GENERAL INTEREST Quick Takes
FERC approves four Texas liquefied natural gas export projects
The Federal Energy Regulatory Commission approved four Texas liquefied natural gas export projects, including three along the Brownsville Ship Channel and a fourth which expands a currently operating facility near Corpus Christi. The Nov. 21 approvals followed similar actions by the commission on seven other projects earlier this year, it noted.
“The commission now has completed its work on applications for 11 LNG export projects in the past nine months, helping the US expand the availability of natural gas for our global allies who need access to an efficient, affordable and environmentally friendly fuel for power generation,” Chairman Neil Chatterjee said.
FERC approved, with conditions, three Brownsville Ship Channel projects, proposed by Texas LNG Brownsville LLC; Rio Grande LNG LLC, and Rio Bravo Pipeline Co.; and Annova LNG Common Infrastructure LLC and three of its affiliates, the federal agency said.
It noted that Texas LNG Brownsville would build and operate facilities to export some 4 million tonnes/year of natural gas as LNG. The Rio Grande LNG Terminal and associated Rio Bravo Pipeline Project would export 27 million tonnes/year. The Annova LNG Brownsville Project would export up to 6 million tonnes/year
FERC also approved with conditions, a proposal by Corpus Christi Stage III LLC and Corpus Christi Liquefaction LLC to site, build, and operate the Stage 3 LNG Project that would allow the company to liquefy for export an additional 11.45 million tonnes/year at Corpus Christi Liquefaction’s LNG terminal now operating in San Patricio and Nueces counties in Texas.
All four LNG project sponsors have applications pending before the US Department of Energy seeking authorization to export gas to countries without Free Trade Agreements with the US, FERC said.
GeoPark buying Colombian operator Amerisur
GeoPark Ltd. will acquire all shares of Colombian oil and gas operator Amerisur Resources PLC for £315 million cash.
The deal includes 12 production, development, and exploration blocks in Colombia covering 2.5 million gross acres. Eleven blocks operated by Amerisur are in the Putumayo basin.
GeoPark also will acquire Amerisur’s 100% interest in the 17-km Oleoducto Binacional Amerisur (OBA) pipeline, which exports oil to Ecuador.
Production net to Amerisur’s working interest in September was 6,865 b/d of light oil from two blocks. The Platanillo block, which Amerisur operates with a 100% working interest, produced 4,503 b/d of 30º gravity oil (OGJ Online Apr. 6, 2011). The CPO-5 block, operated by ONGC Videsh with Amerisur as a 30% partner, produced 7,872 b/d of 36º-41º gravity oil from Indico and Mariposa fields.
Amerisur’s net proved and probable reserves are 12.3 million bbl of oil in the Platanillo block and 9.5 million bbl in the CPO-5 block.
The OBA pipeline, which connects the Platanillo block with an Ecuadorean system carrying oil to the port of Esmeraldas, has capacity of 50,000-70,000 b/d but is currently utilized at less than 10%. The pipeline this year began carrying third-party crude.
Houston American farms in to Colombian project
Houston American Energy Corp. (HAE) acquired a membership interest in Hupecol Meta LLC, which owns the CPO-11 block in Colombia’s Llanos basin. The 639,405-gross-acre block is comprised of the 69,128-acre Venus Exploration area, operated by Hupecol Operating Co. LLC, and 570,277 acres which was 50% farmed out by Hupecol to Parex Resources Inc., Calgary. Through its membership interest, HAE holds a 1% interest in the Venus Exploration area and a 0.5% interest in the remainder of the block.
Hupecol plans to begin drilling the Venus-1 horizontal well in the Venus Exploration area in December. Pursuant to the farmout agreement covering the balance of the block, the Daisy-1 vertical well is planned for November followed by the Montuno-1 in February 2020. Additional wells could be drilled in 2020 based on initial drilling results.
The CPO-11 covers 1,000 sq miles with multiple identified leads and prospects expected to support a multiwell drilling program, the company said. The Venus Exploration area includes an existing productive vertical well that is presently shut in. Based on analogies to adjacent Rubiales field and in order to optimize expected resource recovery and well economics, the Venue-1 well and future wells in the Venus Exploration area are currently planned as horizontal wells.
Over the last year, HAE acquired positions on two blocks in Permian basin’s Midland subbasin totaling 6,500 gross acres.
Exploration & Development Quick Takes
North Sabah development projects continue
Hibiscus Petroleum Bhd., Kuala Lumpur, reports progression on three development projects under the 2011 North Sabah Enhanced Oil Recovery Production-Sharing Contract (North Sabah PSC) offshore Malaysia.
