OGJ Newsletter
GENERAL INTEREST Quick Takes
US fracturing slowdown led to DUC wells pile up
The slowdown in US hydraulic fracturing activity brought on by the COVID-19 pandemic-driven downturn has caused an inventory increase of about 750 drilled but uncompleted (DUC) wells the last 3 months, a Rystad Energy analysis of major liquid basins finds.
The backlog, which will likely increase in June, is equivalent to about 2 years of fracturing at the current pace.
“When it comes to the regional trends for the inventory of drilled wells awaiting frac services, we see a particularly strong build-up in the Permian basin where almost 500 wells were added over the past 3 months. All other major liquids basins combined saw a build-up of about 270 wells in the same period,” said Rystad Head of Shale Research Artem Abramov.
“Usually there is a typical DUC build-up during winter months and a gradual drawdown during the spring and summer months. Contrary to the norm, in the last 3 months this metric jumped to 15-25 months of frac activity. However, in the second half of 2020 we might see a modest rebound in [fracturing] without extra drilling.”
Drilled wells awaiting frac services exceeded 5,700 assets at the end of May, the highest level since at least December 2017. At the end of 2019, DUC levels were just above 5,300 assets, In February, an interim low, the number fell to just below 5,000.
The build-up since then is primarily driven by the wells that were drilled recently and are currently less than 6 months old (i.e. total depth was reached less than 6 months ago, but frac operations have not yet been started). This part of the inventory has increased from 1,651 wells at the end of 2019 to 2,970 wells now.
“In our view, this is currently the most representative part of the DUC inventory, which suggests that many recent wells are left uncompleted and will probably be carried all the way into 2021, so the industry is well positioned to boost or protect production while staying within relatively low capex levels,” Abramov said.
Norway production decreased in May, NPD says
Norway’s daily production averaged 2.029 million b/d in May, a decrease of 78,000 b/d compared to April, the Norwegian Petroleum Directorate reported.
The preliminary average daily liquids production included 1.74 b/o, 269,000 bbl of NGL, and 20,000 bbl of condensate.
Total gas sales in May were 8.2 billion standard cu m, which is 0.9 standard cu m less than April.
The update takes into account the authorities’ regulation of oil production, delayed start-up of fields under development, as well as oil production in the first quarter.
Oil production in May is 1.0% above the NPD’s forecast, and 0.7% above the forecast so far this year.
Talos Energy to operate certain newly acquired GoM shelf assets
Talos Energy Inc. will become operator of 11 of 16 selected US Gulf of Mexico shelf assets acquired in a newly-entered agreement with Castex Energy 2005 affiliates. The deal includes operatorship of 11 fields in which working interest was previously acquired in deals closed in February (OGJ Online, Dec. 11, 2019).
Castex Energy 2005 emerged from bankruptcy in 2018 and is controlled by prior first lien lenders. As of Apr. 1, and based on an early June 2020 strip price case, the assets had proved reserves of 17.6 MMboe, with over 66% classified as proved developed reserves. For the year-to-date period ended May 31, the assets had an average daily production of 6,400 boe/d (15% oil, 85% natural gas).
Among the acquired assets are multiple producing fields originally discovered and/or operated by predecessor companies led by current Talos management. The acquired assets carry de minimis plugging and abandonment obligations over the next several years.
The purchase price of $65 million is to be paid through the issuance of some 4.95 million Talos common shares and $6.5 million of cash. Closing is expected in this year’s third quarter.
In the same release, Talos noted that its borrowing base has been confirmed at $985 million following its semi-annual redetermination—a 14% reduction from the previous $1.15 billion.
Egdon, Shell advance UK offshore farm-in following license extension
Edgon Resources PLC will progress assignment of UK offshore license interests and operatorship to Shell UK Ltd. following approval by Oil & Gas Authority to extend P1929 and P2304 license terms and work obligations (OGJ Online, Jan. 21, 2020).
The initial term of the licenses will be extended to May 31, 2024, subject to fulfilling two commitments. By May 31, 2021, the companies acquire 400 sq km of 3D seismic in P1929 and P2304 or relinquish the licenses. By Nov. 30, 2022, the companies undertake to drill one well in either license to a depth of 1,700 m TVD subsea, or 75 m below the Base Permian Unconformity, or relinquish the licenses.
Following completion of the farm-in, Egdon will retain a 30% interest. Under the terms of the agreement, Shell will pay 85% of the costs of the acquisition and processing of the seismic survey covering both the Resolution and Endeavour gas discoveries. The carry on the acquisition costs will be capped at $5 million gross, beyond which Egdon would pay 30% of the survey costs. Furthermore, Shell will also pay 100% of all studies and manpower costs through to the well investment decision on the licenses.
