GENERAL INTEREST Quick Takes
EIA: US sets natural gas records in 2018
The US set new records in natural gas production, consumption, and exports in 2018, according to the US Energy Information Administration (EIA). Its Natural Gas Annual 2018 shows that dry natural gas production increased by 12% during 2018, reaching a record-high average of 83.8 bcfd. This increase was the largest percentage increase since 1951 and the largest volumetric increase in the history of the series, which dates back to 1930. US natural gas consumption increased by 11% in 2018, driven by the electric power sector. Natural gas gross exports totaled 10 bcfd in 2018, 14% more than the 2017 total of 8.6 bcfd. Several new LNG export plants came online in 2018, allowing for more exports.
US natural gas consumption grew in each end-use sector. Demand for natural gas as a home heating fuel was greater in 2018 than in 2017 because of slightly colder weather during most of the winter. Similarly, the summer of 2018 saw record-high temperatures, increasing demand for air conditioning and, therefore, electricity, much of which was generated by natural gas-fueled power plants. The electric power sector has been shifting toward natural gas in the past decade because of favorable prices and efficiency gains.
US natural gas production growth was concentrated in the Appalachian, Permian, and Haynesville regions. Pennsylvania and Ohio, states that overlay Appalachian basin, had the first- and third-largest year-over-year increases for 2018, increasing by 2 bcfd and 1.7 bcfd, respectively. Louisiana had the second-largest volumetric increase in dry production, up 1.8 bcfd as a result of more production from Haynesville shale. Texas remained the top natural gas-producing state (18.7 bcfd) as a result of continued drilling activity in the Permian basin in western Texas and eastern New Mexico.
US exports have risen steadily since 2014, when they totaled 4.1 bcfd. This has been the case despite fluctuating export prices. The average US export price in 2014 was $5.51/Mcf, dropping to $2.79/Mcf in 2016 before rebounding to $3.89/Mcf in 2018. Exports from Texas in 2018 averaged 3.9 bcfd, up from 1.4 bcfd in 2013.
NMED posts reported excess air emissions data
The New Mexico Environment Department (NMED) posted reported excess emissions data on its web site, saying it would update the information regularly. The excess emissions, which include volatile organic compounds (VOC) and nitrogen oxides (NOx), make up a large part of the state’s greenhouse gas (GHG) emissions and are contributing to concerning levels of ozone present in seven of the state’s counties, it said.
“Transparency of self-reported emissions data, in conjunction with our regulatory efforts to curb excess methane emissions in the oil and gas industry, is essential to understanding air-quality impacts in communities around the state,” NMED Cabinet Sec. James Kenney said. “Compliance with permits and air quality regulations is not optional—it is expected by the communities in which these facilities operate and by NMED.”
These excess emissions, which can include VOCs and NOx, make up a large part of the state’s GHG emissions and are contributing to higher ozone levels. The information extends back several years.
Posting this information highlights the extent of the problem and allows the public to see for itself the volume of emissions emitted in excess of allowable, permitted limits, Kenney said. While excess emissions are not necessarily violations, they present an opportunity for reductions, he said.
Rohling succeeds Wright as Halcon COO
Daniel P. Rohling has succeeded Jon Wright as executive vice-president and chief operating officer of Halcon Resources Corp. following the company’s emergence from bankruptcy under Chapter 11 of the US Bankruptcy Code.
The company completed its financial restructuring, eliminating more than $750 million in debt and $40 million of annual interest expense.
Rohling has 15 years of oil and gas operations experience and most recently served as the asset vice-president at Ajax Resources LLC until it sold most of its assets to Diamondback Energy Inc. in October 2018 for $1.2 billion (OGJ Online, Aug. 10, 2018).
Halcon entered into a restructuring support agreement on Aug. 2 and filed a prepackaged bankruptcy plan on Aug. 7. The bankruptcy filing was the second in nearly 3 years (OGJ Online, July 29, 2016). That same month, Ragan T. Altizer was appointed executive vice-president, chief financial officer, and treasurer (OGJ Online, Aug. 16, 2019).
