GENERAL INTERESTQuick Takes
Apache trims upstream capital budget for 2019
Houston independent Apache Corp. reduced its preliminary upstream capital budget for 2019 by 20% but expects full-year total adjusted production to trend to the midpoint of the projected 410,000-440,000 boe/d target—a 3% drop from prior estimates.
The $2.4-billion budget—excluding planned consolidated activities of its Altus Midstream Co. partnership with Kayne Anderson Acquisition Corp.—is a substantial reduction from the preliminary $3-billion estimate, as well as from the company’s actual upstream investment level in 2018 (OGJ Online, Aug. 9, 2018).
Of the $2.4 billion, 70-75% will be allocated within the US where the company projects production growth of 12-16% and 5% Permian basin oil growth from fourth-quarter 2018 to this year’s fourth quarter. Fourth-quarter 2018 and full-year 2018 results are expected on Feb. 28.
Over the same period, Apache expects to generate production increases of 6-10% on a total company-adjusted basis, while international adjusted production is projected to be down slightly.
Canada due electric-vehicle charge network
A Suncor Energy Inc. subsidiary is building a network of fast-charging stations for electric vehicles across Canada.
More than 50 charging facilities will be installed at Petro-Canada service stations along the Trans-Canada Highway between Victoria, BC, and St. John’s, Newf.
For most electric vehicles, the equipment can provide an 80% charge in less than 30 min, Suncor said.
Construction will begin this spring. Charging stations will open over the next year.
Vintage acquires onshore Bonaparte gas permit
Vintage Energy Ltd., Adelaide, has acquired 100% and operatorship of onshore Bonaparte basin permit EP 126 in the Northern Territory from Beach Energy Ltd., also of Adelaide.
The 6,700-sq km permit stretches east from the border of Western Australia and Northern Territory to the Victoria River and contains the Cullen-1 wildcat drilled by Beach in 2014 that encountered strong natural gas shows in a thick fractured carbonate reservoir.
Cullen-1 was cased by Beach following its drilling program and is available for future testing.
Vintage Chairman Reg Nelson was managing director of Beach at the time of the Cullen project and is still keen to continue exploring the area.
The region also is known for a noncommercial gas discovery at Weaber (although this field has been excised from EP 126) as well as surface bitumen seeps and several other wells with oil and gas flows.
Vintage has undertaken initial evaluation work and has completed processing and modelling of EP 126 airborne geophysical data. This has been calibrated with data from Cullen-1.
The geophysical modelling results are being incorporated into a geological model for the area which, along with information from any future testing of Cullen-1, will guide the forthcoming exploration effort. Flow testing is planned to be the first ground activity to investigate the possibility of commercial gas flows from the well.
The existing gas pipeline from Eni SPA’s offshore Black Tip field to connect with the Northern Territory grid lies about 100 km north of Cullen-1.
An environmental management plan has been submitted to the Northern Territory Department of Primary Industries and Resources. The company is also working with the traditional landowners and other stakeholders.
Any encouragement in the test program is likely to lead to seismic acquisition and further drilling.
PetroQuest Energy emerges from bankruptcy
PetroQuest Energy Inc., Lafayette, La., emerged from bankruptcy after meeting conditions of its Chapter 11 plan of reorganization, which was confirmed by the US Bankruptcy Court for the Southern District of Texas on Jan. 31. Through the process, the company eliminated $295 million in debt and preferred equity obligations.
The company’s post-restructuring balance sheet includes $130 million of debt outstanding. The company’s current cash balance is estimated at $23 million.
The irm ended 2018 with about 130.3 bcf equivalent of estimated proved oil and gas reserves. Estimated proved reserves at Dec. 31, 2018, comprised 82% gas, 5% oil, and 13% natural gas liquids. Some 47% of the reserves were proved developed.
Exploration & DevelopmentQuick Takes
India seeks more oil, gas license appeal
Seeking to increase exploration and production, India’s Union Cabinet has approved a new round of changes in oil and gas licensing and regulation.
“Considering stagnant/declining domestic production of oil and gas, rise in import dependence, and decline in investment in E&P activities, the need to bring further policy reforms was felt,” said a statement by the Ministry of Petroleum and Natural Gas.
The government in 2016 changed terms of participation to revenue-sharing, introduced open-acreage licensing, and offered a uniform license allowing development of all forms of hydrocarbon (OGJ Online, Mar. 10, 2016).
Under the new changes, bidding for licenses in basins with no current production will be based strictly on work programs with no sharing of revenue or production with the government. Operators still will pay royalties and statutory levies.
For unallocated or unexplored areas in producing basins, bidding will be based on revenue-sharing, but work programs will receive greater weight than before. A ceiling on biddable revenue shares will prevent unviable bids. Exploration periods have been shortened, and fiscal incentives will encourage early production. License holders will be able to sell oil and gas through competitive bidding.
