded block offshore Malaysia

ConocoPhillips East Malaysia Ltd. (COPEM), a subsidiary of ConocoPhillips and Petronas Carigali Sdn. Bhd. (PCSB), has been awarded Block SB405 by Petronas in North East Sabah basin, off the coast of Sandakan, Sabah, Malaysia.

The block covers 5,857 sq km in 100 m of water. Its award is expected to bolster exploration off the coast of Sabah which has proven working petroleum systems such as Kuda Terbang and Nymphe fields, the company said.

SB405 is a new addition to COPEM’s existing interests in five production sharing contracts in Malaysia: Block J, G, and Kebabangan off the coast of Sabah, and SK304 and WL4-00 off the coast of Sarawak.

COPEM is operator of Block SB405 PSC with 85% interest. PCSB holds the remaining 15%.

CNOOC makes Bohai Bay discovery

CNOOC Ltd. discovered oil and gas in the southwestern Ring of Bozhong Sag in Bohai Bay.

Bozhong 13-2 lies in 23.2 m water depth and was drilled and completed at a depth of 5,223 m. The discovery encountered oil pay zones with a total thickness of 346 m. The well tested at an average 1,980 bbl crude oil and 5.25 million cu ft/d of natural gas.

Carnarvon Petroleum to redevelop Timor-Leste field

Carnarvon Petroleum Ltd. will drill Buffalo-10 in second-half 2021, targeting the crest of the proven Buffalo oil field, offshore Timor-Leste in Bonaparte basin.

The well is in production sharing contract (PSC) TL-SO-T 19-14 and is the first step to redevelop the field. Once drilled, the well will be suspended as a future production well.

The company awarded drilling management services to Petrofac which will include completion of detailed well design, procurement of long lead time items, and contracting the drilling rig and associated services.

Carnarvon is operator of the field with JV partner Advance Energy Partners. Carnarvon will have 50-75% interest in the project after the JV concludes joint financing.

Drilling & Production Quick Takes

Neptune Energy starts Gjøa P1

Neptune Energy and partners started production from the Gjøa P1 development in the Norwegian sector of the North Sea.

Gjøa P1 has been developed via a new subsea template and tied back to existing infrastructure on Gjøa field (OGJ Online, Dec. 20, 2020). It is a two-well development with one oil and one gas producer. The gas well came onstream on Feb. 22, and the oil well was expected to start-up the last week in February.

The semisubmersible Gjøa production unit is electrified with hydropower from shore and has one of the lowest CO2 footprints per produced boe on the Norwegian Shelf, the company said.

Startup of Gjøa P1 increases total remaining developed reserves at Gjøa by 30%. Gjøa is now set to produce over 100 MMboe more than was estimated when production began in 2010.

Neptune Energy is operator in Gjøa (30%) with partners Petoro AS (30%), Wintershall Dea Norge AS (28%), and OKEA (12%).

Ring to kick off production increase in March

Ring Energy Inc. expects four Permian basin Northwest Shelf (NWS) San Andres wells drilled in Yoakum County, Tex., in December and January—including three 1.5-mile horizontal wells and one 1.0-mile horizontal well—to be completed and on production by the first week of March 2021.

The wells are part of a plan to drill six to eight wells and complete eight to ten wells in 2021 and increase its 2021 production 3-8% above 2020 levels to a target average of 9,100-9,450 boe/d (85-87% oil) with a capital spending program of $44-48 million.

Work includes well reactivations, workovers, infrastructure upgrades, and continuing the conversions from electrical submersible pumps to rod pumps program in the NWS and the Central Basin Platform areas. Anticipated leasing, contractual drilling obligations and non-operated drilling, completion, and capital workover projects are also included.

Average production in 2020 was 8,790 boe/d. For fourth-quarter 2020, Ring produced 9,307 boe/d, exceeding its previous guidance of 8,900-9,000 boe/d.

The company also plans to begin a process to sell its Delaware basin assets in this year’s second quarter, subject to market conditions.

Cimarex expects 5-7% production volume hit from Winter Storm Uri

Cimarex Energy Co., Denver, expects a 5-7% reduction in production volumes for this year’s first quarter due to downtime associated with Winter Storm Uri in the Permian and Mid-Continent regions.

Oil production in first-quarter 2021 is expected to average 65,000-69,000 b/d. First quarter total production is expected to average 205,000-225,000 boe/d. 

Of the $500-600 million drilling and completion budget for 2021, over 90% will be invested in the Permian region with the remainder in the Mid-Continent. Permian activities will continue to focus on long lateral Wolfcamp and Bone Spring wells in Culberson and Reeves counties in Texas, and in Lea and Eddy counties in New Mexico. In the region, 67 net wells are expected to begin producing by yearend. Six are expected by yearend in the Mid-Continent for a total 73 net wells expected to begin producing during the period. 

