December 2018, Vol. 245, No. 12
Projects
Projects
Valley Crossing Pipeline to Mexico Gains FERC Extension
The Federal Energy Regulatory Commission (FERC) awarded Enbridge subsidiary Valley Crossing Pipeline six additional months to connect its natural gas pipeline to its counterpart in Mexico, moving the deadline to April 23.
The 168-mile pipeline, expected to have been operational in October, was delayed by rough seas on the Mexican side of the project. When completed, it will transport 2.6 Bcf/d from the Eagle Ford Shale of South Texas to power plants in Mexico.
From the Agua Dulce natural gas hub outside of Corpus Christi, Texas, the project heads south to the Port of Brownsville, then enters the Gulf of Mexico before crossing the border.
TransCanada is building the underwater pipeline from Tuxpan, Veracruz, which will join the Valley Crossing Pipeline at the border.
Valley Crossing said it is in discussions with a number of potential end users, such as local distribution companies and power plants to install delivery points along the pipeline.
Crude Oil Service to Begin on Epic NGL Pipeline in 2019
Epic Midstream Holdings obtained all required approvals for subsidiary Epic Crude Oil Pipeline, through a lease arrangement to begin crude oil service on a portion of the Epic NGL Pipeline, once construction is completed in the third quarter of 2019.
Because of high customer demand for crude oil transportation, EPIC said it made the decision to use the third and final phase of its Epic NGL Pipeline from Crane, Texas, to Corpus Christi for crude oil service, while its crude oil pipeline and NGL fractionator remain under construction. The NGL Pipeline will convert back to NGL service by January 2020.
The portion of the NGL line being placed into crude service will originate in Crane with an additional injection point in Wink, Texas, and will have multiple terminal and refinery connections in Corpus Christi and Ingleside.
The 24-inch NGL line will have a capacity of 400,000 bpd for its interim crude service. The construction of the final phase of the EPIC NGL Pipeline is progressing on time, with three contractors working on the project over five spreads of the pipeline path.
Due to demand, EPIC will increase the size of its pipeline from a 24-inch line to a 30-inch line, expanding its Permian Basin capacity to 600,000 bpd. With the installation of additional pumps and storage, EPIC can increase the 30-inch capacity to 900,000 bpd.
The EPIC Crude Oil Pipeline will run alongside the EPIC NGL Pipeline with expected completion by January 2020.
Salt Creek, Noble Midstream to Partner on Delaware Basin Project
Salt Creek Midstream and Noble Midstream Partners have agreed to form a joint venture to build a new 200,000 bpd crude oil pipeline and gathering system in the Delaware Basin in West Texas.
The 95-mile, 20-inch pipeline system will originate in Pecos County with additional connections in Reeves and Winkler counties, providing shippers with access to multiple downstream outlets. Salt Creek and Noble Midstream expect to execute definitive agreements and closing of the transaction by year-end, the companies said.
Salt Creek said it has already commenced construction of the pipeline, with an expected operational date in the second quarter of 2019.
The project provides access to 200,000 barrels of new crude oil storage with expansion potential to 300,000 barrels. Its development is supported by an average customer acreage dedication term of about 15 years, Salt Creek said.
The project is underpinned by 180,000 dedicated acreage from the venture partners and five other Southern Delaware Basin producers, with available dedications of another 100,000 acres. It includes in-field crude gathering lines and a trunkline to Wink Hub that will provide downstream connectivity for producers in the Southern Delaware Basin.
Energy Transfer Considers Boosting Dakota Access Capacity
Dakota Access pipeline developer Energy Transfer Partners is gauging shippers’ interest in a possible expansion of the volume of crude oil moved through the pipeline from 500,000 bpd to 570,000 bpd, despite ongoing tribal efforts to shut the pipeline down.
The Texas-based company began seeking commitments from shippers to transport additional oil recently. The pipeline’s permit in North Dakota allows it to ship up to 600,000 bpd. North Dakota produced nearly 1.3 MMbpd in August, the most recent month for which data is available.
Company spokeswoman Vicki Granado told The Bismarck Tribune that an expansion would require minimal modifications to the actual pipeline system. Companies can increase pipeline capacity by adding a chemical to make oil flow more easily, or by adding more pumping power or pumping stations.
The pipeline has been moving North Dakota oil through South Dakota and Iowa to a shipping point in Illinois since June 2017. From there it is transported to the Gulf Coast through the Energy Transfer Crude Oil Pipeline, which ends at Nederland, Texas.
Despite the work stoppage in the area affected by the ruling, construction on other phases of the project has continued despite heavy rains and the threat of further court challenges.
Regulator Ties Pipeline Work to Deadly Massachusetts Gas Explosion
A NiSource affiliate failed to require contract repair crews to relocate pressure sensors during natural-gas pipeline work, the National Transportation Safety Board (NTSB) said, resulting in over-pressured lines that caused explosions and fires in three Massachusetts communities.
Gas poured through Columbia Gas Co of Massachusetts’ distribution system in Lawrence, North Andover and Andover, flooding into homes and businesses and sparking explosions and fires that killed one person and injured 21.
