OGJ Newsletter

GENERAL INTEREST Quick Takes

Appellate court halts Dakota Access pipeline shutdown order for review

A federal appeals court July 14 temporarily blocked a shutdown order issued for the Dakota Access crude oil pipeline.

The US Court of Appeals for the District of Columbia Circuit issued the administrative stay to give the court more time to consider an emergency motion for a longer stay, one that might remain in place until the case is resolved.

The appellate court gave parties in the case a deadline of July 20 for filing arguments against the stay and July 23 for filing replies to those arguments.

The pipeline, operated by Energy Transfer LP, carries 570,000 b/d of crude oil more than 1,000 miles from North Dakota to a pipeline hub at Patoka, Ill. Connections there allow the oil to flow as far as the Gulf Coast.

Judge James Boasberg of the US District Court for the District of Columbia ordered July 6 that the Dakota Access crude oil pipeline must be shut down and emptied of oil by Aug. 5 pending completion of a study of the line’s potential environmental impacts. The line has been in operation for 3 years (OGJ Online, July 6, 2020).

The US Army Corps of Engineers has told the court it can complete an environmental impact statement on the pipeline—specifically on an easement allowing the line to pass under the Missouri River in North Dakota—in 13 months.

The case is Standing Rock v. US Army Corps of Engineers. While the Corps of Engineers is the primary defendant, Energy Transfer is an intervenor defendant.

Sanchez emerges from Chapter 11 as Mesquite Energy  

Sanchez Energy Corp. has emerged from its financial restructuring and emerged from Chapter 11 as privately held Mesquite Energy Inc. With the restructuring and pursuant to the plan of reorganization, the company eliminated substantially all its $2.3 billion debt.

Cameron W. George will serve as interim chief executive officer, executive vice-president, and chief financial officer of the company. George served as executive vice-president and chief financial officer of Sanchez Energy. Prior, he was a member of the founding team at Linn Energy.

The Houston-based company and certain of its subsidiaries voluntarily filed for reorganization under Chapter 11 of the US Bankruptcy Code in the US Bankruptcy Court for the Southern District of Texas in August 2019 (OGJ Online, Aug. 12, 2019).

Talos given deadline for Zama field unitization plans  

Talos Energy Inc. along with Block 7 partners and Petróleos Mexicanos (Pemex) have 120 working days to submit a Unitization and Unit Operating Agreement to Mexico’s Ministry of Energy (SENER) that will serve as the governing document of a unitized consortium over the life of Zama field offshore Mexico’s Sureste basin.

Talos is operator of Block 7 in a partnership with Wintershall DEA and Premier Oil. Zama field extends from Block 7 into the neighboring block to the east, which is operated by Pemex. Constitution of a formal unit is required prior to final investment decision and field development (OGJ Online, Jan. 7, 2020). Official instruction to unitize was given to Talos by SENER on July 7.

The UUOA will address such topics as initial participating interests, roles of the parties, and reimbursement of exploration and appraisal costs spent to date, as well as a redetermination mechanism for adjusting the initial participating interests as additional technical data is collected.

Pre-FEED has been completed, and early FEED work has begun to develop the detailed engineering plans for Zama. Development will include two fixed production facilities capable of handling a combined 150,000 b/d of oil, plus associated gas. In 550 ft of water, the platforms would be the deepest facilities ever installed in Mexico, Talos said.

Exploration & Development Quick Takes 

Equinor tests middle Jurassic rocks near Vigdis Vest 

Equinor Energy AS drilled a wildcat in North Sea production license 089 to prove petroleum reserves from middle Jurassic age rocks in the Rannoch formation. The license partners so far presume the discovery commercial and are considering tie-in to Vigdis field. A preliminary estimate places the size of the discovery at 0.9-1.5 million standard cu m recoverable oil.

