GENERAL INTEREST Quick Takes
Equinor approved to extend operation of Troll B
Equinor and its partners have been granted a 10-year extension from Norwegian authorities for Troll B facility in Troll field in the North Sea until 2030.
The extended lifetime also includes the oil and gas pipelines that were included in the approved plan for development and operation (PDO). The current consent expires in September this year. Since Troll B start-up in September 1995, the facility has produced more than one billion bbl of oil (OGJ Online, Oct. 16, 1995).
Extension of Troll B’s lifetime is one potential solution for further developing gas production from the Troll West gas cap, Troll Phase 3.
Nine seismic surveys have been carried out on the Troll field, with the last one completed in summer 2019. All previous surveys have contributed to identify new well targets. The licensees expect the results from processing the data from the latest seismic survey will yield additional well targets which can be drilled from the subsea templates tied to Troll B.
Kosmos cuts budget as Greater Tortue Ahmeyim project hits delay
Kosmos Energy, Dallas, has cut an additional $75 million from its 2020 budget, including costs associated with the BP-operated Greater Tortue Ahmeyim LNG project in Mauritania and Senegal now delayed due to restrictions arising from the coronavirus pandemic.
The company is now targeting total capital expenditure of $200-225 million in 2020. In March, the company made a 30% cut to its 2020 base production capital to under $250 million from the previous $325-375 million budget (OGJ Online, Mar. 17, 2020).
Greater Tortue Ahmeyim project activities impacted include construction of the breakwater during the 2020 weather window. The Phase 1 project timeline is expected to be delayed by 12 months, with first gas now expected in the first half of 2023. Phase 1 of the project is currently over 30% complete.
Kosmos said it is working with BP to establish a revised 2020 budget with the objectives of maintaining the project economics and extending the carry of its capital obligations through the end of this year.
BP, Hilcorp revise financial terms of Alaska sale
Citing significant market volatility and oil price drops, BP and Hilcorp have renegotiated financial terms of the 2019 deal that would see BP sell its Alaska business to Hilcorp (OGJ Online, Sept. 2, 2019).
Subject to regulatory approvals, the deal is expected to close in June.
Originally, Hilcorp was set to pay BP $4 billion near-term and $1.6 billion through an earnout thereafter for total consideration of $5.6 billion. Hilcorp paid BP a $500-million deposit on signing of the transaction in 2019.
The revised agreement adjusts the structure and phasing of the remaining consideration to include lower completion payments in 2020, new cash flow sharing arrangements over the near-term, interest-bearing vendor financing and, potentially, an increase in the proportion of the consideration subject to earnout arrangements.
In Alaska, BP operates Prudhoe Bay, with a working interest of 26%, and holds non-operating interests in producing Milne Point and Point Thomson fields. It also holds non-operating interests in the Liberty project and exploration lease interests in the Arctic National Wildlife Refuge. In addition to shares in TAPS and its operator the Alyeska Pipeline Service Co., BP is divesting its midstream interests in the Milne Point Pipeline and the Point Thomson Pipeline.
The deal is part of BP’s divestment program to deliver $15 billion of announced divestments by mid-2021.
Aker BP to merge exploration, reservoir units
Aker BP has appointed Evy Glørstad as senior vice-president of exploration and reservoir, merging the exploration and reservoir business units as it expects oil prices to remain low over time, resulting in reduced activity. The appointment comes into effect in October, at which time Ole-Johan Molvig, who currently services as senior vice-president of reservoir, will step down from the executive management team and continue with the company in an unspecified role.
Glørstad has held several managerial positions at Aker BP and has led the company’s exploration activities since July 2018.
Exploration & Development Quick Takes
West Erregulla JV plans next stage appraisal
West Erregulla joint venture partners Strike Energy Ltd. and Warrego Energy Ltd. have planned the next stage of appraisal work at the gas field in the North Perth basin onshore Western Australia.
The approved three-well plan provides for the West Erregulla-4 and possibly West Erregulla-5 wells to be added to the West Erregulla-3 drilling and 3D seismic program.
The seismic will be acquired over a substantial portion of the remaining part of EP469.
The opportunity to drill the wells in close succession will support further understanding of the field and its plans for its future development.
All the wells will be drilled for use as future producers to support the proposed Stage 1 development.
Strike, as operator, anticipates that the appraisal work will enable the JV to take advantage of the current lull in exploration activity in the short-term, while in the longer-term the companies will be positioned to benefit from the expected tightening in the market and likely shortfall in domestic gas supply following delays to major offshore Western Australian LNG projects and their associated domestic supply obligations.
Drilling of West Erregulla-3 is expected during this year’s second half. A decision on drilling West Erregulla-5 will be made before the end of November.