Exploration & Development Quick Takes
Vintage farms into Perth basin Cervantes prospect
Vintage Energy Ltd., Adelaide, has signed a binding term sheet to farm into the Cervantes oil prospect in Western Australian licence area L14 on the north Perth basin coast just south of, and part of the producing Jingemia oil field production area.
Vintage has taken up a 30% interest leaving other partners Metgasco Ltd. and RCMA Australia Pty Ltd. (Jade) with 30% and 40%, respectively.
The farm-in agreement has a planned execution date prior to Dec. 18. The Cervantes-1 wildcat is scheduled for spudding during the third quarter of 2020. There is an option to drill a second well in a separate prospect.
Vintage will pay 50% of the Cervantes-1 well cost and A$200,000 of evaluation and exploration costs to earn its 30% interest.
Vintage said that the Cervantes structure lies in a gap between the oil discovery trend of Hovea, Jingemia, and (offshore) Cliff Head oil fields. These three fields have produced over 27 million bbl of oil from the main Permian-age reservoirs in the North Perth basin.
The Cervantes feature itself is a high-side fault trap of multiple Permian reservoir units and shares a similarity with the surrounding discovered fields. The prospective reservoirs of Dongara, Kingia, and High Cliff sandstones could contain up to 15 MMbbl on a best (2U) estimate. Close proximity to existing infrastructure means that success could be rapidly brought into commercial production.
PGNiG logs small discovery off Norway
PGNiG Upstream Norway expects to develop its small Shrek oil and gas discovery via tie-back to the nearby floating production, storage, and offloading vessel on Skarv field in the Norwegian Sea.
The Polish Oil & Gas Co. subsidiary operates the 6507/5-9 S wildcat and 6507/5-9 A appraisal sidetrack in 357 m of water 5 km south of the Skarv FPSO.
The discovery well encountered a total oil and gas column of about 85 m in the Middle Jurassic Fangst group, the primary target, and in the Lower Jurassic Bat group, the secondary target. About 60 m of sandstone had good to very good reservoir quality.
The well encountered the gas-oil contact at about 2,034 m below surface and oil-water contact at 2,074 m. The top of the reservoir is about 2,000 m below sea surface.
The westward appraisal well encountered a total oil and gas column of about 65 m in the same formations, of which 45 m of sandstones had good to very good reservoir quality.
The appraisal well encountered oil-gas and oil-water contacts at the same depths as in the discovery well.
Odfjell Drilling’s Deepsea Nordkapp semisubmersible rig drilled the 6507/5-9 S well to 2,261 m vertical depth and 2,285 m measured depth below sea surface and the 6507/5-9 A well to 2,134 m and 2,198 m on Production License 838.
Cores, logs, and fluid samples indicate 3-6 million cu m of recoverable oil-equivalent hydrocarbons. The wells have been plugged.
“It is very probable that the new field will be tied back to Skarv FPSO,” said Piotr Wozniak, president of the PGNiG management board.
Aker BP ASA operates the Skarv FPSO, in which PNGiG holds an interest.
PL 838 interests are PGNiG, 40%, and Aker BP and DEA Norge AS, 30% each.
Norwest downgrades Xanadu potential
The Norwest Energy Ltd.-operated joint venture has revised its structural model of the Xanadu oil discovery in permit TP/15 in the inshore sector of the Perth basin, Western Australia following receipt of the final processed 3D seismic data from the 40 sq km Xanadu Transition Zone survey run in July this year.
Norwest said that the fault geometry that defines the up-dip structure has changed such that the up-dip area to the north of the Xanadu-1 discovery well intersection is reduced. Consequently, commerciality of the up-dip resource is likely to be marginal. Three reservoirs in this zone have been shown to be of limited thickness and each likely to require horizontal well completion.