Well 34/7-E-4 AH—a shallow sidetrack from existing development well 34/7-E-4 H and the 41st exploration well on the license—was drilled 160 km west of Florø, just northwest of Vigdis Vest field, by the Transocean Norge drilling facility in 283 m of water to a vertical depth of 2,517 m subsea and a measured depth of 4,459 m (OGJ Online, Mar. 16, 2020).

The well terminated in the Rannoch formation and encountered an oil column of about 20 m, 18 m of which are good reservoir-quality sandstone. Oil-water contact was encountered at 2,479 m. Data acquisition and sampling were carried out, but the formation was not tested. The reservoir section will be temporarily plugged back.

Equinor Energy AS is operator with 41.5% interest. Partners are Petoro AS, 30%; Vår Energi AS, 16.1%; Idemitsu Petroleum Norge AS, 9.6%; and Wintershall Dea Norge AS, 2.8%.

MOL makes gas, condensate discovery in TAL Block, Pakistan    

A new gas and condensate discovery in TAL Block in Pakistan’s Khyber Pakhtunkhwa province de-risks an exploration play in deeper reservoir, operator MOL said July 14. The discovery is MOL’s 13th in Pakistan and the 10th discovery in the block.

The Mamikhel South-1 exploratory well reached a total depth of 4,939 m on May 23. Upon testing the well flowed gas and condensate from Lockhart & Hangu formation at a flow rate of 6,516 boe/d (16.12 MMscfd and 3,240 b/d, respectively), with flowing well-head pressure of 4,476 psi at 32/64-in. choke. Further testing of the well is ongoing.  

MOL is responsible for 89,000 boe/d gross production from the block as of first-quarter 2020.

MOL is operator of the block with 8.4% interest. Partners are Pakistan Oil & Gas Development Co. (OGDC), Pakistan Petroleum Ltd. (PPL), POL, and Government Holdings (Pvt.) Ltd.

ADX Energy prepares Romania well flow test  

ADX Energy Ltd., Perth, has completed workover rig mobilization and set-up at its lecea Mica-1 (IMIC-1) gas well onshore Romania in preparation for a flow test.

The initial test will use underbalanced perforation to maximize inflow and clean up to enable maximum well productivity.

The well lies in the lecea Mare production license in the central eastern part of the country 10 km from the border with Serbia.

During drilling the IMIC-1 well encountered gas across three zones before being suspended for future completion as a production well, pending test results. Initial estimates suggest a total 2C contingent resource of 20 bcf.

ADX said testing will concentrate on the PA 1V Pliocene-age sand which is a proven reservoir and has the greatest upside potential of the three zones.

The program will determine the production capacity using multiple flow rate measurements and pressure build-up response times. The produced gas will be sampled to determine its suitability for commercial sale.

Mudlog data, along with nearby analogues, indicate IMIC-1 contains dry gas that will require minimal processing.

Ongoing gas commercialization studies are looking at two development options, including the delivery of sales gas to the Romanian grid near the Satchinez-Calacea gas plant or, alternatively, the use of gas to generate electricity for connection into a high-voltage power line 2 km from the well site.

Following the test program, the resource potential of all three gas reservoirs in the well will be further assessed using high resolution 2D seismic data that is to be acquired across the IMIC-1 and potential IMIC-2 accumulations.

The 2D seismic will be acquired in conjunction with a planned 3D seismic program during this year’s third quarter in the surrounding region.

ADX holds a 49% of Danube Petroleum Ltd., which holds 100% interest in the lecea Mare production license. The remaining shareholding in Danube is held by Reabold Resources PLC.

Drilling & Production Quick Takes 

Petrobras: New concept reduces postsalt well construction time, costs by half 

Petrobras completed offshore well 7 GLF 49H ESS in early July in half the historical time and for half the cost using the True One Trip Ultra Slender (TOTUS) concept. Pioneering use of TOTUS resulted in a 44-day well completion time compared to the historical average of 96 days for the field. Cost reduction was about 50%, equivalent to $30 million, Petrobras said.

