GENERAL INTEREST Quick Takes
Government to buy more oil for petroleum reserve
The US Department of Energy is preparing to purchase crude oil for the Strategic Petroleum Reserve (SPR), which has room for an additional 77 million bbl.
“The department is confident that the purchase of oil could begin in as soon as two weeks,” an Energy Department official said March 16. “However, it will take several months to fill the SPR to its maximum capacity.”
The department will purchase “crude oil owned and produced in the United States,” department spokeswoman Shaylyn Hynes said in a statement released late Mar. 13.
First word of the decision came from President Trump speaking to White House reporters Mar 13. Energy Secretary Dan Brouillette then directed Steven Winberg, assistant secretary for fossil energy, to immediately initiate an expedited process for the oil purchases.
A solicitation for the purchase of oil will be issued as soon as possible, Hynes said.
The SPR currently is authorized to store about 713 MMbbl of oil. The stored oil includes both sweet and sour grades, kept in four sets of salt caverns on the Gulf Coast, two of the sets in Texas, and two in Louisiana.
The decision to buy oil for the SPR came as prices for West Texas Intermediate lingered at levels low enough to spur severe reductions in spending and staffing by many US oil companies and service companies, with economic implications for communities in oil-producing areas.
The price of West Texas Intermediate oil, as measured by New York Mercantile Exchange futures, continued to drop Mar. 16 despite the SPR oil purchase plan.
EOG cuts capex 31%, predicts flat full-year production
EOG Resources Inc. cut its exploration and development expenditures for 2020 by 31% to $4.3-4.7 billion including facilities and gathering, processing, and other expenditures, and excluding acquisitions and non‐cash exchanges. The company expects net cash from operating activities to fund both capital expenditures and dividend payments assuming mid-$30/bbl oil prices for the remainder of 2020.
The revised capital plan supports full-year 2020 crude oil production of 446,000-466,000 b/d, roughly flat compared with full-year 2019 levels. Given current oil and natural prices, EOG will reduce activity across its operating areas, focusing on drilling in Delaware basin and Eagle Ford shale.
The company’s total crude oil volumes in fourth-quarter 2019 were 468,900 b/d, above the midpoint of its target range and an 8% increase compared with the same period in 2018.
EOG expected to complete 800 net wells in 2020 compared with 750 net wells in 2019, according to its 2019 earnings report, with activity focused in Delaware basin, Eagle Ford, and Rocky Mountain areas and a 2020 exploration and development budget of $6.3-6.7 billion. The original capital program supported growth in crude oil production of 10-14% in 2020 (OGJ Online, Mar. 2, 2020).
Hess cuts budget by 27%, reduces Bakken drilling
Hess Corp. revised its 2020 capital and exploratory budget to $2.2 billion, an $800-million reduction from the previous budget (OGJ Online, Jan. 28, 2020). Reductions will come primarily from shifting to a one-rig program from a six in the Bakken shale, a move it expects to have completed by end-May 2020. Most discretionary exploration and offshore drilling activities, excluding its work in Guyana, will also be deferred.
The company now forecasts net production for 2020 to average 325,000-330,000 boe/d, excluding Libya, versus previous guidance of 330,000-335,000 boe/d. Hess’s Bakken net production is forecast to average 175,000 boe/d in 2020, versus previous guidance of 180,000 boe/d.
Hess also entered into a $1-billion, 3-year term loan agreement with JPMorgan Chase Bank NA. The company entered 2020 with more than $1.5 billion in cash and cash equivalents on its balance sheet and has a $3.5 billion undrawn revolving credit facility and no material debt maturities until 2027.
FERC general counsel Danly confirmed as commissioner
The Senate confirmed James Danly to be a member of the Federal Energy Regulatory Commission (FERC) by a vote of 52-40 on Mar. 12.
Danly’s regulatory philosophy is not something he has elaborated upon publicly.
He will be the third Republican on the commission, but Republican Commissioner Bernard McNamee has said he will leave when his term ends June 30. After that, the commission will consist of Republican Chairman Neil Chatterjee, Danly, and Democrat Richard Glick, unless McNamee chooses to stay longer while a replacement is sought. Danly’s term will expire on June 30, 2023.
On Capitol Hill, Democrats have said a Republican nominee should have been paired with a Democratic nominee, but Danly ended up being moved forward alone.
Among Democratic senators, Joe Manchin (D-W.Va.), Doug Jones (D-Ala.), and Kyrsten Sinema (D-Ariz.) voted along with Republicans to confirm Danly. Four Republicans and four Democrats did not vote.
Danly, FERC’s general counsel, is a former attorney in the energy regulation and litigation group at law firm Skadden, Arps, Slate, Meagher and Flom LLP.