Details were provided as part of a corporate and business update issued in conjunction with the company’s quarterly report for the period ended Sept. 30.
During the year, the company completed its first development project which involved the drilling of three infill wells in St. Joseph field (OGJ Online, July 25, 2019). The company is at the “tail-end” of its second development project which involves the drilling of three infill wells in SF30 field. Meantime, drilling activities have commenced on the company’s third development project which involves the drilling of a water injection well in SF30 field as part of a wider waterflood development strategy.
The net oil production rate from the North Sabah PSC is, as of Oct., some 6,200 b/d. In March 2018, prior to the company assuming operatorship in April, the net oil production rate was 5,700 b/d (OGJ Online, Apr. 2, 2019).
Hibiscus operates the PSC with a 50% interest, Petronas Carigali Sdn. Bhd. holds the other 50%.
Strike reports significant flow test at West Erregulla
Strike Energy Ltd., Adelaide, has completed its West Erregulla-2 appraisal well in permit EP 469 in the onshore North Perth basin of Western Australia as a future producer for the proposed Phase-1 development, which is targeting first production in 2022. The company is preparing the appraisal drilling campaign slated for the second half of 2020. Engineering and project development workstreams are progressing for a potential future investment decision.
In October, Strike reported a strong test flow from West Erregulla. The company said that 48 m of perforations across the Kingia Sandstone reservoir between 4,799 m and 4,951 m flowed at a rate of 69 MMcfd of gas through a 2-in. choke with a wellhead pressure of 700 psi. The test lasted one hour.
The flow was limited by surface equipment constraints which indicates that the Kingia reservoir has the capacity to flow at higher rates.
The test program has been designed to determine the deliverability from the well using a series of flow tests at different choke settings, rates, and wellhead pressures as well as the collection of gas samples for compositional analysis.
Strike’s managing director and chief executive officer Stuart Nicholls said the flow rate from the Kingia confirms the company’s interpretation of a high quality reservoir with excellent productivity.
He said that the result, along with significant upside in the underlying High Cliff formation and the overlying Wagina formation increases the attractiveness of West Erregulla as the company progresses towards appraisal and development.
West Erregulla-2 reached a total depth of 5,100 m making it the deepest onshore well drilled in Australia and one that has discovered the deepest ever hydrocarbons.
Strike has 50% interest and is operator. Warrego Energy holds the other 50% interest.
Tethys Oil farms in to Block 56 onshore Oman
Tethys Oil AB, through subsidiary Tethys Oil Oman Onshore Ltd., will pay up to $9.5 million in a cash and carry farm-in agreement with Biyaq Oil Field Services for 20% interest in the exploration and production license covering Block 56 onshore Oman.
Block 56 covers 5,808 sq km in southeastern Oman some 200 km south of Blocks 3 and 4. Eleven wells have been drilled on the block, three by operator Medco Arabia Ltd. All but one of the total wells drilled have encountered oil or oil shows. None have been determined to be commercial. A work program to flow test up to three wells is being prepared.
The block lies at the intersection of different geological provinces including the South Oman salt basin. It offers exploration potential in multiple play concepts, both proven and unproven, Tethys Oil said.
The initial 3-year exploration and production-sharing agreement for the block, signed in November 2014, was extended to December 2020. A second exploration phase, ending in December 2023, is optional.
Interest in Block 56, upon completion of the transaction, will be operator Medco Arabia Ltd. 50%, Intaj LLC 25%, Tethys Oil 20%, and Biyaq 5%.
Beach Energy makes gas discovery in Beharra Springs Deep
Beach Energy Ltd., Adelaide, along with 50% JV partner Mitsui E&P Australia Pty Ltd., made a new conventional gas discovery at the Beharra Springs Deep-1 well in onshore North Perth basin production license L11 in Western Australia.
Interpretation of wireline log data identified gas bearing reservoir in the Kingia Sandstone.
The well was drilled to a total depth of 4,170 m and intersected a 65 m thick reservoir at a depth of 3,935-4,000 m. Estimated gas pay is 36 m. No gas-water contact was found.
Beach, as operator, said wireline logging data indicates an average estimated porosity of 14.5% (up to a maximum of 21%) across the net pay interval.
Beharra Springs Deep-1 is 450 m from the onstream Beharra Springs gas processing facility. It is also 16 km south of the Beach JV’s successful Waitsia-4 well where the Kingia reservoir interval is comparable.
In addition, the discovery is 15 km southwest of the successful West Erregulla-2 well drilled recently by Strike Energy Ltd. and which flowed 69 MMcfd of gas during a test of the Kingia interval.
Beach will make a full assessment of the potential recoverable gas volumes following completion of wireline evaluation, gas sampling, and production testing activities.