The new changes also grant marketing and pricing freedom to operators with gas discoveries for which field development plans have not been approved. They include fiscal incentives “on additional gas production from domestic fields over and above normal production.”
For “nomination fields” held under rights granted before license bidding began, state-owned Oil & Natural Gas Corp. and Oil India Ltd. will be required to prepare “enhanced production profile[s].” They’ll be able to form partnerships with private companies for production-enhancement projects.
And the government will adopt unspecified measures “for promoting ease of doing business,” including a new “coordination mechanism” and acceleration of approvals by the Directorate General of Hydrocarbons.
Shell Australia lets contract for Crux project
Shell Australia let a multimillion-dollar contract to global engineering groups Wood and KBR to deliver integrated front-end engineering and design for Shell’s Crux gas-condensate development project in the Browse basin off Western Australia.
The project entails a not-normally manned steel-legged platform and a 160-km gas export pipeline to connect with Shell’s Prelude floating LNG (FLNG) facilities.
Crux will be used as a source of backfill gas supply to Prelude and be remotely operated from the Prelude FLNG.
The FEED work will be carried out during the next 18 months by Wood and KBR’s engineering and project management teams in Perth and supported by Wood’s resource base in Kuala Lumpur.
The companies will provide a single integrated FEED for the Crux jacket, topsides, pipeline, subsea pipeline, and manifold.
Crux, discovered in 2000 by Nexus Energy Ltd., lies in 165 m of water about 620 km northeast of Broome. The field has estimated reserves of as much as 2 tcf of gas and 70 million bbl of condensate.
Shell has 82% and operatorship. SGH Energy Pty. Ltd. has 15%, and Osaka Gas 3%.
Joint Niger Delta gas development proceeds
A joint venture led by Shell Petroleum Development Co. has made its final investment decision for the Assa North/Ohaji South natural gas project in Nigeria’s northeastern Niger Delta (OGJ Online, Aug. 15, 2018).
Nigerian National Petroleum Corp. expects the fields to produce 600 MMscfd of gas and says a doubling of output is possible. It estimates the resource at 4.3 tcf of gas and 215 million bbl of condensate. Production is to start in the fourth quarter of 2019 or first quarter of 2020.
Assa North, on OML 21 operated by Shell, and Ohaji South, on OML 53 operated by Seplat Petroleum Development Co. of Lagos, are in communication with one another and will be developed under a 50-50 unitization agreement.
Seplat acquired its 40% interest in OML 53 in February 2015 from Chevron Corp. NNPC holds the remaining interest.
In OML 21, NNPC holds a 55% interest. Other partners besides Shell are Total Exploration & Production Nigeria and Nigeria Agip Oil Co.
In a 2015 environmental report, Shell said six exploration and appraisal wells had been drilled in the fields. It said initial development would include the drilling of six wells and construction of a gas processing plant.
McFadyen to assume exploration role at Murphy Oil
Michael K. McFadyen, executive vice-president, offshore, of Murphy Oil Corp., El Dorado, Ark., will assume responsibility for exploration following the Feb. 28 retirement of Eugene T. Coleman, executive vice-president, exploration and business development. The responsibility for business development will be assumed by David R. Looney, executive vice-president and chief financial officer.
Coleman joined Murphy in 2001 as subsea systems manager. He was named executive vice-president, offshore, in 2016 and transitioned to his current role in 2018.
Henderson named Kosmos chief exploration officer
Tracey Henderson has been named chief exploration officer of Kosmos Energy Ltd., Dallas, succeeding founding partner Brian F. Maxted, who is retiring.
A Kosmos employee since 2004, Henderson served on the technical team instrumental in the discoveries of Jubilee oil field offshore Ghana, Greater Tortue-Ahmeyim gas field off Mauritania and Senegal, and Yakaar gas field off Senegal.
Maxted will remain on the Kosmos board of directors.
Drilling & ProductionQuick Takes
Total reports record production in 2018
Total SA reported increases in adjusted net income for the fourth quarter and full year 2018 as production reached a record level for the year.
With a 10% increase from the previous quarter, Total reported adjusted net income of $3.2 billion in fourth-quarter 2018.
Production reached a rounded 2.88 million boe/d in the fourth quarter, an increase of 10% over the same quarter a year ago, due to start-ups and ramp-ups on new projects, notably Yamal LNG, Ichthys, Fort Hills, Kaombo North, and Kashagan, the company said. Liquids production was up 14% to 1.59 million b/d. Natural gas production increased 2% to 6.99 Mcfd.
For full-year 2018, Total reported adjusted net income of $13.6 billion—a 28% increase year-over-year attributed to the rise of the average oil prices to $71/bbl compared with an average of $54/bbl in 2017.