The company said further engineering and commercial studies are required before contingent resources can be determined and a decision made on whether future appraisal can be justified.
On a more positive note, Norwest said the area down-dip of the discovery well offers greater resource potential, but only in the ‘A’ sand and this too is regarded as relatively high risk.
The JV will now undertake further analysis to integrate the revised structural model with down-dip data acquired from Xanadu-1 to determine whether the chance of success for a down-dip appraisal well might be increased.
Norwest said there is still untapped prospective potential within and adjacent to the 3D seismic coverage to the north of the Xanadu horst and in a structural culmination to the west of the down-dip area. The JV will consider a 2D survey in this area to mature a drilling prospect.
Additional prospective resource potential is seen within the deeper Kingia/High Cliff Formations, but further work is required to quantify these prospective resources.
The original Xanadu-1 well, drilled in 2017, intersected three sandstone reservoir units with the upper ‘A’ sand interpreted as having 4.6 m of net oil pay. Oil was recovered with wireline techniques.
At that time, it was conjectured that two deeper sands (‘B’ and ‘C’) may host oil pay in an up-dip location. The 3D seismic survey was programed to test that potential, but found instead there is no evidence of a thickening of the reservoir sequence in that direction.
Norwest is operator of the Xanadu project with 25% interest. Triangle Energy has 45% and the 3C Group 30%.
Drilling & Production Quick Takes
Karoon contracts Stena Forth for Marina-1 off Peru
Karoon Energy Ltd., Melbourne, has contracted the dynamic positioning drillship Stena Forth to drill the company’s Marina-1 wildcat in the Tumbes basin offshore Peru.
The well, in Karoon’s 40% owned and operated Block Z-38, is scheduled to be spudded early in first quarter 2020. Water depth is 350 m and the well will be drilled to a TD of 3,026 m.
Marina prospect is a large fault-bounded structure with prospective reservoirs at multiple levels from 900-2,900 m subsea. The feature has a prospective resource of 256 million bbl of oil and, if successful, would de-risk a number of other prospects in the block as well as in Karoon’s 100%-owned Area 73 technical evaluation permit to the south.
Karoon said the well is a critical milestone for assessing the prospectivity of the deeper waters off northern Peru. It is the first well to be drilled in Z-38.
The Stena Forth vessel is a recently delivered harsh water drillship with capabilities to drill in far deeper water and much rougher sea states than those found off Peru.
Of Karoon’s JV partners in Z-38, Tullow Oil Ltd. has 35% interest and Pitkin Petroleum 25% (OGJ Online, May 8, 2019).
KPO lets contract for Karachaganak field
Karachaganak Petroleum Operating BV (KPO) let a contract to Fluor Corp. through its consortium with the branch of KMG Engineering LLP KazNIPImunaigas, for projects at Karachaganak field in Kazakhstan.
The value of the 3-year engineering services agreement with two potential 1-year extensions was undisclosed.
Fluor’s scope of work includes feasibility studies, front-end engineering design, and other engineering services. Fluor plans to open an office in Aksai for dedicated project personnel with scalable accommodation to meet all engineering requirements. An engineering team in Farnborough, UK, as well as global subject matter experts also will support project needs, Fluor said.
Karachaganak, covering 280 sq km, produces oil, condensates, and natural gas. Recoverable reserves are estimated at 5 billion boe. KPO—a joint venture of Shell 29.25%, Eni 29.25%, Chevron 18%, Lukoil 13.5%, and KazMunaiGas 10%—oversees the expansion and development of the field.
An expansion project contemplates the implementation, in subsequent stages, of gas treatment and reinjection plants in order to maintain the liquid production profile.
Eni starts production at Niger Delta’s Obiafu-41
Eni SPA has started natural gas and condensate production from the Obiafu-41 discovery, Niger Delta, just 3 weeks after well completion. The Obiafu-41 Deep well reached 4,374 m TD, encountering gas and condensate in the deltaic sequence of Oligocene age.