Beach managing director Matt Kay said the Beharra Springs Deep result is a further validation of the North Perth basin’s conventional gas potential within the Kingia reservoir.
He added that the JV’s near-term plans in the region include expansion of the Waitsia Stage 1 project and making a final investment decision on Waitsia Stage 2 as well as the acquisition of the Trieste 3D seismic survey in permit EP 320 to the southeast to high grade several prospects and leads as future drilling targets.
Drilling & Production Quick Takes
CNOOC starts production at Caofeidian expansion China National Offshore Oil Co. Ltd. (CNOOC) has started production at its Caofeidian 11-1/11-6 oilfield comprehensive adjustment project in Bohai Bay.
Caofeidian 11-1/11-6 are in 20-25 m water. The output expansion project included construction of two central processing platforms and will also fully utilize existing facilities in Caofeidian oilfield, including six wellhead platforms and one floating, production, storage, and offloading (FPSO) vessel.
A total of 89 producing wells are planned with 12 wells currently producing. The project is expected to reach peak production of about 28,700 b/d in 2021.
As the operator, CNOOC holds 51% interest in Caofeidian 11-1 and 60% interest in Caofeidian 11-6. Brightoil Petroleum (Holdings) Ltd. holds 40.09% and 29.18% in the two fields respectively. SPC E&P (China) Pte. Ltd. holds the remaining interest.
Norway production increased in October, NPD says
Norway’s liquids production averaged 1.828 million b/d in October, an increase of 264,000 b/d compared to September, the Norwegian Petroleum Directorate reported Nov. 19.
The preliminary liquids total included 1.519 million b/d of oil, 279,000 b/d of natural gas liquids, and 30,000 b/d of condensate.
Oil production for October was 4.5% higher than NPD’s estimates and 2.4% higher than those for October 2018.
So far this year, oil production is about 3.2% below NPD’s forecast.
Total gas sales in October were 9.3 billion standard cu m.
Final liquids production of 1.563 million b/d in September included 1.303 million b/d of oil.
Goodnight Midstream expands Eagle Ford operations
Goodnight Midstream LLC is expanding its Eagle Ford shale operations, starting construction of Rooster saltwater disposal (SWD) to serve its expanding DeWitt County, Tex., pipeline network. Rooster SWD will be sited south of Yorktown, Tex., and will serve both piped and trucked volumes. With this addition, Goodnight’s Eagle Ford operations now include three SWD sites and 40 miles of pipeline in DeWitt and Atascosa Counties.
Upon completion of Rooster SWD, Goodnight will operate more than 500 miles of oilfield waste water pipelines and 58 saltwater disposal wells in Williston, Midland, and Delaware basins along with the Eagle Ford shale.
Goodnight is also integrating and rebranding Wyatt Water Solutions LLC under the Goodnight Midstream corporate umbrella. Goodnight purchased Wyatt Water, a provider of saltwater gathering and disposal systems, in 2017.
Goodnight began operating in Eagle Ford in 2017 when it acquired Wyatt Water.
PROCESSING Quick Takes
HollyFrontier’s Navajo refinery due new unit
HollyFrontier Corp. is building a new renewable diesel unit (RDU) at its 100,000-b/d Navajo refinery in Artesia, NM.
The RDU will have a production capacity of about 125 million gal/year, enabling the refinery and enable the refinery to process soybean oil and other renewable feedstocks into renewable diesel, HollyFrontier said.
The proposed investment will provide HollyFrontier the opportunity to meet demand for low-carbon fuels while covering the cost of the operator’s annual RIN purchase obligation under current market conditions, the company said.
HollyFrontier said it expects the RDU project, which will include corresponding rail infrastructure and storage tanks, is estimated to have a total capital cost of $350 million.
To be funded with cash on hand and anticipated to generate an internal rate of return between 20-30%, the project is scheduled to be completed during first-quarter 2022.
Contracts let for Russian ethylene project
Baltic Chemical Co. (BCC) and China National Chemical Engineering No. 7 Construction Co. Ltd. (CC7) have let contracts to McDermott International Inc. to provide technology licensing and engineering for RusGazDobycha subsidiary Baltic Chemical Complex LLC’s ethane cracking project on the Gulf of Finland near Ust-Luga, Russia (OGJ Online, Apr. 2, 2019).
McDermott’s Lummus Technology will provide both the process design package (PDP) engineering and the technology license for its olefin production and recovery technology, including Lummus Technology’s proprietary ethylene steam cracking process, for production of polymer-grade ethylene at the complex, the service provider said.
Slated to become the largest ethylene integration project in the world, the natural gas processing chemical plant will include two ethylene cracking sites, each with a capacity of 1.4 million tonnes/year, according to McDermott.