Critical valves controlling the gas flow were not shut for nearly 3 1/2 hours after the first alarm was raised at Columbia Gas’ monitoring center, NTSB said in a preliminary report. The center had no ability to remotely open or close valves on its own, but did notify technicians, it added.
Crews were working for Columbia Gas in Lawrence, a city northwest of Boston, to replace an aged cast-iron main with a new plastic distribution main line. The abandoned main had regulator sensing lines used to detect pressure in the system, the NTSB report said.
After that main line was disconnected, the sensing lines lost pressure and the regulators fully opened, “allowing the full flow of high-pressure gas into the distribution system supplying the neighborhood,” the report said.
Columbia Gas had approved a “work package (that) did not account for the location of the sensing lines or require their relocation to ensure the regulators were sensing actual system pressure,” according to the NTSB.
Minutes before the explosion, Columbia Gas’ monitoring center in Columbus, Ohio, received high-pressure alarms for its South Lawrence gas pressure system. The company shut down the regulator at issue about 25 minutes later, at about 4:30 p.m., the NTSB said.
The explosions and fires in September damaged 131 homes and businesses as Columbia Gas was replacing cast-iron pipe with safer plastic lines when the accident occurred. It was the largest U.S. natural gas pipeline accident since 2010 in terms of structures involved.
Argentina’s YPF to Spend Billions on Infrastructure, Production
Argentina’s state oil company, YPF, will significantly boost oil and gas production and infrastructure expansion, investing between $4 billion and $5 billion per year through 2022, Chief Executive Daniel Gonzalez told Reuters.
It plans to raise production by between 5% and 7% per year, primarily in the Vaca Muerta shale, and invest $3.6 billion on infrastructure in the Vaca Muerta over the next five years.
The Vaca Muerta formation is one of the world’s largest reserves of shale oil and gas, and Argentina has offered financial incentives to help spur development. The initiatives, put in place in late 2015, include a labor agreement designed to attract midstream service providers to the region.
YPF is the leading investor in the Vaca Muerta, but its strategy calls for a broader expansion. With plans to begin exporting gas to Chile, YPF said it will increase offshore exploration in Argentina’s Gulf of San Jorge, on the southern Atlantic coast.
Australian AGL LNG Import Project Slowed by Environment Review
Plans by Australian company AGL Energy to start importing LNG from 2021 will be delayed after the state of Victoria called for the company and its pipeline partner to submit a full environmental assessment of their project, according to Reuters.
The review process typically takes nine to 12 months, which means AGL will not be able to reach a final investment decision on the $178 million (A$250 million) jetty project by June 2019, as it had hoped.
AGL had been on track to be the first of four proposed LNG import projects looking to fill an expected gas supply shortfall in southeastern Australia from 2021.
AGL declined to comment on how the environmental review would affect the project’s timing but said it was committed to working with the community and following all state and regulatory assessment requirements.
The state’s move follows protests in the community around the Western Port location where AGL plans to build a jetty to park a ship that would regasify imported LNG and hook it up to a new gas pipeline to be built by APA Group.
Aspen to Construct Residue Gas Pipeline in Austin Chalk
Aspen Midstream is constructing a large-diameter residue pipeline, and both a lean and a rich gas gathering system in the Austin Chalk play in Texas. Producers drilling in the Giddings Field are developing multiple stacked pay zones, including the Austin Chalk and Eagle Ford Shale formations.
The initial system will consist of more than 90 miles of 10- to 20-inch gas gathering mainlines, treating facilities, a cryogenic processing plant with the capacity to process 200 MMcf/d of natural gas, and a residue gas pipeline to the market hub at Katy, Texas, the company said.
The system is supported by about 150,000 acres of long-term dedications from multiple producers, and Aspen said it is in discussions with other producers about additional dedications. The system is expected to be in service by the third quarter of 2019.
Funding Secured for Permian-to-Gulf Coast Crude Oil Pipeline
Midstream company Jupiter secured a funding commitment from Charon System Advisors that would enable it to build the 1MMbpd capacity Jupiter Pipeline from the Permian Basin to the Port of Brownsville, Texas.
In addition to the Jupiter Pipeline, the company said it is constructing a crude upgrading, processing and export terminal capable of loading VLCCs on 270 acres of land located in the Port of Brownsville, Jupiter said.
Expected to be operational late in the third quarter of 2020 and originating near Midland, Pecos and Crane, the pipeline will have offtake points near Three Rivers, Texas.
Jupiter has completed engineering, design, and right-of-way planning for the pipeline, the company said. As designed, it will be the only pipeline out of the Permian Basin that can access all three deep water ports in Texas (Houston, Corpus Christi and Brownsville) and will have direct access to a fully capable very large crude carriers (VLCC) loading facility. P&GJ
Correction:
The item “Targa Signs Letter to Build Whistler Pipeline Project,” which appeared in the September 2018 edition of P&GJ, failed to credit the accompanying map to RBN Energy. Additionally, RBN Energy should have been credited for supplying a portion of the item’s content.
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