The well, in Golfinho field, Espírito Santo basin, 100 km from Vitória, is the first postsalt well built with TOTUS, which consists of simplifying and reducing time on drilling and completion stages based on optimizations and innovations inserted in the design and planning phases, the operator said.

TOTUS, developed and patented by Petrobras, consists of drilling the well in only three phases (Ultra Slender) compared to four or five phases in conventional drilling, and a one-trip completion system (True One Trip) instead of two or more maneuvers for conventional completions. The technique can be used in certain mature fields of the postsalt where geological and reservoir characteristics favor its application. Petrobras said it can apply the concept in new wells drilled in 2021-2025 with potential cost reductions of $20-35 million per well.

Baker Hughes: International rig count down 24 units in June  

The international rig count for June reached 781, a decrease of 24 units from May and down 357 units from the 1,138 counted in June 2019, according to Baker Hughes data.

The international offshore rig count for June was 194, down 1 unit from May, and down 52 units from the 246 counted in June 2019.

The worldwide rig count for June was 1,073, down 103 units from the 1,176 counted in May, and down 1,148 units from the 2,221 counted in June 2019.

The average US rig count for June was 274, down 74 from May, and down 695 from the 969 counted in June 2019.

Europe was down 1 unit with 110 in June and down 83 units year-over-year. Effective June 7, 2019, Ukraine has been added to the Baker Hughes International Rig Count.

Latin America is up 9 units from the previous month with 71 units and down 118 units year-over-year.

The Asia-Pacific region is up 1 with 197 units month-over-month and down 30 units from its year-ago average.

The Middle East is down 32 units month-over-month at 343 and down 70 units year-over-year.

The average Canadian rig count for June was 18, down 5 units from the 23 counted in May, and down 96 units from the 114 counted in June 2019.

License awards move Mahalo gas project toward production  

The Comet Ridge Ltd. group’s Mahalo coal seam gas project in the Denison Trough in central Queensland has been granted two covering production licences by the Queensland government.

PLs 1082 and 1083, in the northern part of exploration permit ATP 1191, have been issued for a term of 30 years. The award is the final regulatory approval required for the project to move into production. Environmental approval was granted in June.

The group comprises Comet Ridge, Brisbane, with 40%, Santos Ltd. with 30%, and Australia Pacific LNG (operated by Origin Energy) 30%.

Comet Ridge farmed into the area and began coal seam gas exploration in 2004 targeting thin Bowen basin Permian-age coal seams known collectively as the Bandanna Coal Measures.

A number of shallow wells proved the extent and gas content of the coal seams. A four-well pilot scheme began in 2012 and the Mahalo 6/7 vertical-horizontal well was successfully drilled in 2017.

The project has estimated 2P gas reserves of 172 petajoules. In Phase 1 development, 20 wells are expected to produce around 20 petajoules/year through the nearby Denison Trough pipeline infrastructure that feeds the Curtis Island LNG plants near Gladstone as well as the Queensland domestic gas grid.

Comet Ridge is also working to prove up resources in its 100%-owned Mahalo North project in exploration permit ATP 2048. The plans include seismic interpretation to optimize drilling locations so the resource can be quickly tied into Mahalo or other nearby gas processing and pipeline facilities.

PROCESSING Quick Takes 

Grassroots LSFO refinery planned for Oman  

Canada Business Holdings Inc. (CBH), Ottawa, Ont., is moving ahead with an investment plan to develop a project for construction of a new low-sulfur fuel oil (LSFO) refinery in Oman.

The proposed 300,000-b/d refinery, which will be built in phases along the Arabian sea, outside the Strait of Hormuz, aims to serve the growing need for LSFO that complies with the International Marine Organization’s (IMO) recently enacted regulations requiring ships to use marine fuels with a sulfur content below 0.5%, CBH said in a statement posted to its website.

The refinery would be equipped with “a unique,” and “proven”—though unidentified—Canadian technology that processes poor-quality fuel into cleaner and higher grades, according to the investment firm.