The field development timeline remains on track with a proposed final investment decision during this year’s fourth quarter, Strike said.
Strike and Warrego each have 50% interest in the permit.
Santos approved for seismic in Bedout subbasin
Santos has been granted approval by Australia’s National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) to run its Keraudren Extension 3D seismic survey in the Bedout subbasin off the Western Australian coast.
The survey will run over parts of Santos-operated exploration permits WA-435-P, WA-436P, WA-437-P, and WA-438-P which contain the Dorado, Roc, and Phoenix discoveries.
The program is an extension of the original Keraudren survey run in 2019 over Dorado field.
The survey data is required to develop regional geological models to determine permit retention strategy and locate future exploration and development well locations, Santos said.
The survey will be run in stages with the exact area of each stage yet to be nominated. The intention is to acquire the full survey in 2021 and/or 2022. Work will be confined to a 6-month period between the beginning of February and the end of July to avoid interfering with fish spawning and whale migration periods.
The survey is expected to take 132 days to complete over an operational area of just over 20,000 sq km. Water depths are 40-250 m.
Total comes up dry on Block 4, offshore Lebanon
Total E&P Liban SAL failed to encounter hydrocarbons in the Byblos 16/1 exploration well, Block 4, Lebanon.
The well—drilled 30 km offshore Beirut to 4,076 m on Apr. 26 in 1,500 m of water—penetrated the Oligo-Miocene target section. Trace gas confirmed presence of hydrocarbons, but the target Tamar formation was not encountered. Based on data acquired, studies will be conducted to understand the results and further evaluate exploration potential of the Total-operated JV blocks and for offshore Lebanon.
Total is operator of Block 4 with 40% interest (OGJ Online, Feb. 9, 2018). Partners are ENI (40%) and Novatek (20%).
Drilling & Production Quick Takes
Jadestone suspends Australian infill drilling
Jadestone Energy Co., Singapore, will defer its planned 2020 infill drilling program in Stag, Skua, and Montara oil fields offshore northwest and northern Australia until 2021 in order to preserve its balance sheet and cash position, and enable it to maximize future returns when the global oil price recovers from its current lows, the company said.
Two development infill wells had been planned for its 100%-owned Stag oil field in the Carnarvon basin off Western Australia in 2020. Also planned were a development well on each of the 100%-owned Montara field and Skua fields in the Timor Sea along with a workover of two wells in the same fields.
The Australian drilling program deferment comes just one month after Jadestone cut its capital expenditure by 50% and deferred its Nam Du and U Minh field development program offshore Vietnam.
Collectively, these measures represent a reduction of 80% of the company’s original 2020 planned spending, resulting in anticipated total capex of $30-35 million in 2020, of which about $15.5 million was spent in the year’s first quarter, including completing the Montara seismic campaign.
With the delay in the Australian infill wells, the company is now targeting a 2020 average production range of 12,000–14,000 bbl/d.
Jadestone said that about one third of its oil production is hedged at $68.46/bbl until Sept. 30.
Despite these changes, the company’s production is still expected to grow by about 25% in 2021 with the addition of the Maari project, offshore New Zealand.
Novatek first quarter production up from 2019
PAO Novatek’s first-quarter 2020 hydrocarbon production totaled 150.2 MMboe, including 19.08 billion cu m (bcm) of natural gas and 3,048 thousand tons of liquids (gas condensate and crude oil), an increase in total hydrocarbons produced of 3.1 million boe, or 2.1% as compared with first-quarter 2019. Preliminary natural gas sales volumes, including volumes of LNG sold, aggregated 20.69 bcm, a decrease of 6.8% compared with the prior year period.
Natural gas volumes sold in the Russian Federation in first-quarter 2020 were 18.24 bcm. LNG sold in international markets amounted to 2.45 bcm. The decrease in sales volumes on international markets was due to the decrease of Yamal LNG shareholders’ share, including Novatek’s share, of LNG sales on the spot market, and a corresponding increase of Yamal LNG direct sales under long-term contracts. Novatek also reported that it is slightly off schedule for the end-2022 opening of its 19.8 million tonne/year Arctic LNG 2 plant.
The company processed 2,823 thousand tons of unstable gas condensate at it Purovsky processing plant, an increase of 4.8% compared with the corresponding volumes processed in the year-prior reporting period. Novatek processed 1,787 thousand tons of stable gas condensate at its Ust-Luga complex, an increase of 1.2%.