The discovery contains about 28 billion cu m of gas and 60 million bbl of condensate. The gas will largely be used in Nigeria’s domestic market to feed the power sector.
At the end of ramp-up, production will reach about 3 million cu m/day of gas and 3,000 b/d of condensate. Gas will be processed at the Eni-operated Ob-Ob plant and sent to the 500-Mw Okpai power plant, also operated by Eni. An upgrade underway at Okpai will double its capacity to 1 Gw. Once the upgrade is complete, Eni will generate 20% of Nigeria’s electricity, establishing itself as the leading producer in the country.
In Nigeria, about 30% of Eni’s gas production is supplied to the domestic market. The company plans to reduce flaring from its Nigerian operations to zero by 2025.
PROCESSING Quick Takes
Gazprom Neft progresses on Omsk refinery revamp
PJSC Gazprom Neft has received additional equipment for its project to expand delayed coking capacity at its 430,000-b/d Omsk refinery in Western Siberia as part of the operator’s second phase of its ongoing modernization program to reduce environmental impacts and improve processing capacities, conversion rates, energy efficiency, and production qualities at the site (OGJ Online, Feb. 15, 2018).
The refinery has taken delivery of 10 pieces of new high-tech equipment designed to produce components for automotive gasoline for construction of the 40,000-b/d delayed coking unit, Gazprom Neft said.
The revamped coking complex, which will reduce environmental impacts and improve refining efficiency at the site, remains on schedule to be commissioned in 2021.
Once in operation, the reconstructed delayed coking unit will enable full processing of heavy oil fractions to increase gasoline and diesel production at the refinery, as well as produce 38,700 tonnes/year of needle coke, according to the operator.
Together with other projects forming the second phase of the Omsk refinery’s modernization project, the revamped coking complex will increase the site’s conversion rate to 97% and increase light-product yield to 80%.
Gazprom Neft—which previously confirmed completion of installation of three major coking ovens, each 28.5 m long and weighing 197 tonnes—said it also will replace process heaters and secondary refining columns, as well as add an additional tank farm and automated control system, as part of the coking reconstruction project (OGJ Online, Sept. 13, 2019).
The company said its current investment in the construction and revamp project stands at more than 50 billion rubles.
As part of its first and second-phase modernization works at the site that started in 2008, Gazprom Neft has, to date, invested a total of 300 billion rubles at the Omsk refinery (OGJ Online, July 26, 2017; July 12, 2017).
ExxonMobil lets contract for UK refinery upgrade
ExxonMobil Corp. has let a contract to Fluor Corp. for a series of services related to the operator’s previously announced expansion project to increase production of ultralow-sulfur diesel by nearly 45% at affiliate Esso Petroleum Co. Ltd.’s (EPCL) 270,000-b/d Fawley refinery near Southampton, UK (OGJ Online, Sept. 20, 2018).
Following its completion of front-end engineering design for the expansion—now known as the Fawley Strategy (FAST) project—Fluor will provide engineering, procurement, fabrication, and construction on a reimbursable basis for the project, the service provider said.
Specifically, Fluor’s scope of work on the project includes design and construction of a new diesel hydrotreater and steam methane-reforming hydrogen plant as well as modifications to unidentified existing installations at the Fawley site.
With EPCL now granted planning permission from local regulatory authority the New Forest District Council Engineering, Fluor said it is currently leading engineering and procurement for the FAST project out of its Farnborough office in the UK.
Construction activities on the FAST expansion are scheduled to start by yearend.
Fluor disclosed neither a value nor duration of the contract.
The contract award follows ExxonMobil’s April final investment decision to proceed with the more than $1-billion expansion project, which intends to help reduce the need to import diesel into the UK by adding a hydrotreating unit to remove sulfur from fuel, supported by a hydrogen plant that, combined, will also help improve the refinery’s overall energy efficiency (OGJ Online, Apr. 24, 2019).