Exploration & Development Quick Takes
Total makes Central North Sea gas, condensate discovery
Total SA and its partners have made a new natural gas and condensates discovery with the Isabella 30/12d-11 well on license P1820 in the Central North Sea offshore UK, about 40 km south of Elgin-Franklin field and 170 km east of Aberdeen. The well was drilled in water depth of about 80 m and encountered 64-m net pay of lean gas and condensate and high-quality light oil in Upper Jurassic and Triassic sandstone reservoirs.
Analysis of data and results are ongoing to assess discovered resources and determine the appraisal program required to confirm commerciality. Total described initial results as encouraging.
Total (30%) operates the P1820 license alongside Neptune Energy (50%), Ithaca Energy (10%), and the wholly owned subsidiary of Edison, Euroil Exploration (10%).
Maurel & Prom to continue Gabon exploration activities following Kari-1
Maurel & Prom, Paris, encountered oil shows with the Kama-1 exploration well on the Kari license in south Gabon. The mediocre quality of the reservoirs did not justify a commercial test, the company said, but the drilling confirms the presence of an active petroleum system in the region and provided additional data which will be helpful for the continuation of exploration activities in the area, particularly in the definition of a second well.
The well encountered several oil shows between 1,865 and 2,701 m total depth in the Kissenda formation, the main drilling objective, and a sample of 35° API oil has been collected.
Maurel & Prom is 100% operator in the license.
NPD: Cost control, execution on NCS projects improved in 2007-2018
A majority of the 66 Norwegian continental shelf (NCS) projects in 2007-2018 reviewed by the Norwegian Petroleum Directorate (NPD) kept costs within the estimates given in their plans for development and operation (PDO).
“The big picture shows that the projects have progressed positively in terms of both cost control and planned execution,” says Niels Erik Hald, assistant director development and operations at the NPD, noting an emphasized importance of the companies pursuing detailed early-phase work.
The finding was part of a report on project execution presented by the NPD on Feb. 7, which compares costs, start-up time, and reserve developments with estimates made in the PDOs. Just over 80% of projects ended up with costs within or below the uncertainty range (+/- 20%) in the estimates.
Ninety percent of the subsea developments reviewed were completed in accordance with or below the PDO forecast, the report showed.
While a number of platform developments experienced cost overruns, the review reported that over 70% of the developments end up in line with estimated costs.
During the 2007-2018 timeframe, market developments since the oil price slump also contributed to improved project executions because the availability of resources and capacity at suppliers was better than in earlier years, the report said.
On average, the time to complete projects has taken 3.5 months longer than planned. The average delay is greater for platform developments than for those based on subsea installations.
Drilling & Production Quick Takes
Bahamas Petroleum gets environmental approval to drill inagural exploration well
Bahamas Petroleum Co. Plc has been granted environmental authorization (EA) by the government of the Bahamas to drill its inaugural exploration well, Perseverance #1, offshore Bahamas, in the B-North segment of the Cooper license. Expected to be spudded in April, the well will target recoverable prospective resources of 700,000 to 1.4 billion bbl of oil.
The authorization has been granted by the Minister in accordance with Regulation 3 of the Bahamian Petroleum (Offshore Environmental Protection and Pollution Control) Regulations 2016. The EA application was submitted Apr. 26, 2018.
The objective of the well is to Test 3 and 4-way dip closures on anticlinal/fault structure for the presence of hydrocarbons, the company noted in a February investor presentation. While drilling, LWD/MWD tools will record rock properties, such as electric, sonic, density, porosity, pressures and fluid types (water, oil, or gas) Additional tools are available to collect fluid samples and side wall cores if required, as well as measure pressures and temperature.
The well, to be drilled at a depth of 4,800-5,600 m, is expected to take 45-60 days at an estimated cost of $25-30 million (plus $5 million for contingencies/expanded testing)
Perseverance #1 is 100% owned and operated by Bahamas Petroleum.
Wintershall starts gas production from Sillimanite field
Wintershall Noordzee BV, a 50-50 joint venture between Wintershall Dea and Gazprom EP International, started gas production from its operated Sillimanite field in the southern North Sea. Discovered in 2015, Sillimanite lies directly north of Wingate natural gas field and stretches across the UK and the Dutch Continental Shelves some 200 km off the coast of Den Helder.
The field will use the twice-recycled topside of the recently decommissioned E18-A platform, formerly P14-A topside.
Also in the southern North Sea, the company expects a final investment decision on the Dutch Rembrandt-Vermeer oil development late this year. The development concept is a proven southern North Sea type shallow water installation. On Vermeer, an integrated wellhead, process, utility and living quarters platform on top of a subsea storage tank as well as an offloading installation for oil export with shuttle tankers will be built. On Rembrandt, a normally unmanned wellhead platform with minimal facilities is planned.