According to preliminary first-quarter 2020 data, petroleum product sales volumes totaled 1,696 thousand tons: 1,040 thousand tons of naphtha, 302 thousand tons of jet fuel, and 354 thousand tons of fuel oil and gasoil. Novatek sold 1,164 thousand tons of crude oil and 414 thousand tons of stable gas condensate.
As at Mar. 31, Novatek had 0.3 bcm of natural gas, including LNG, and 620 thousand tons of stable gas condensate and petroleum products in storage or transit and recognized as inventory.
Crescent Point shut-ins lower production guidance
Crescent Point Energy Corp., Calgary, has lowered its annual production guidance by 15%, primarily due to voluntary shut-in of higher cost production. Annual average production is now forecast to be 110,000-114,000 boe/d for 2020. In aggregate, Crescent Point is shutting-in 25,000 boe/d of its current production, of which 70% is oil.
Management continues to evaluate market conditions, including market access constraints and the potential for involuntary shut-ins.
The company is lowering its 2020 capital expenditures guidance by $75 million, or 10%. Capital expenditures for 2020 are now forecast to be $650-700 million with no associated impact to production.
The company lowered its original 2020 capital expenditures guidance by over 40%. Further reductions are possible. Some 65% of the company’s remaining 2020 budget is expected during fourth quarter. The majority of these expenditures are discretionary and dependent on commodity prices, the company said.
Operating expenses for the current fiscal year are expected at $140 million—20% below initial expectations. Some $50 million of the reduction is sustainable and is expected to be driven by internal initiatives with the remaining reduction achieved through lower activity levels and cost savings from shut-in production.
Gran Tierre suspends fields
Gran Tierra has shut-in 2,500 b/d of oil with the temporary suspension of most minor fields with zero or negative netbacks at current oil prices.
Another 4,000 b/d remains shut-in and waterflood operations remain suspended at the Suroriente and PUT-7 Blocks in the southern Putumayo region in Colombia due to a local farmers’ blockade.
Production and waterflood operations are expected to resume to pre-suspension levels once COVID-19, blockade, and economic restrictions pass.
An additional 4,800 b/d of oil production awaiting routine mechanical workovers will remain offline during the low-price environment. While the Colombian government has deemed the oil and gas industry essential during the COVID-19 pandemic, mobility and logistics issues may result in oil field restart and workover services delays.
In March, the company reduced its 2020 capital program to $60-80 million from $200-220 million. The company said it remains focused on ongoing production and waterflooding of Acordionero, Costayaco, and Moqueta, which represent 81% of the company’s working interest total proved reserves as of Dec. 31, 2019.
PROCESSING Quick Takes
Sinopec starts up new unit at Wuhan refinery
China Petroleum & Chemical Corp. (Sinopec) subsidiary Wuhan Petrochemical Co. Ltd. has commissioned the first commercial-scale revamp of a hydrogen fluoride (HF)-based alkylation unit at its 161,000-b/d refinery in Wuhan City, Hubei Province (OGJ, July 8, 2019; Jan. 7, 2019, p. 61).
The 7,500-b/d unit, based on composite ionic liquid (IL) alkylation technology and commissioned on Jan. 21, 2020, has been operating at reduced capacity due to decreased fuel demand as a result of the COVID-19 pandemic, said Well Resources Inc., licensor for Beijing-based China University of Petroleum’s (CUP) Ionikylation process, on Apr. 15.
Sinopec previously commissioned an Ionikylation unit of similar capacity at subsidiary Sinopec Jiujiang Co.’s 161,000-b/d refinery in Jiujiang City, Jiangxi Province (OGJ Online, Apr. 2, 2019).
Commissioning of Sinopec’s newly revamped Wuhan unit follows PetroChina Co. Ltd.’s—the publicly listed arm of state-owned China National Petroleum Corp. (CNPC)—startup of a 3,000-b/d brownfield alkylation unit based on Ionikylation technology in November 2018 at subsidiary Harbin Petrochemical Co. Ltd.’s refinery in Harbin City, Heilongjiang Province, as well as the January 2019 commissioning of a 1,000-b/d Ionikylation unit at subsidiary Golmud Petroleum Refinery’s 20,000-b/d refinery in the Qinghai-Tibet Plateau of Golmud City, Qinghai Province, China, according to Well Resources.
Refiners in the Asia-Pacific region are increasingly turning to Ionikylation alkylation technology—which uses a proprietary composite IL catalyst that eliminates reliance on more dangerous, corrosive, and hazardous chemicals such as HF and sulfuric acid—as they seek to expand alkylation capacity to safely produce low-sulfur, higher-octane alkylate that complies with more stringent clean-fuel standards such as China 6-quality specifications (equivalent to Euro 6-quality standards).