In addition to logistics improvements, the project will increase ultralow-sulfur diesel production at the site by 38,000 b/d.
Pending regulatory approval, the FAST project is targeted for start-up in 2021.
Situated on the western side of Southampton Water, the Fawley refinery—the UK’s largest—features a mile-long marine terminal that annually handles about 2,000 ship movements and 22 million tonnes of crude and other products.
TRANSPORTATION Quick Takes
Jordan Cove LNG receives final EIS
Jordan Cove LNG in Coos Bay, Ore., and the associated Pacific Connector natural gas pipeline received a final environmental impact statement (EIS) from the US Federal Energy Regulatory Commission (FERC) noting “temporary, long-term, and permanent impacts on the environment.” FERC stated that many of the impacts either were not significant or could be made less than significant with mitigation, but that others would be adverse and significant.
Specifically, the final EIS concluded that construction would temporarily, but significantly impact housing in Coos Bay; that building and operating the project would permanently and significantly impact the visual character of Coos Bay; that noise resulting from pile driving activities at the LNG plant would temporarily, but significantly impact the Coos Bay area; and that the project could have a significant impact on the Southwest Oregon Regional Airport operations. Building and operating the project also is likely to adversely affect 18 federally-listed or proposed threatened and endangered species.
The LNG plant would use five trains to liquefy up to 1.04 bcfd of natural gas for export. The roughly 200-acre plant site would include: a pipeline gas conditioning facility; five gas liquefaction trains; two full-containment LNG storage tanks and associated equipment; LNG loading platform and transfer line; and marine facilities. As proposed, the LNG plant would load about 120 LNG carriers per year.
The 229-mile, 36-in. OD pipeline would originate at interconnections with existing pipeline systems in Klamath County, Ore., and would span parts of Klamath, Jackson, Douglas, and Coos Counties, Ore., before connecting with the LNG plant, carrying up to 1.2 bcfd. It would include one compressor station.
The final EIS recommended project-specific impact avoidance, minimization, and mitigation measures in addition to those already put forward by the company.
Sempra, Mitsui sign MOU for LNG export projects
Sempra Energy and Mitsui & Co. Ltd. have signed a memorandum of understanding (MOU) for development of the Cameron LNG Phase 2 project in Louisiana and a future expansion of the Energía Costa Azul (ECA) LNG project in Baja California, Mexico.
The MOU contemplates the continued mutual support for the development of Cameron LNG Phase 2, including Mitsui’s purchase of up to one-third of the available capacity of the project, as well as the potential offtake of 1 million tonnes/year of LNG and equity participation in a future expansion of ECA LNG (OGJ Online, Nov. 5, 2018).
ECA LNG is being developed with IEnova, Sempra’s subsidiary in Mexico. Phase 1 includes one liquefaction train with an export capacity of 2.4 million tpy. ECA LNG future expansion would include additional trains with an expected export capacity of 12 million tpy.
Train 1 of Cameron LNG Phase 1 started commercial operations in August. Trains 2 and 3 are expected to begin LNG production in the first quarter and second quarter of 2020, respectively. Cameron LNG Phase 2, which has all necessary permits from the Federal Energy Regulatory Commission, encompasses up to two additional liquefaction trains and up to two additional LNG storage tanks. Mitsui is also an equity owner of Cameron LNG LLC, the development company for Cameron LNG Phase 1 and Phase 2.
Sempra LNG and Mitsui are currently working to negotiate and finalize a definitive 20-yr LNG sales-and-purchase agreement for the potential purchase of 0.8 million tpy of LNG from the ECA LNG Phase 1 project.
Development of the LNG export projects is contingent upon obtaining customer commitments, completing commercial agreements, securing permits, obtaining financing, and reaching final investment decisions, amongst other factors. The ability to complete construction projects, such as the Cameron LNG export project, is subject to risk and uncertainties.