Exploration & Development Quick Takes
Equinor, Aker BP agree to NOAKA coordinated development
Equinor ASA and Aker BP AS have agreed to coordinated development of Krafla, Fulla, and North of Alvheim (NOAKA) on the Norwegian Continental Shelf and have started preparations for submitting plans for development and operation in 2022.
Equinor is operator of the Krafla license and Aker BP is operator of the NOA and the Fulla licenses (OGJ Online, July 12, 2019).
The area, between Oseberg and Alvheim in the North Sea, consists of many licenses and complex reservoirs that contain several oil and gas discoveries with total recoverable resources estimated at more than 500 MMboe, with further exploration and appraisal potential identified, Equinor said in a release June 11.
The contemplated development concept consists of a processing platform in the south operated by Aker BP and an unmanned processing platform in the north operated by Equinor with the possibility of satellite platforms and tiebacks.
Lotos Exploration and Production Norge AS is a partner in the licenses.
King’s Quay project selects umbilical supplier
Murphy Exploration and Production Co. – USA’s King Quay development in the US Gulf of Mexico will receive umbilicals through a contract by Subsea 7 to Aker Solutions.
The work scope includes 22 km of dynamic steel-tube umbilicals and distribution equipment to connect the King’s Quay floating production system to Samurai and Khaleesi-Mormont deepwater developments (OGJ Online, Mar. 3, 2020).
The King’s Quay host facility lies 175 miles south of New Orleans in the Green Canyon area (OGJ Online, Dec. 12, 2019).
The engineering, design, and manufacturing of the umbilicals and distribution equipment will take place at Aker Solutions’ facility in Mobile, Alabama. Work starts immediately, with delivery expected in fourth-quarter 2021.
Trillion plans gas production increase offshore Turkey
Trillion Energy International Inc. is formulating a comprehensive re-development program for South Akcakoca Gas-Basin (SASB) gas fields in the Black Sea to increase production levels by accessing additional proven gas reserves.
The company conducted operations to extend the life of the Phase I and II wells by lowering producing pressure to increase gas production, which resulted in a 50% production increase (555,000 cfd increase) to 1.517 MMcfd.
SASB gas field wells first started production between 2007 and 2011 and have produced a total of 41.66 bcf to date, an average of 4.166 bcf/well. The company recently completed a forecast for total economic recovery per well of 5.814 bcf for the 10 production wells drilled during Phases I and II development. Production from Phase I and II peaked in 2011 at 6.5 bcf/year and now currently produce 40 MMcf/year.
SASB consists of 23 shallow water wells, four offshore platforms, related pipelines and a gas processing plant for a to-date total development cost of $608 million.
The natural gas is produced from Eocene age sandstone reservoirs at subsea depths of 1,100-1,800 m in each of the wells. The wells are shallow water in less than 100 m depth. The 12,385-hectare SASB development license is 100% covered by 3D seismic.
Phase I development included partial development of the three nearer shore gas fields, Ayazli (discovered in 2004), Dogu Ayazli (discovered 2006), and Akkaya (discovered in 2005), with first gas in 2007. A total of 17 wells were drilled in Phase I to an average depth of 1,500 m subsea.
Phase II consisted of the deeper water Akcakoca field (discovered in 2006) which was developed with Phase II gas production coming online in 2011. Six wells were drilled and one platform was constructed during the phase.
In total, an 82% success rate occurred in drilling the wells for Phase I and II and finding gas based on the 3D seismic. Several prospects and field extensions were identified by 3D seismic, however, were not drilled at the time.
Trillion Energy is a 49% owner of SASB natural gas field.
Drilling & Production Quick Takes
CNOOC starts production from Qinhuangdao 33-1S, Bohai Bay
Production from Qinhuangdao 33-1S oilfield, Phase I, in Bohai Bay has begun, operator CNOOC Ltd. said in a release June 11.
The project, in water depths of 21 m, is one of 10 new projects expected to come on stream this year (OGJ Online, Jan. 13, 2020). One wellhead platform has been built, and existing facilities of Qinhuangdao 33-1 and Qinhuangdao 32-6 will be utilized. Thirteen wells, (9 production, 4 water injection) are planned. Peak production of about 6,000 b/d of crude is expected in 2021.
CNOOC is operator of Qinhuangdao 33-1S with 100% interest.
Senex completes Surat gas development project
Senex Energy Ltd., Brisbane, has completed its 100%-owned Surat basin natural gas development.
The onshore southeast Queensland project comprises 80 gas wells which is less than the 110 wells originally envisaged because of continuing outperformance.