CBH said it expects the proposed LSFO refinery—which will require a $1.5-billion total investment based on a global fund out of London still open to interested investors—to deliver an ROI of 22%/year.

A timeline for the project, however, was not disclosed.

The early-July 2020 announcement follows CBH’s confirmation in late 2019 that it secured a petroleum refining license and government approval for a 300,000-b/d low sulfur bunkering fuel oil refinery in the Middle East that would be established as a public-private partnership by CBH and its partners, according to a Dec. 30, 2019, release from CBH.

In mid-2019, CBH signed a memorandum of understanding greenlighting the proposed 300,000-b/d refinery project for an estimated investment of $300-million investment, according to a July 5, 2019, release from the firm.

In approving the firm’s planned 2020 agenda in December 2019, CBH’s board adopted a measure to expand its LSFO refining investments in the Middle East with a proposed second refinery in the region, CBH said in a Dec. 15, 2019, release.

The company, however, has yet to release any details regarding the seemingly approved LSFO refinery.

Marubeni inks deal for Enterprise propylene supply 

Enterprise Products Partners LP (EPP), through one of its affiliates, has entered a long-term agreement with Marubeni Corp. of Japan, under which Marubeni will offtake polymer-grade propylene (PGP) produced from a second propane dehydrogenation plant (PDH 2) currently under construction at EPP’s operations in Mont Belvieu, Tex., for supply to global customers (OGJ Online, Sept. 26, 2019).

Concluded June 16, the PGP offtake agreement is part of a long-term collaboration between EPP and Marubeni that also includes the export of liquefied ethylene, the first 25-million lb vessel of which loaded and sailed from EPP and Navigator Holdings Ltd.’s 50-50 joint venture marine terminal at Morgan’s Point, Tex., in early January, EPP and Marubeni said June 30.

While neither company revealed a precise volume of PGP included under the new agreement, Marubeni—the globe’s largest trader of olefins—said access to PGP supply included in the deal will help meet its international customers’ demand for derivative products.

Still on schedule to enter service in second-quarter 2023, PDH 2 will have the capacity to upgrade 35,000 b/d of propane into 1.65 billion lb/year of PGP.

Upon PDH2’s full commissioning, EPP said its Mont Belvieu complex—equipped with capacity to produce up to 8 billion lb/year of PGP from its seven propylene fractionators and 3 billion lb/year from PDH1 and PDH2—will have a total PDH production capacity of 11 billion lb/year to become the largest complex of its kind in the world.

Earlier this year, EPP commissioned a new isobutane dehydrogenation (iBDH) unit at the Mont Belvieu complex (OGJ Online, Jan. 13, 2020). The iBDH unit is designed to process about 25,000 b/d of butane into nearly 1 billion lb/year of both high and low-purity isobutylene for use primarily as feedstock at EPP’s olefins assets to expand production of lubricants, rubber products, alkylate for gasoline blendstock, and methyl tertiary butyl ether to help meet growing demand on export markets.

GTG takes operatorship of Algeria’s Touat gas project 

Groupement TouatGaz (GTG) has formally taken over as operator of Neptune Energy Group Ltd. and Sonatrach’s jointly held Touat natural gas project in Algeria’s Sbaa basin, 1,500 km southwest of Algiers, near Adrar.

Técnicas Reunidas, which has carried out day-to-day operation of the natural gas plant since gas exports began in September 2019, transferred operatorship to GTG following the parties’ signature of a performance acceptance certificate on June 24, Neptune Energy said.

Spanning more than 1,300 sq km across the Sahara Desert, the Touat project—which includes 19 development wells, a treatment plant for gas and stabilized condensate, a gathering network, and connection to the Sonatrach-built main GR5 pipeline for transporting gas from southwest Algeria to Hassi R’Mel, about 800 km north—achieved its plateau production of 450 MMcfd in April 2020, according to Neptune.