Total capital investment in 2021 (including midstream capital) is projected at $650-750 million. 

For the year, oil production is projected to average 75,000-81,000 b/d, up 2% at the midpoint from 2020 levels. Total equivalent production is expected to average 235,000-255,000 boe/d.


Kazakhstan lets JGC gas separation plant FEED contract

KazMunayGas (KMG) awarded JGC Holdings Corp. the front-end engineering and design contract for a 957-MMscfd gas separation plant, to be built by KMG subsidiary KLPE. Separated ethane will be supplied to the planned 1.25-million tonne/year (tpy) Atyrau polyethylene plant.

Kazakhstan Petrochemical Industries Inc. (KPII) is building an integrated gas chemical complex for completion by end-2021. The complex will produce 500,000 tpy of polypropylene products including films and sheets, raffia sheets, fibers, fiberboard, and cast film.

KPII described construction as 77% complete as of October 2020, with design complete, equipment manufacture and delivery 70% complete, and construction and installation 46% complete.

The new KLPE gas separation plant will be adjacent to one operated by Tengizchevroil as part of its development of Tengiz oil field.         

CPCL commissions new unit at Manali refinery

Indian Oil Corp. Ltd. subsidiary Chennai Petroleum Corp. Ltd. (CPCL) has started up a new unit as part of the second phase of the previously announced Bharat Stage VI (BS VI, equivalent to Euro 6-quality standards) fuels project at its 10.5-million tonnes/year Manali refinery in Tamil Nadu, India (OGJ Online, Feb. 28, 2018).

CPCL commissioned the grassroots 600,000-tpy FCC gasoline desulfurization unit at Manali in late-January 2020, Engineers India Ltd.—which delivered engineering, procurement, and commissioning services on the project—said in a series of posts to its official social media accounts.

Consisting of sections for selective hydrogenation, splitting, two-stage hydrodesulfurization, and stabilizing, the new FCC gasoline desulfurization unit is designed to produce gasoline with less than 10 ppm sulfur in compliance with the Ministry of Petroleum & Natural Gas (MOPNG) of India’s directive of 100% production of BS VI-quality fuels for the country that took effect Apr. 1, 2020, CPCL said in a series of official project documents filed with Indian regulators.

The FCC gasoline desulfurization unit—which was in the precommissioning stage as of August 2020—was scheduled for mechanical completion by second-quarter 2020-21 (July-September), with startup to follow during third-quarter 2020-21 (October-December), CPCL said in its 2019-20 annual report to investors issued on Aug. 17, 2020.

Alongside the newly commissioned FCC gasoline desulfurization unit, Phase 2 of CPCL’s Manali BS VI fuels project also includes ongoing construction of a grassroots sulfur recovery block that—scheduled for mechanical completion by fourth-quarter 2020-21 (January-March)—will house: a 200-tonnes/day sulfur recovery unit (two trains, each with a 100-tonne/day capacity)); an amine treating unit; and a sour-water stripping unit.

Once in operation, the new sulfur recovery block will treat acid gas generated from the FCC gasoline desulfurization unit as well as the refinery’s recently revamped and expanded diesel hydrotreating unit included in Phase 1 of Manali’s BS VI fuels project.

Completed in November 2019, the Phase 1 upgrading project involved increasing capacity of the refinery’s existing diesel hydrotreating unit to 2.4 million tpy from 1.80 million tpy, as well as works to ensure 100% production of BS VI-compliant diesel containing less than 10 ppm sulfur, according to official project documents and CPCL’s latest annual report.

In August 2020, CPCL estimated overall project cost of the Manali refinery’s BS VI fuels project at 18.58 billion rupees.

Ecopetrol plans major upgrades at Barrancabermeja refinery

State-owned Ecopetrol SA is investing nearly $780 million during the next 2 years on a series of projects aimed at ensuring operational and environmental sustainability of its 250,000-b/d Barrancabermeja refinery in Santander, Colombia.

The proposed $777-million investment will cover works focused on conserving water, reducing emissions, and improving quality of fuel production at the site as part of Ecopetrol’s broader strategy to reduce the refinery’s impacts to air, water, and soil, as well as to guarantee its legal compliance with environmental regulations, the operator said on Feb. 18.

Initiatives already under way as part of the 2021-23 investment program include a technology upgrade of the refinery’s wastewater treatment plant—now 74% completed—as well as an upgrade and expansion of the complex’s mild hydrocracking unit that will enable the refinery to reduce sulfur content of its gasoline production to 30 ppm by 2025 and 10 ppm by 2030.

Alongside a modernization project to improve reliability of the refinery’s water segregation system, the investment program also will include a project at the complex’s sulfur plants to control emissions of sulfur oxides (SOx). Development of basic engineering on the SOx-emissions control project is currently under way, according to the operator.