PBF sheds hydrogen production plants, enters supply agreements
PBF Energy Inc. has completed the sale of five steam methane reformer (SMR) hydrogen production plants to Air Products and Chemicals Inc. as part of the refiner’s strategic plan to navigate current extraordinary and volatile markets as a result of the COVID-19 crisis.
As part of the $530 million deal finalized on Apr. 20, PBF Energy entered into long-term off-take arrangements under which Air Products will deliver hydrogen supplies to three of the operator’s refineries, including the 157,000-b/d dual-coking refinery at Martinez, Calif., 155,000-b/d Torrance, Calif., refinery, and 190,000-b/d refinery in Delaware City, Del., PBF Energy said.
Sale of the SMR hydrogen production plants follows PBF Energy’s Mar. 30 announcement that it also was reducing 2020 cash outlays by more than $500 million through lowered capital and operating expenses, dividend suspension, and other deferrals as part of its response to market impacts resulting from the global pandemic.
Caltex to shut Brisbane refinery
Caltex Australia will temporarily close its Lytton oil refinery in Brisbane next month due to plummeting profit margins caused by the COVID-19 crisis’ effect on world fuel demand.
The company said the refinery will close in May as it brings forward a planned maintenance program originally due in July. The maintenance work is expected to be completed by August, but the refinery will not re-open until margin conditions have sufficiently recovered, it said.
Caltex said its refining margin at Lytton had virtually halved in the last 12 months. In 2019 its margin was $7.34/bbl. In January 2020 it had fallen to $5.78 with a further fall in February to $4.14/bbl.
The company supplied 20 billion l. of fuel in 2019.
Interim chief executive Matthew Halliday said that Caltex was shutting the refinery so that it can protect cash flows while demonstrating an ongoing commitment to the plant.
Halliday added that the company is working closely with customers and government agencies to ensure its supply chain remains resilient.
TRANSPORTATION Quick Takes
Keystone XL water-crossing permit revoked
TC Energy Corp.’s 1,179-mile Keystone XL pipeline faces potential new delays after a federal court in Montana revoked a US Army Corp of Engineers (ACE) water-crossing permit for failing to assess the project’s impact on endangered species. The court’s ruling requires suspension of filling and dredging activities until the ACE conducts consultations compliant with the US Endangered Species Act.
Construction of the 830,000-b/d pipeline between Hardisty, Alta., and Steele City, Neb., resumed near the US-Canadian border earlier in April 2020. Work on the cross-border segment is not affected by the court’s ruling.
Keystone XL is underpinned by new 20-year transportation service agreements for 575,000 b/d. Once the pipeline is in service, current contracts for 115,000 b/d from Hardisty to the US Gulf Coast on the existing Keystone line also will shift to Keystone XL under renewed 20-year contracts (OGJ Online, Mar. 31, 2020).
TC Energy expects the line to enter service in 2023.
Pieridae expects Goldboro LNG project FID delay
Pieridae Energy Ltd. said final investment decision on its Goldboro LNG project in Nova Scotia, Canada, has been delayed due to market conditions and the global fallout from COVID-19.
Alfred Sorensen, chief executive officer, said advancement work continues, “primarily with KBR to finalize a fixed price contract to design and build the facility.” While FID cannot be made this fall, the company is “confident it will happen once conditions improve and we can better analyze the landscape,” Sorensen said in a statement Apr. 16.
In April 2019, the company said it would make FID by midyear to begin construction before 2020. Pieridae expects Goldboro to begin exports by fourth-quarter 2023.
Goldboro will have a send-out capacity of 10 million tpy, loadable onto vessels as large as 250,000 cu m. The plant includes three 230,000 cu m storage tanks and will load 7-13 ships/month.
Fieldwood awards Genesis GoM crude transport contract
Fieldwood Energy LLC, along with Ridgewood Katmai LLC and ILX Prospect Katmai LLC—two entities managed by Ridgewood Energy Corp.—awarded Genesis Energy LP contracts to provide downstream transportation services for 100% of crude oil production associated with the deepwater Gulf of Mexico Katmai field development through the existing Tarantula production platform, owned by Fieldwood. First deliveries of oil are anticipated second-quarter 2020.
Tarantula, in South Timbalier Block 308, can process up to 25,000 b/d from Katmai, in Green Canyon Blocks 39 and 40. Crude will be shipped through Genesis’s 100%-owned Tarantula lateral to its 64%-owned Poseidon system for delivery to shore.
The contracts for Katmai include life-of-lease dedications. No capital was required by Genesis to connect Katmai production to its assets.
Fieldwood acquired Katmai from Noble Energy Inc. in early 2018 as part of the former’s Chapter 11 bankruptcy restructuring.