Representing about 9% of Algeria’s total gas exports, the Touat project will be in production for more than 20 years, Neptune said.

GTG partners include Neptune Energy Touat (65%) and Sonatrach (35%). Neptune Energy Touat is jointly owned by Neptune (54%) and Engie E&P International SA (46%).

TRANSPORTATION Quick Takes 

NextDecade cuts Rio Grande LNG to five trains 

NextDecade Corp. is optimizing its Rio Grande LNG (RGLNG) project by cutting a planned six liquefaction trains to five. Original front-end engineering and design for RGLNG was based on six 4.5-million tonne/year (tpy) LNG trains.

Liquefaction technology, however, has evolved since the project’s 2015-16 filings with the US FERC, such that five trains will now produce the planned 27-million tpy total output, reducing CO2 emissions by 21% and cutting construction time. The company anticipates a smaller plant footprint and reduced road traffic.

Future development of Train 6 will require authorization from FERC, the US Department of Energy, and any other relevant federal or state agencies.

NextDecade earlier this year delayed RGLNG’s final investment decision to 2021 due to the COVID-19 pandemic’s effect on the LNG market (OGJ Online, May 20, 2020).

Empire buys coastal Louisiana crude terminal, plans Zydeco interconnect

Empire Pipeline LLC acquired a crude oil terminal in Gibson, La., from Equilon Enterprises LLC and Shell Oil Co. Gibson is Empire’s first crude oil terminal. The company intends to increase market optionality for crude transport and blending through a planned bidirectional pipeline connection to Shell’s 375,000-b/d Zydeco pipeline, which delivers crude to St. James and Clovelly, La., from terminals in Houston and Nederland, Tex.

The terminal already receives sweet and sour crudes via Shell’s 200,000-b/d deepwater Gulf of Mexico Ship Shoal pipeline system, the 18,000-b/d Atchafalaya pipeline, and the Magellan pipeline. Offtake from the terminal is substantially directed by pipeline to St. James terminal.

Gibson terminal, connected to the Intercoastal Waterway, includes 300,000 bbl of storage, blending services, three docks for barge unloading and loading, and a truck receiving station.

YPF declares force majeure on Tango FLNG 

YPF SA has given Exmar written notification of force majeure under the charter and services agreements between the two companies regarding 500,000-tonne/year Tango floating LNG (FLNG) plant, stationed in Bahia Blanca, Argentina. YPF claimed that effects of the COVID-19 pandemic both worldwide and in Argentina have hindered its ability to perform its obligations under the agreements, including its ability to pay the invoices due for services performed since second-half March 2020.

Tango FLNG shipped its first commercial cargo in November 2019, with plans to ship as many as eight LNG cargoes per year over 10 years.

YPF has two LNG carriers on charter to ship Tango’s output, one from Exmar and one from Excelerate Energy LP.

According to Exmar’s first-quarter 2020 results, Tango FLNG contributed 36% of the company’s earnings before interest, taxes, depreciation, and amortization. Exmar considers the force majeure notice to be unlawful and said it is considering its best option to defend its interests. The company added that its current forecast liquidity is not at risk until end-2020.

Align Midstream completes Haynesville gathering line 

Align Midstream Partners II LLC, Dallas, has completed the TOPS pipeline and formed a joint venture in the pipeline with Sabine Oil & Gas Corp., a fully owned subsidiary of Osaka Gas USA Corp. TOPS is a 30-mile, 16-in. OD natural gas gathering pipeline in the Carthage, Tex., area with interconnections to bring Haynesville shale production to downstream markets.

The transaction marks Osaka Gas USA’s first US midstream acquisition.

Align Midstream and Elevate Midstream Partners LLC in 2019 combined their respective East Texas asset bases. Both companies are backed by Tailwater Capital.

Sabine Oil & Gas Holdings Inc. in 2019 sold Sabine Oil & Gas Corp. to Osaka Gas USA, a subsidiary of Osaka Gas.