Work on the project is scheduled to begin immediately, with both the BCC and CC7 contracts—each valued at between $1-50 million—to be reflected in McDermott’s fourth-quarter 2019 backlog.
According to local news reports from China and Russia, China National Chemical Engineering Group will serve as general contractor for the more than $13-billion project, which will take 60 months to build from the start of construction.
Alongside the ethylene crackers, the project also will include six polyethylene trains with a combined processing capacity of 480,000 tpy, as well as two linear alpha olefin plants with a combined capacity of 137,000 tpy.
TRANSPORTATION Quick Takes
NuStar launches open season for Permian Crude System expansion
NuStar Energy LP has launched a binding open season for a capacity expansion of its Midland Trunkline within the NuStar Permian Crude System.
NuStar is proposing to expand the capacity of its 20-in. Midland Trunkline that runs from its Stanton Terminal to Midland Junction by adding pump upgrades at the Stanton Terminal. The expansion would offer 60,000 b/d of such expanded capacity to the EPIC pipeline at Midland Junction. Up to 90% of the expanded capacity is being offered to shippers making long-term, ship-or-pay commitments, with at least 10% available for walk-up shippers. The project is expected to be in service in first-quarter 2020.
Since its acquisition in May 2017 from Navigator Energy Services LLC, NuStar’s Permian Crude System throughput has grown by 233%. In 2019, NuStar expanded its capacity to 560,000 b/d from 460,000 b/d and added a total 34 additional well connections. NuStar moved an average of 416,000 b/d in October. With November nominations of 436,000 b/d, NuStar expects to exit 2019 with throughput around 450,000 b/d.
Shippers that execute transportation services agreements during the open season will have the option to elect priority transportation rights on the expanded capacity. The open season runs until Dec. 20.
WhiteWater reaches FID on Agua Blanca System expansion
Joint venture partners WhiteWater Midstream, Austin, and MPLX LP made a final investment decision to proceed with the expansion of the Agua Blanca Delaware basin intrastate natural gas pipeline system.
The current system consists of 90 miles of 36-in. pipeline and 70 miles of smaller diameter pipelines with a system capacity of 1.4 bcfd. The pipeline has multiple deliveries in Waha.
The expansion includes a 42-in. trunkline that more than doubles system capacity to more than 3 bcfd of gas across Culberson, Loving, Pecos, Reeves, Winkler, and Ward counties (OGJ Online, July 27, 2018). The expansion is supported by multiple 10-year, take-or-pay transportation agreements.
First Infrastructure Capital is lead investor of Agua Blanca.
PetroVietnam begins work on first LNG terminal
PetroVietnam Gas Corp. has begun construction of its 1-million tonne/year (tpy) Thi Vai LNG terminal. The company expects to put the terminal in service during 2022. Phase 1 work will include a 180,000-cu m LNG storage tank. Phase 2, tripling capacity to 3 million tpy, is expected to be complete in 2023.
Samsung C&T Corp. leads the consortium building Thi Vai LNG, joined by PetroVietnam Technical Services Corp.
Vietnam has authorized a second terminal, Son My LNG, to be built by AES Corp. and begin operations in 2024. The country plans to have 10 LNG import terminals operating by 2029.
Inpex group signs formal PSC extension for Abadi field development
Japanese company Inpex Corp. and its joint venture partner Royal Dutch Shell PLC have signed the Masela block production-sharing contract amendment, which includes a 7-year additional time allocation and a 20-year extension of the proposed Abadi LNG project. The project will be supplied with gas from Abadi field in the Indonesian portion of the Timor Sea.
The deal, which was signed with the Indonesian government, marks the execution of the formal agreement on the PSC terms made in a heads of agreement and announced in July as part of the government’s approval of the Abadi project revised plan of development.
The PSC term will now extend until 2055 and the project’s development plan has been changed from a floating LNG scheme to an onshore LNG scheme.
A project start-up date is envisaged for the latter half of the 2020s and the JV has begun preparations for the front-end engineering and design stage.
Abadi is Inpex’s first large-scale integrated LNG project in Indonesia. Abadi field, first discovered in December 2000, lies 150 km offshore Saumlaki in the Tanimbar Islands. Water depth over the field varies at 400-800 m.
Following numerous delays and changes of plan, Inpex completed a feasibility study in late 2018 for a 9.5 million tonne/year onshore plant at an undisclosed location. Additionally, there will be production of about 35,000 b/d of condensate. Total recoverable gas reserves for the field have been estimated at around 20 tcf.
Inpex is operator and holds 65% interest. Shell has the remainder.