GENERAL INTEREST Quick Takes
US was net energy exporter in November
The US became a net energy exporter for the first time in 60 years during November and produced a record 12.9 million b/d of crude oil, the American Petroleum Institute said Dec. 19 as it released its 2019 fourth quarter industry outlook and latest monthly statistical report.
With solid productivity and expanded pipeline infrastructure, the nation is in a position to continue its oil and gas production growth in 2020 as predicted by the US Energy Information Administration, the quarterly industry outlook said.
It found that US energy exports have continued to grow despite trade frictions. “Nationwide, natural gas demand for electricity generation increased 5.65 year-to-year so far in 2019, reflecting its cost competitiveness,” the outlook indicated.
Domestic petroleum demand remained near record peaks throughout 2019, it said. The US refining system is well-positioned to meet 2020 International Maritime Organization (IMO) sulfur reduction requirements due to its relatively complex plant, access to attractive crude feedstocks, abundant and inexpensive natural gas, and the best refining workers globally, API’s latest quarterly industry outlook said.
“Motor gasoline and diesel fuel prices have generally moved with crude oil, and EIA expects limited impact from IMO 2020,” API’s latest quarterly industry outlook said. “Since 2000, US distillate stocks have remained above 100 million bbl with an increasingly interconnected supply chain and pipeline network.”
API releases standard for layflat hose operations
The American Petroleum Institute issued its first safety and environmental protection standard covering layflat hoses, high-pressure equipment which upstream operators use to transport associated water from production operations.
Compliance with Recommended Practice 15WT will assure operators and users that they are deploying the equipment in a manner that maintains the layflat hose’s integrity while transporting water at consistently high volumes and under high pressures, it said on Dec. 17.
API noted that the new standard includes workplace procedures and protocols aimed at driving safe use of production equipment by calling for users to:
- Conduct thorough risk management evaluations before deploying a layflat hose deployment to account for possible environmental impacts.
- Avoid operating layflat hoses underwater.
- Install pressure gauges and alarm systems at water transfer pumps to provide continuous operator feedback and alert personnel of overpressure or abnormal changes in pressure.
- Perform pre-job and hydraulic testing.
- Prepare a response to mitigate environmental and operational risks associated with spills.
RP 15WT also outlines proper actions for storage and transportation, including retrieval and respooling of layflat hoses and actions that need to be taken to protect on-site workers during draining and pigging operations, API indicated.
It said that in addition to RP 15WT, a new product specification for manufacturing layflat hose assemblies will be forthcoming. This specification also will include performance requirements for layflat hose materials and couplings. Together, the recommended practices and specifications will further drive the safety, reliability, and environmental integrity of layflat hoses, API said.
Continental Resources names new CEO, COO
William Berry has been appointed chief executive officer of Continental Resources Inc., Oklahoma City. Harold Hamm, founder and chief executive officer, became executive chairman on Jan. 1. Berry has been a director of Continental Resources since May 2014. He retired from ConocoPhillips as executive vice president, exploration and production, in January 2008.
Hamm had served as chief executive officer and a director since the company’s inception in 1967.
Jack Stark who has served as president since September 2014, assumes the additional role of chief operating officer.
Rystad: E&P investments in 2020 will decrease 4%
Overall global upstream investments in 2020 will decrease by around 4% with investments in shale/tight oil expected to contract the most, by almost 12%, said Rystad Energy.
Rystad believes that the lower oil price and weaker cash flows will force shale companies to reduce activity. Deepwater is the only segment expected to grow above 5% next year, spelling a boom for the industry.
On a regional level, only Africa, Russia, and South America are expected to see growth or flat development in investments next year, with key players like Mozambique, Libya, and Mauritania pushing the largest continent’s growth to the highest worldwide at 11%.
Unsurprisingly, Brazil, thanks to Marlim and Mero projects, will likely prop up South America to a predicted growth of almost 6% in 2020. Investments in the Middle East and Australia also are expected to grow on the back of new LNG projects and the redevelopment of old oil fields.
Exploration & Development Quick Takes
Chevron sanctions Anchor in US Gulf of Mexico
Chevron Corp. has sanctioned the Anchor project in the US Gulf of Mexico, marking the industry’s first deepwater high-pressure development to achieve a final investment decision. At a cost of $5.7 billion, Stage 1 of Anchor development consists of a seven-well subsea development and semi-submersible floating production unit. First oil is anticipated in 2024.
Anchor field lies in the Green Canyon area, 225 km off the coast of Louisiana, in water depths of 1,524 m. The planned facility has a design capacity of 75,000 bbl of crude oil and 28 MMcfd of natural gas. The total potentially recoverable oil-equivalent resources for Anchor are estimated to exceed 440 million bbl. The discovery was successfully appraised in the Lower Tertiary Wilcox trend in October 2015 (OGJ Online, Oct. 29, 2015).