In conjunction with infrastructure partner Jemena, the group also has built and commissioned natural gas processing facilities at Roma North and Atlas capable of handling more than 20 petajoules/year of gas (OGJ Online, June 19, 2018; Oct. 8, 2019).
Final investment decision for the $400-million (Aus.) project was reached in October 2018 and drilling and construction completed in less than 2 years.
Roma North has been consistently producing above nameplate capacity at around 18 terajoules/day while the Atlas coal seam gas production has exceeded 15 terajoules/day and continues to increase towards its nameplate capacity of 32 terajoules/day. Atlas also has an additional 8 terajoules/day of installed capacity available.
The initial water treatment facilities at Atlas have been commissioned and final construction completion is expected in the second half of this year.
The company has proved and probable (2P) gas reserves in excess of 600 petajoules in its Surat basin permits and expects to supply the domestic market in Eastern Australia for decades to come.
PROCESSING Quick Takes
ExxonMobil lets contract for NOx-reducing technology
ExxonMobil Corp. has let a contract to ClearSign Technologies Corp. to provide its proprietary nitrogen oxide (NOx)-reduction technology at its 561,000-b/d integrated refining and petrochemical complex in Baytown, Tex.
As part of the contract, ClearSign will fabricate and install a multiburner process heater and burners equipped with its ClearSign Core NOx-reduction technology at the Baytown refinery as part of a final step in validating the technology’s effectiveness at improving energy, operational efficiency, and safety while simultaneously reducing NOx emissions, the service provider said.
The Baytown refinery installation order follows ExxonMobil’s previous order with ClearSign for early engineering and installation planning regarding a trial installation of ClearSign Core process burners at one of ExxonMobil’s US Gulf Coast refineries in 2019 following testing of the technology that involved evaluation of its application over a broad range of typical conditions—including variations in fuel heating values, turndown, and excess air—at ClearSign’s research and development site in Seattle, Wash., according to an Oct. 18, 2019, release from ClearSign.
ClearSign disclosed neither a value of the order nor a timeframe for the technology’s implementation at the Baytown complex.
Retrofittable for crude heaters, vacuum heaters, hot-oil and heat-medium heaters, regeneration gas heaters, reactor-feed heaters, reboiler heaters, reformers, and delayed cokers, ClearSign Core process burner technology has been implemented as part of a retrofit installation of five ClearSign Plug & Play burners on a process heater in a California refinery to demonstrate the technology as a best available control technology (BACT) candidate for the South Coast Air Quality Management District and the refiner, according to Jan. 31, 2020, and Feb. 18, 2019, releases from ClearSign.
Based on preliminary estimates, if successful, ClearSign said it expects the California refinery implementation to reduce the refinery’s current NOx emissions by more than 15 tonnes without the use of catalysts, chemicals, utility consumption, or other inefficient requirements of established technologies.
Russian LNG, LPG, petchem complex signs gas supply agreement
Gazprom and RusKhimAlyans signed 20-year commercial contracts for supplies of feed gas and sales gas for the planned gas processing, liquefaction, and chemical complex on the Gulf of Finland near Ust-Luga seaport, Leningrad Oblast, Russia. RusKhimAlyans is operator of the planned complex and a joint venture of Gazprom and RusGasDobycha. Planned liquefaction capacity is 13 million tonnes/year (tpy).
Gazprom will supply 45 billion cu m/year (bcmy) of wet natural gas from its Achimov and Valanginian deposits in the Nadym-Pur-Taz region of the Yamal Peninsula to RusKhimAlyans. Gas remaining after processing (including ethane extraction) and LNG production, about 18 bcmy, will go into Russia’s gas transmission system. The complex will produce as much as 4 million tpy of ethane, and more than 2.2 million tpy of LPG.
While LNG and LPG produced at the complex will be exported, ethane from the site will feed nearby RusGazDobycha subsidiary Baltic Chemical Complex LLC’s (BCC) proposed $13-billion ethane cracking project, which—once in operation—will produce more than 3 million tpy of polymers (OGJ Online, Nov. 18, 2019).
RusKhimAlyans also entered into an engineering, procurement, and construction (EPC) contract with Nipigaz (part of the Sibur Group) for the integrated complex’s gas processing. Nipigaz previously completed a set of engineering surveys and developed basic technical solutions for RusKhimAlyans under at contract signed September 2019. Design documentation is now being drafted for the gas processing facilities.
RusKhimAlyans will later select EPC contractors for the liquefaction plant, storage of both raw material and finished products, a marine shipment terminal, and other nonproduction infrastructure. An EPC management contractor will be chosen to carry out integrated management of the construction across the complex.