The company also is evaluating the development potential of the Greater Ravn area in Denmark (OGJ Online, Apr. 19, 2017).
Hilcorp completes Green #2 in Matagorda County
Hilcorp Energy has started production from the Green #2 well in Lightning field, onshore Matagorda County, Tex., partner Otto Energy reported. The well was completed in the Tex Miss 1 interval with 66 ft of perforations out of a total of 146 ft of calculated net pay and is producing 12.4 MMscfd gas and over 350 b/d condensate. Further perforations may eventually be added. Detailed information obtained during evaluation has confirmed multiple levels of hydrocarbon pay in the field through 3D seismic reinterpretation.
Gross production from the Green #1 well continues at 14.3 MMscfd gas and over 400 b/d condensate with additional upside potential pending pressure stabilization. The upper Tex Miss 1 zone is the reservoir unit from which both Green #1 and Green #2 are producing. The lower Tex Miss 2/3 zone, aerially significantly larger and potentially thicker than the Tex Miss 1, has been tested in both Green #1 and Green #2. In both tests, production from the Tex Miss 2/3 has indicated lower permeability than Tex Miss 1 and has not been able to produce steadily. A future well will test the ability to stimulate the zone.
The plan is to run both wells and evaluate the potential for additional wells to be added to the field.
Hilcorp Energy is operator with 62.5%. Otto Energy holds 37.5%.
PROCESSING Quick Takes
Gazprom Neft installing new process control system at Omsk refinery
PJSC Gazprom Neft is implementing an integrated automated process control system (APCS) at its 430,000-b/d Omsk refinery in Western Siberia.
Developed by Gazprom Neft industrial automation subsidiary Avtomatika-Servis and designed specifically for the refinery’s 2 million-tpy advanced oil refining complex (AORC) currently under construction, the APCS integrates three distinct technological processes in the future complex into a single, cohesive system that will be able to manage the refinery’s more than 80 existing control systems, as well as AORC’s, by processing information from 18,700 sensors concurrently into a single-flow process, Gazprom Neft said.
The APCS system, which also will be integrated into the operator’s future production control system to further enhance efficiency and reliability of the entire vertical production chain, is currently undergoing precommissioning activities, according to the company.
Part of the second phase of the operator’s ongoing modernization program at the Omsk refinery, the new APCS—which will use a combination of hydrocracking and sulfur-removal technologies to remove 99.8% of sulfur compounds from unfinished feedstock for production of Euro 5-quality fuel—is scheduled for completion by 2021 (OGJ Online, Feb. 19, 2020; July 12, 2017).
Crestwood commissions Bucking Horse II gas plant
Crestwood Equity Partners LP has started commercial operations at its Bucking Horse II cryogenic natural gas processing plant in Converse County, Wyo., in the Powder River basin.
In operation as of Mar. 4, the 200-MMcfd increases Crestwood’s total Powder River basin processing capacity to 345 MMcfd, the operator said.
Alongside startup of the Bucking Horse II plant, Crestwood also confirmed it has entered a new gathering and processing agreement to provide wellhead services for Occidental Petroleum Corp.’s 2020 delineation program in Powder River basin, on the eastern portion of Crestwood’s existing Jackalope gas gathering services system in Converse County.
Based on proximity of Occidental’s wells to existing Jackalope system, Crestwood said it expects minimal incremental capital requirements to connect the new wells.
Occidental is one of the largest operators in the basin with about 400,000 net undeveloped acres, according to Crestwood.
There are currently 19 rigs running in the Powder River basin, three of which are running on acreage dedicated to the Jackalope system, Crestwood said.
In 2019, the Jackalope system averaged gathering volumes of 145 MMcfd and processing volumes of 125 MMcfd, increases of 41% and 46%, respectively, compared with 2018.
Based on current development plans from Chesapeake Energy Corp., Occidental, and Panther Energy Co., Crestwood said it expects to connect 45-50 wells to Jackalope in 2020, and estimates volume growth of 10% for gathering volumes and 15% for processing volumes above growth in 2019.
With the Bucking Horse II plant now completed, Crestwood said its capital requirements in the basin will decrease substantially. The operator, however, said it does plan to invest future capital in various expansion and optimization projects across the system, including line looping and compression.
Further details regarding the proposed capital investment projects were not disclosed.
Preem lets contract for renewable fuels plant at Gothenburg
Swedish refiner Preem AB, a wholly owned subsidiary of Corral Petroleum Holdings AB, Stockholm, has let a contract to Haldor Topsoe AS to provide process technology for a grassroots renewable fuels plant to be built at its 125,000-b/d refinery in Gothenburg, Sweden.