Delivery of the new technology, which is capable of handling pressures of 20,000 psi, also enables access to other high-pressure resource opportunities across the Gulf of Mexico for Chevron and the industry, the company said.
The project’s sanction “shows that the US Gulf of Mexico still offers attractive investment opportunities for large greenfield developments,” said Justin Rostant, an analyst with Wood Mackenzie’s Gulf of Mexico team. “While over 80% of projects sanctioned in the last 5 years are shorter-cycle subsea tiebacks, standalone developments like Anchor are still able to compete for development capital,” he said.
The project is the first of three 20-K projects that Wood Mackenzie expects to reach FID within the next 18 months, Rostant said. “We estimate that these three projects combined hold approximately 1 billion bbl of oil equivalent in reserves and will require over $10 billion of capital investments.”
Wood Mackenzie values Anchor at $1.5 billion with a development-cycle breakeven of $51/bbl (Brent).
Chevron USA Inc. is operator with 62.86% interest. Total E&P USA Inc. holds 37.14%.
Canacol to explore Middle Magdalena Valley basin
Canacol Energy Ltd. expects to initiate exploratory activity on conventional gas exploration blocks in Colombia this year with a view to drilling in 2021 and 2022. The company secured a 100%-operated working interest in three new conventional gas exploration contracts in the recent bid round (Proceso Permanente de Asignación de Areas Ciclo 2) administered by Colombia’s hydrocarbon regulatory authority, the Agencia Nacional de Hidrocarburos.
Under its wholly owned subsidiary CNE Oil & Gas SAS, Canacol was awarded conventional exploration contract VIM 33 (155,310 acres) in the Lower Magdalena Valley basin, and conventional exploration contracts VMM 45 (12,422 acres) and VMM 49 (148,244 acres) in the Middle Magdalena Valley basin. On a net acreage basis, these conventional exploration contracts increase the company’s land position for conventional natural gas in Colombia by 29% to 1.4 million net acres from 1.1 million net acres.
By extending exploration efforts for conventional natural gas to the Middle Magdalena Valley basin, the company continues its strategy to replace declining production from the mature gas fields in the Guajira and at Cusiana-Cupiagua in the Llanos basin, said Mark Teare, senior vice-president, exploration.
The winning bids commit the company to an exploratory work program including geological studies, seismic, and wells over a 3-year phase (Phase 1) on each of the exploration contracts. After Phase 1, the company has the option to extend the exploratory work program by an additional 3 years (Phase 2) on each of the exploration contracts.
Total launches FEED for North Platte discovery
Total has launched front-end engineering and design (FEED) for the North Platte discovery in the deepwater US Gulf of Mexico, marking its return to the region as an operator. A final investment decision is expected in 2021.
North Platte field straddles four blocks of the Garden Banks area, 275 km off the coast of Louisiana in 1,300 m of water. The reservoir is of high quality, both in porosity and permeability, with thickness in places exceeding 1,200 m.
Discovered in 2012 by Total and Cobalt International Energy Inc. in the Wilcox play, North Platte covers Blocks 915, 916, 958, and 959. The field is now fully appraised with a total of three wells and three sidetracks (OGJ Online, Dec. 5, 2012; Jan. 4, 2017).
Like Anchor, sanctioned by operator partner Chevron (62.86%), North Platte requires the use of 20 kpsi technologies (OGJ Online, Dec. 12, 2019). The field development plan is based on eight subsea wells and two subsea drilling bases connected via two production loops to a newbuild, lightweight floating production unit (FPU). Production will be exported through existing oil and gas subsea networks.
Total operates North Platte with a 60% working interest, alongside Equinor, 40%. With Equinor (then Statoil) in April 2018, Total E&P USA bid $339 million for the North Platte prospect on Garden Banks during the bankruptcy auction of Cobalt (OGJ Online, Apr. 11, 2018).
Oil production at plateau level is expected to average 75,000 b/d. Output will include associated gas. Total also holds interests in high-potential exploration acreage in the Greater North Platte Area, and the FPU design provides for a possible future tie-in.
Drilling & Production Quick Takes
Johan Castberg partners nix Veidnes transfer terminal talk
After studying a possible development of a downscaled ship-to-ship oil transfer terminal at Veidnes in Finnmark county in North Norway, Johan Castberg partners concluded that the costs of constructing a terminal will be too high, Equinor reported Dec. 13 (OGJ Online, Dec. 5, 2017). The oil export from Johan Castberg will therefore go directly to the market, as described in the plan for development and operation (PDO).
In March 2018, the study of a full-scale oil terminal for the Barents Sea was shelved, and a new study of alternative solutions for ship-to-ship transfer of oil from the Barents Sea by a quay in Finnmark was initiated. Several solutions for ship-to-ship oil transfer in a fjord or by a quay were studied.