Full-year hydrocarbon production ticked upward more than 8% over 2017 levels to reach a record-high 2.78 million boe/d, Total said.
Total expects 2019 production to increase by more than 9% with ramp-ups of Kaombo North, Egina in Nigeria, and Ichthys plus the start-ups of Iara 1 in Brazil, Kaombo South in Angola, Culzean in the UK, and Johan Sverdrup in Norway. Planned projects include Mero 2 in Brazil, Tilenga and Kingfisher in Uganda, and Arctic LNG 2 in Russia.
Eni reports record oil production for 2018
Eni SPA said it achieved record production of 1.85 million b/d during 2018, up by 2.5% from 2017, while its proved reserves replacement ratio again rose above 100% for a 3-year average of 131%, the company said in an earnings statement.
Claudio Descalzi, Eni chief executive officer, said he sees more growth opportunities in the Middle East. Since March 2018, Eni has announced a series of United Arab Emirates licenses and other deals.
Eni was awarded the three blocks offered in Sharjah’s first international competitive exploration licensing round (OGJ Online, Jan. 14, 2019). Eni also has expanded with deals in Oman and Bahrain (OGJ Online, July 2, 2018).
In January Eni and OMV AG reported plans to buy interests in ADNOC Refining at prices that Abu Dhabi National Oil Co. said establishes the enterprise value of its refining subsidiary, with its 922,000-b/d of refining capacity, at $19.3 billion (OGJ Online, Jan. 28, 2019).
Horse Hill field due horizontal drilling
Horse Hill Developments Ltd. (HHDL) plans horizontal drilling this year at Horse Hill field, which is undergoing an extended production test near Gatwick Airport outside London, reports parent company UK Oil & Gas PLC.
HHDL will drill the Horse Hill-2 horizontal well into the Upper Jurassic Portland sandstone and a horizontal sidetrack into the Upper Jurassic Kimmeridge limestone in the Horse Hill-1 discovery well on PEDL 137 (OGJ Online, Oct. 27, 2016).
The company has restarted flow from a 114-ft vertical perforated Portland section in Horse Hill-1 after a 6-month shut-in. The rate is being held at a stable rate of 208-218 b/d of oil with no water, below the calculated optimum sustained rate of 362 b/d.
The Weald basin well has produced more than 5,100 bbl of Portland oil to date.
As Portland flow resumed, Kimmeridge test production in Horse Hill-1 was shut in for a further long-term pressure build-up test. The well has produced more than 30,200 bbl of 40° gravity oil from the formation with no water.
Most of the test production has been trucked to Perency’s Hamble oil terminal.
Portland test production will be switched to Horse Hill-2 when drilling of that well is complete.
Kimmeridge test production in Horse Hill-1 then will resume followed by further long-term production testing of the planned Horse Hill-1z sidetrack.
Contracts let to Maersk Drilling for offshore work
Cairn Energy let a 110-day contract to Maersk Drilling for the Maersk Developer semisubmersible rig with an option for four additional wells offshore Mexico. The contract is expected to start in September, Maersk Drilling said in a fleet update.
Elsewhere, Aker BP signed a 1-year contract for the Maersk Integrator jack up drilling rig for work offshore Norway scheduled to begin in June. Ithaca Energy signed a 120-day contract for the Maersk Resilient jack up drilling rig to drill a UK exploration well starting in April.
Off the Netherlands, Wintershall Noordzee let a 90-day contract for the Maersk Resolve jack up rig. That contract started in January. Wintershall Noordzee also let a 180-day contract for the rig plus options for another 3 months starting Sept. 1.
PROCESSINGQuick Takes
Queensland grants license for Senex’s Atlas project
Queensland has granted a petroleum facility license to Melbourne-based energy infrastructure company Jemena for the construction of a natural gas processing plant that will form part of the Atlas Pipeline project.
The Atlas project involves the delivery of gas from 100 coal seam gas wells on acreage owned by Senex Energy Ltd., Brisbane, in the Surat basin of southeast Queensland near the townships of Wandoan and Miles specifically to the domestic market. The Atlas project 2P gas reserves are estimated to be 144 petajoules.
Senex was awarded the permits in 2017. The company announced its agreement with Jemena in June 2018 in which Jemena will build, own, and operate the $140-million (Aus.) Atlas Pipeline that will span 60 km and transport about 40 terajoules/day of gas. The line will connect gas from the Senex acreage with Jemena’s existing Darling Downs pipeline and the Queensland Wallumbilla gas hub.
Jemena has already awarded a $22-million (Aus.) construction contract to Valmec Ltd. of Perth for the construction of the Atlas compression station.