As a result of rigorous biosafety protocols implemented at Barrancabermeja to maintain continuity of operations amid the COVID-19 pandemic, Ecopetrol confirmed the refinery will continue to execute planned shutdowns in 2021 to carry out works designed to improve reliability and integrity of units, tanks, and boilers.

Ecopetrol said the new investment plan at Barrancabermeja follows the company’s previous $721-million capital expenditures at the site during the last 6 years to ensure the refinery—Colombia’s largest—remains technologically up to date.

In 2020, Ecopetrol invested a total of $181 million at Barrancabermeja on projects to improve reliability ($100 million), environmental legal compliance ($58 million), quality of fuel production ($12 million), and health, safety and environment (HSE, $11 million) at the site, according to the operator’s website.

Currently processing about 225,000-b/d of crude oil, the Barrancabermeja refinery houses 54 processing units, more than 315 storage tanks, and 32 industrial services.


Qatargas awards Saipem North Field EPCI contract

Qatargas has awarded Saipem SPA an engineering, procurement, construction, and installation (EPCI) contract for development of the North Field production sustainability offshore project, northeast of Qatar, increasing LNG production capacity to 110 million tonnes/year (tpy) from 77 million tpy. Work includes platforms, supporting and connecting structures, subsea cables, and anticorrosion internally clad pipelines as well as decommissioning of an existing pipeline and modifications to other offshore infrastructure.

Saipem’s DE HE S-lay, heavy lift, dynamically positioned construction, and anchor vessel will execute pipelay and lifting operations in water depths of about 65 m, with first gas anticipated in 2023.

The company is already executing the WHP12N jacket project, awarded in July 2020, as part of the North Field production sustainability project. This jacket is designed for 12 well slots and to support a topsides. Work began in October 2020.

Saipem also received a letter of intent from Qatargas to develop the project’s offshore export pipelines and related onshore works, with award pending definition of contractual details and Qatargas’s final approval.

The EPCI contract is worth about $1.7 billion.

Sempra plans 20-bcf Louisiana gas storage

LA Storage LLC, a division of Sempra LNG, plans to build new 20-bcf natural gas salt dome storage and associated compression and pipeline in Cameron and Calcasieu Parishes, La. The Hackberry Storage Project will involve the conversion of three existing salt dome caverns to natural gas storage service and the development of one new salt dome cavern, as well as construction of 16 miles of 42-in. OD pipeline. LA Storage hopes to receive US Federal Energy Regulatory Commission (FERC) approval by 2022 to meet a targeted 2024 in-service date.

The three existing caverns will store 16.1 bcf of natural gas, 12.64 bcf of working gas, and 3.46 bcf of base gas. The new, proposed cavern will store 9.4 bcf of natural gas, 7.39 bcf of working gas, and 2.01 bcf of base gas. The total capacity of the four caverns will be 25.5 bcf, 20.03 bcf of working gas, and 5.47 bcf of base gas. The project will be designed to inject and withdraw natural gas into storage at a maximum rate of 1.5 bcfd.

LA Storage will also build the Pelican compressor station on site, using four 5,350-hp natural gas-driven reciprocating units. The compressors will be designed to compress natural gas at suction pressures of 650-1,440 psig and discharge natural gas at pressures of 1,000-2,300 psig.

The proposed Hackberry Pipeline consists of 11.1 miles of 42-in. OD line connecting the storage caverns to the planned interstate pipeline owned by LA Storage’s affiliate, Port Arthur Pipeline LLC (PAPL) by extending north to PAPL’s Louisiana Connector Pipeline approved by FERC for construction in Calcasieu Parish (OGJ Online, Apr. 18, 2019). The proposed CIP Lateral, a 4.9-mile, 42-in. pipeline, will extend from Hackberry Storage in Cameron Parish north to connect it with the existing 42-in. interstate pipeline owned by LA Storage’s affiliate, CIP, in Calcasieu Parish. The interconnection of the CIP Lateral to the CIP pipeline will be just south of the Gulf Intracoastal Waterway.

LA Storage is jointly owned by SEI Storage Corp. (75%), a wholly owned subsidiary of Sempra Energy International, and ProLiance Transportation and Storage-Liberty LLC (25%).

Fluxys takes FID on Zeebruge LNG expansion

Fluxys LNG has taken final investment decision on an additional 6 million tonnes/year (tpy) of regasification at its 11.2-million tpy Zeebrugge LNG terminal in West Flanders, Belgium, having fully subscribed a binding open season for the capacity.

Phase 1 of the expansion (4.7 million tpy) will enter service in early 2024, with the balance following 2 years later.

The open-season counterparties were not disclosed, but Qatar Petroleum holds 100% of current capacity through as long as 2044.