The studies have considered both current and future volumes. Based on volumes from Johan Castberg and Goliat, the financial loss before tax is estimated at $3.6 billion kroner, compared to oil export directly to the market. In a large-volume scenario, including other proven Barents Sea volumes, the financial loss before tax is estimated at slightly above $2.8 billion kroner.
“We will still continue the work of securing local spinoffs and jobs from the field both in the development and operating phases,” said Anders Opedal, Equinor’s executive vice-president for technology, projects, and drilling.
Johan Castberg license partners are Equinor (50%), Var Energi (30%), and Petoro (20%).
BP confirms potential offshore Mauritania and Senegal
BP will conduct further appraisal drilling offshore Mauritania and Senegal to help inform future development decisions after the company’s recent three-well drilling campaign further confirmed the scale of the gas resource in the region, the company said.
Three appraisal wells drilled in 2019—GTA-1, Yakaar-2, and Orca-1—targeted a total of nine hydrocarbon-bearing zones. The wells encountered gas in high quality reservoirs in all nine zones (OGJ Online, Sept. 22, 2019; Oct. 28, 2019).
The wells were the first in the region to be operated by BP. In total, the wells encountered 160 m of net pay. The overall drilling campaign was delivered 40 days ahead of schedule and $30 million under budget.
In November 2019, Orca-1 well in Block C8 offshore Mauritania encountered all five of the gas sands originally targeted. The well was then further deepened to reach an additional target, which also encountered gas.
The result “proves that our seismic data is identifying hydrocarbon reservoirs deeper than we had previously thought,” said Howard Leach, head of exploration.
The Greater Tortue Ahmeyim Phase 1 development was sanctioned in December 2018. The successful results of Yakaar-2 and Orca-1 could underpin future developments, including a possible new development in Yakaar-Teranga in Senegal and in the Bir Allah/Orca area in Southern Mauritania. Timing of potential future developments depends on the level of appraisal required, supporting commercial development plans, and integrated gas master plans in the host nations.
BP holds 62% interest in Block C8 in Mauritania. Partners are Kosmos Energy (28%) and SMHPM (10%). BP holds 60% interest in the Cayar Profond block (which includes Yakaar-2) in Senegal. Partners are Kosmos Energy (30%) and Petrosen (10%). BP’s partners in the Greater Tortue Ahmeyim unit are Kosmos Energy, SMHPM, and Petrosen.
Falcon, Origin begin Beetaloo horizontal drilling
Falcon Oil & Gas Ltd. has begun drilling the horizontal section of the Kyalla 117 N2-1H appraisal well in Beetaloo subbasin, Northern Territory, Australia. The company is also evaluating the Kyalla 117 N2-1 vertical well.
A joint-venture between Falcon (30%) and Origin Energy (70%) elected to land the horizontal well within the Lower Kyalla shale, at ~1800 m TVD. The horizontal section will be drilled for 1,000-2,000 m. On completion of drilling, the horizontal section will be fracture stimulated and production tested.
Vertical-well evaluation identified three source rock reservoir (SRR) sections within the Kyalla shale formation, the Lower, Middle, and Upper Kyalla. The Kyalla shale measured almost 900 m thick. Gross thickness of each SRR interval is 75-125 m. Each SRR exhibited elevated gas shows with relatively high C3, C4, and C5 components. Diagnostic fracture injection tests (DFIT) were performed on each SRR.
Ongoing analysis of conventional cores acquired in each of the Upper and Lower Kyalla reservoir sections, along with sidewall cores, DFITs, and extensive wireline logging, will enable a full-scale evaluation of prospectivity of the Kyalla formation in the central part of Beetaloo subbasin.
Beetaloo, about 600 km south-southeast of Darwin, contains rocks of Proterozoic age within the larger McArthur basin.
PROCESSING Quick Takes
INA reaches FID on Rijeka refinery modernization
Croatia’s INA Industrija Nafte DD has taken final investment decision on a more-than $600-million plan to modernize its 90,000-b/d Rijeka refinery along the northern part of the Adriatic Sea.
Part of its INA Downstream 2023 New Course program, the proposed investment plan will involve concentration of crude processing activities at the Rijeka refinery and conversion of the company’s 44,000-b/d refinery in Sisak into a biorefining and petrochemical production site for bitumen, renewables, and potentially lubricants, as well as equipping it to perform as a modern logistics hub, INA said.
The proposed 3-year conversion process coincides with the concurrent construction of a heavy residue upgrading plant—or delayed coking unit (DCU)—at the Rijeka refinery, which would include a delayed coker, a coke port, storage installations, as well related pipelines and off sites. The DCU aims to improve the refinery’s production structure by increasing its output of more valuable products, such as motor fuels.
INA said it expects the project to be commissioned in 2023.