As part of the contract, Haldor Topsoe will license its proprietary HydroFlex renewable fuel technology as well as supply basic engineering, proprietary equipment, catalysts, and technical services for the unit to enable the refinery’s production of clean, renewable diesel and jet fuel, the service provider said.
Scheduled for startup in 2024, the new 16,000-b/d unit—which will be completely dedicated to producing renewable fuels from tall oil, tallow, and other renewable feedstocks—will produce about 1 million cu m/year of fuels, which corresponds to about 25% of Sweden’s estimated consumption of renewable fuels in 2030 and will enable reduced carbon dioxide (CO2) emissions from cars and planes by 2.5 million tonnes/year, according to Haldor Topsoe.
Alongside awarding the contract for the new unit, Preem also has signed a letter of intent with Scandinavian Airlines, or SAS, to bring the unit’s production of renewable jet fuel to market, Haldor Topsoe said.
A value of the technology licensing contract was not disclosed.
The Gothenburg renewable fuels plant comes as part of Preem’s broader plan to become the world’s first climate-neutral petroleum and biofuels company with net zero emissions across its entire value chain before 2045. The operator also said it plans to increase its renewable fuel production to 5 million tpy by 2030.
As part of its net-zero emissions program, Preem and US-based project developer Beowulf Energy LLC, New York, also recently let a contract to McDermott International Inc. to provide front-end engineering design for the partners’ plan to build a residue hydrocracking plant—or residue oil conversion complex (ROCC)—at Preem’s 220,000-b/d refinery in Lysekil, Sweden, to enable the refinery to upgrade as much heavy oil as possible into sulfur-free gasoline and diesel fuels to help meet rising demand (OGJ Online, Jan. 27, 2020).
Preem also confirmed in 2019 that it intends to build a full-scale carbon capture plant at the Lysekil refinery to reduce CO2 emissions by one-third by 2025 following a demonstration project at the site that began in 2019 and will run to 2021 (OGJ Online, Mar. 4, 2019).
TRANSPORTATION Quick Takes
NGTL to buy Pioneer gas pipeline
TC Energy Corp.’s wholly owned subsidiary, Nova Gas Transmission Ltd. (NGTL), has executed an exclusive letter of intent with Tidewater Midstream and Infrastructure Inc. and TransAlta Corp. to purchase the Pioneer Pipeline.
Pioneer consists of 131 km of operating pipeline that, upon closing, will be integrated into the NGTL system. The pipeline runs from west of Drayton Valley, Alta., to west of Edmonton. The acquisition is underpinned by 15-year firm delivery contracts for 328 MMcfd and an 8-year firm receipt contract for 47 MMcfd.
TC Energy said the acquisition would help connect Western Canadian Sedimentary Basin production to growing provincial power generation demand.
The proposed $255-million purchase is subject to execution of definitive agreements, expected to occur second-quarter 2020. The acquisition also requires approval of the Canadian Energy Regulator.
Tellurian, Petronet extend MOU timing for Driftwood equity investment
Tellurian Inc. has extended its memorandum of understanding (MOU) with Petronet LNG Ltd. wherein Petronet and its affiliates intend to negotiate the purchase of up to 5 million tonnes/year of LNG from the Driftwood project, concurrent with an equity investment in Driftwood Holdings.
The MOU signed in September 2019 previously contemplated that transaction agreements would be finalized by Mar. 31 (OGJ Online, Sept. 23, 2019). The timing has been extended to May 31 to support Petronet’s consultative review process.
Petronet looks to spend $2.5 billion for an 18% equity stake in the project. A $5-billion debt commitment comprises the remainder, said Tellurian Chief Executive Officer Meg Gentle in September 2019.
The Driftwood LNG project consists of two main components: the construction and operation of the LNG facility, which includes five LNG plant facilities to liquefy natural gas, three tanks to store the LNG, LNG carrier loading and berthing facilities, and other appurtenant facilities at a site near Carlyss, Calcasieu Parish, La.; and the construction and operation of about 96 miles of pipeline, three compressor stations, and 15 meter stations.
Pacific Coast LNG project in Mexico lets FEED contract
Mexico Pacific Ltd. LLC (MPL), a Pacific Coast LNG project based in Mexico, has let a contract of initial design and engineering (FEED) to TechnipFMC (OGJ Online, Feb. 3, 2020).
Major permitting of the project is complete, and a final engineering decision is expected in early 2021 with commissioning in 2024, said Josh Loftus, MPL development director, in a statement.
MPL looks to connect Permian gas to Asian markets. MPL’s facility will be constructed by an EPC contractor using equipment supplied by Baker Hughes. MPL will build its 12 mtpa facility on a 1,100-acre site it owns in Puerto Libertad in Sonora, Mexico, some 125 miles south of the Arizona border. MPL is backed by AVAIO Capital.