RusKhimAlyans also signed a 20-year contract to supply ethane to BCC.
Viva to turn Geelong oil refinery into energy hub
Viva Energy, owner of the Geelong oil refinery 50 km west of Melbourne, plans to turn the facility into a 235-hectare energy hub that includes an LNG reception terminal and solar farm. It will retain the existing refining operations.
The LNG terminal would bring in natural gas from other parts of Australia and overseas. It is the second such project earmarked for Victoria with AGL, Sydney, looking to establish a floating LNG import terminal in Western Port Bay south of Melbourne.
The LNG import project is at pre-front-end engineering and design stage. Viva plans to begin assessing interest from potential partners for gas supplies, gas demand, power generation and LNG floating storage management and will consider associated projects like gas-to-power, LNG for transport, and gas-to-hydrogen.
No indications on a possible size or cost of a Geelong LNG import terminal have been given.
Viva said there was also potential to develop a 27 Mw solar photovoltaic and battery storage plant on the site.
The 128,000-b/d refinery, originally built by Royal Dutch Shell in 1954, supplies about 10% of Australia’s liquid fuel demand, but has struggled with falling demand due to COVID-19 lockdowns and is likely to post a loss of more than $40 million (Aus.) for the first half of the year.
Major maintenance works at the refinery between July and November will proceed, but some works will be delayed until 2021.
TRANSPORTATION Quick Takes
Energean completes Karish sales gas pipelay
Energean PLC has completed installation of the sales gas export pipeline and main deepwater production systems in the Karish and Tanin development project, offshore Israel. Karish development is now 80% complete, according to Energean.
TechnipFMC completed core installation of 90.3 km of 30- and 24-in. OD pipeline at depths as much as 1,700 m using Allseas’ Solitaire pipelay vessel. Construction support vessel Normand Cutter completed installation of the production manifold and subsea isolation valve foundations and structures. The company expects full pipeline installation, including a tie-in manifold and precommissioning, to be completed fourth-quarter 2020.
Installation of three sets of risers (two 10-in. OD and one 16-in. OD) that will connect the development’s three producing wells to the 8-billion cu m/year Energean Power floating production vessel and then the sales gas pipeline are expected to begin fourth-quarter 2020 and be completed first-quarter 2021.
Karish lies in the Alon C license in 5,700 ft of water. It was discovered in May 2013 and drilled to a depth of 15,783 ft, encountering 184 ft of net gas pay in high-quality lower Miocene sands with 0.9 tcf confirmed reserves.
Mountain Valley gas pipeline to enter service early-2021
Mountain Valley Pipeline LLC plans to place its 303-mile natural gas transmission pipeline in service early-2021. The project, to be operated by EQM Midstream Partners LP, is 92% complete.
Mountain Valley’s three compressor stations are 100% complete and its three original certificated interconnects are 100% complete with a fourth approved for construction in 2020. About 80% of the pipeline work is complete including 264 miles of 42-in. OD pipe welded and in place and restoration of 50% of the right-of-way.
The pipeline will carry 2 bcfd of Marcellus and Utica shale production from northwestern West Virginia to southern Virginia.
The US Federal Energy Regulatory Commission in October 2019 issued a stop-work order on the project, pending completion of a biological opinion. Mountain Valley has been working on environmental stabilization and restoration in the meantime as well as maintenance of existing erosion and sediment controls.
Mountain Valley said the 2021 in-service date includes continued timing uncertainty regarding permits for a 3.7-mile crossing of the Jefferson National Forest and Appalachian Trail and waterbody crossings totaling about 10 miles.
The company projects a 5% cost increase above the $5.4 billion estimated.
Mountain Valley Pipeline LLC is a joint venture of EQM Midstream, NextEra Capital Holdings Inc., Con Edison Transmission Inc., WGL Midstream, Inc., and RGC Midstream LLC.
Williams, LLOG enter tieback deal for Taggart development
Williams and LLOG Exploration Offshore LLC entered a tieback agreement for offshore natural gas and oil gathering and production handling services for the Taggart development at Williams’ Devils Tower Spar, which lies 140 miles southeast of New Orleans in the Mississippi Canyon area of the Gulf of Mexico. Williams also will provide onshore gas treatment and processing services.
Williams will gather Taggart crude and natural gas production through its Mountaineer and Canyon Chief pipeline systems. Natural gas will be delivered to Williams’ Mobile Bay processing plant, and the natural gas liquids will be fractionated and marketed at the Baton Rouge fractionator (Williams 33% owner) in Louisiana.
Taggart is expected to come online in early 2022, and the reserves are expected to produce some 27 million bbl over 8 years.