Conversion of the Sisak refinery into a base for bitumen production was approved in 2019, with portions of the project for lubricant production and biorefining still subject to further investment decisions, INA said. A timeframe for conversion was not disclosed.
INA is jointly owned by Hungary’s MOL PLC 49.1%, the Republic of Croatia 44.8%, and private and institutional investors 6.1%.
Guinea refinery advances
Brahms Oil Refineries Ltd. and Africa Finance Corp. (AFC) have agreed to codevelop Brahms’s refinery and storage project in Kamsar, Guinea. The project will include a 12,000 b/d modular refinery (producing gasoil, kerosene, gasoline, and fuel oil), 76,000 cu m of crude oil storage, 114,200 cu m of refined products storage, and ancillary transportation infrastructure.
The refinery will be able to meet about one-third of Guinea’s refined products demand, according to the companies, adding that Kamsar is one of the country’s larger mining regions.
Brahms, based in Geneva, and AFC expect to close the agreement in early 2020. A local company, Societe de Raffinage Guineenne SA, has been established to build the project.
SNC-Lavalin Group Inc. performed front-end engineering design for the project in 2017 (OGJ Online, July 26, 2017).
MPC lets contract for ND refinery conversion
Marathon Petroleum Corp. (MPC) has let a contract to WorleyParsons Ltd. to provide detailed engineering services for conversion of Marathon’s 19,000-b/d refinery in Dickinson, ND, into a renewable diesel refinery.
Under the contract, Worley will provide engineering services as well as procure equipment and materials for the refinery conversion, the service provider said.
Worley—which provided engineering services during the project’s early concept phase—said it will execute its work under the contract out of its US offices with support from global locations. A value of the contract was not disclosed.
MPC plans to convert the existing Dickinson refinery into a 12,000-b/d, 100% renewable diesel refinery that will process refined soy oil and other organically derived feedstock in 2020.
TRANSPORTATION Quick Takes
CER approves Chevron Canada application to export LNG
Canada’s Energy Regulator (CER), formerly the National Energy Board (NEB), approved an application by Chevron Canada to export LNG from Kitimat, BC, for a term of 40 years.
In its application, Chevron Canada said that it intends to export up to 18 million tonnes (997 bcf) of liquefied natural gas per year from the proposed Kitimat LNG project with markets in the Pacific Rim (Japan, South Korea, and China) as intended targets.
The approval doubles the timeline of a 2011 license agreed to by the NEB. At the time, the regulators approved a 20-year license to export 10 million tonnes/year (tpy) of natural gas.
In its recent approval, the CER found that the natural gas that Chevron plans to export would be surplus to the needs of Canadians, both today and in the future.
Chevron will operate a proposed natural gas liquefaction export terminal to be constructed and operated at Bish Cove, near Kitimat, BC. Development will proceed by way of an unincorporated joint venture between Chevron and KM LNG Operating GP. A revised plant design calls for up to three LNG trains to deliver up to 18 million tpy of LNG as the world’s first all-electric LNG plant powered by renewable hydroelectricity from BC Hydro, Chevron said.
Commissioning is anticipated to be no later than 2029, depending on the pace of regulatory approvals and a final investment decision by the project’s sponsors, Chevron said.
CER said the decision does not come into effect until it is approved by Governor in Council.
Epic begins Corpus Christi crude exports
Epic Crude Holdings LP loaded the first shipment of crude oil from its IGC marine terminal on the inner harbor of the Corpus Christi Ship Channel. The IGC terminal, formerly the International Grain Port Terminal, was repurposed by Epic beginning in June 2019 to export crude oil while the company’s larger export terminal is still under construction.
Once complete, Epic’s marine terminal will consist of two separate docks: the West Dock and the East Dock. The West Dock, IGC, can load up to Aframax-sized tankers (750,000 bbl) at a maximum rate of 20,000 bbl/hr. The East Dock, adjacent to the West Dock, is a greenfield dock that will load up to Suezmax-sized tankers (1 million bbl) at a maximum rate of 40,000 bbl/hr. Epic expects the East Dock to enter service third-quarter 2020.
The Epic Crude Oil Pipeline runs parallel to the Epic Y-Grade Pipeline from Orla, Tex., to the Port of Corpus Christi and includes terminals in Orla, Saragosa, Crane, Wink, Midland, Upton, Hobson, and Gardendale, with connectivity to the Corpus refining market as well as multiple terminals in the Port of Corpus Christi for export access. The crude pipeline services Delaware, Midland, and Eagle Ford basins.
EPIC began interim crude operations in August 2019, using the 24-in. OD Y-grade pipeline, which can ship up to 400,000 b/d from Crane, Tex., to terminals in Corpus Christi and Ingleside. Once the planned 30-in. OD crude pipeline is completed in first-quarter 2020, Epic will have initial capacity to transport 600,000 b/d. The crude pipeline is expandable up to 900,000 b/d.