The plan is for gas from Senex’s wells to be compressed at the new facility and transported to Wallumbilla for onward distribution to the Queensland domestic grid.
When granting the facility license to Jemena, Queensland Natural Resources, Mining, and Energy Minister Anthony Lynham said gas was scheduled to come on stream through the Atlas system by yearend.
Community information sessions are being held during February and early March in the Wandoan region to explain the mechanics of the project.
Contract let for Map Ta Phut petchem complex
Bangkok Synthetics Co. Ltd. has let a contract to Toyo Engineering Korea Ltd., a subsidiary of Toyo Engineering Corp., to provide engineering, procurement, and construction on two units at the operator’s existing petrochemical complex in Map Ta Phut, Rayong, Thailand.
Toyo’s scope of work on the project includes delivery of EPC services for an 80,000-tonne/year 1,3 butadiene unit as well as a 34,000-tpy butene-1 unit, the service provider said.
The new dual-unit plant is scheduled for startup in 2021.
Toyo did not disclose a value of the lump-sum turnkey contract.
This latest EPC contract for the Map Ta Phut complex follows Bangkok Synthetics’ late-2017 award to Toyo-Korea for front-end engineering design on the proposed project, Toyo said.
Bangkok Synthetics, a major C4 downstream-product manufacturer, currently produces 140,000-tpy of butadiene and 35,000-tpy of butene-1 at its existing complex.
Sonatrach lets contract for Algerian gas plants
State-owned Sonatrach has let a contract to Larsen & Toubro Ltd. subsidiary L&T Hydrocarbon Engineering (LTHE) to provide engineering, procurement, construction, and commissioning services for three central gas processing plants near to each other in southwest Algeria’s Adrar Province.
The contract specifies that LTHE will deliver EPCC for a 6-million cu m/day plant at Hassi Ba Hamou and Reg Mouaded field, a 4-million cu m/day plant at Hassi Tidjerane field, and a 4-million cu m/day plant at Tinerkouk field, Larsen & Toubro said.
Each of the central processing plant modules, which will be fabricated in-house to achieve standardization across the fields, will be equipped with separation, compression system, mercury removal, gas dehydration, and hydrocarbon dewpoint control capabilities.
Larsen & Toubro valued the lump-sum turkey EPCC contract, which also covers off-site installations and utilities for the plants, at more than 70 billion rupees.
Further details regarding the central processing sites, including timeframes for their commissioning, were not disclosed.
TRANSPORTATIONQuick Takes
Final rule issued to fortify oil train spill readiness
The US Pipeline and Hazardous Materials Safety Administration, in coordination with the Federal Railroad Administration, issued a final rule requiring railroads to develop and submit comprehensive oil spill response plans covering route segments used by high hazard flammable trains (HHFT).
The rule applies to HHFTs that are transporting crude oil in a block of 20 or more loaded tank cars and trains that have a total of 35 tank cars loaded with crude, PHMSA said on Feb. 14.
The rule revises oil spill response plan requirements currently in place to require railroads to establish geographic response zones along various rail routes and assure that both personnel and equipment are staged and prepared to respond if an accident occurs, PHMSA said.
Railroads also will have to identify a qualified individual responsible for each response zone, as well as the organization, personnel, and equipment capable of removing and mitigating a worst-case discharge, it said.
Rail carriers also will be required to provide information about HHFTs to state and tribal emergency response commissions in accordance with the 2015 Fixing America’s Surface Transportation Act, PHMSA said.
Northeast Gateway terminal sends out record LNG
Excelerate Energy LP’s Northeast Gateway Deepwater Terminal, about 13 miles offshore Boston, reported that it reached a peak send-out rate of more than 800,000 MMbtu/d of regasified LNG a week earlier. The Feb. 1 volume was a record for the facility, officials said.
Demand for natural gas from residential customers rises during the coldest days each winter in New England. Historically, during these times, gas deliverability becomes constrained, and electric power generators have been forced to use other petroleum-based fuels, they said.
The terminal, which The Woodlands, Tex.-based company commissioned in 2008, is designed to respond to local market conditions in real-time and can ramp up service to ensure energy providers meet customer demand, the company said. The high flow rate represents the average gas demand of New England power generators during recent January-February periods.
The operation was completed by two of Excelerate’s floating storage regasification units (FSRU)—Exemplar and Express—discharging in parallel through Excelerate’s proprietary offshore buoys. Excelerate said the terminal consists of a dual submerged turret-loading buoy system that allows for the connection of FSRUs that have been designed specifically to meet the challenging conditions of the North Atlantic.
In all aspects, FSRUs act like a land-based terminal and have the onboard capability to vaporize LNG and deliver gas directly to the existing subsea HubLine Pipeline operated by Enbridge Inc.’s Algonquin Gas Transmission subsidiary.
