OGJ Newsletter

 GENERAL INTEREST Quick Takes

Trump extends, expands offshore drilling moratorium near Florida 

President Trump signed a memorandum Sept. 8 extending the moratorium on oil and gas drilling in the eastern Gulf of Mexico by 10 years and expanding the moratorium to Atlantic federal waters off the coasts of Florida, Georgia, and South Carolina.

Trump announced the decision at a political gathering in Jupiter, Fla., where he stressed environmental protection as part of his policies. Both Republicans and Democrats in Florida have been opposed to oil and gas drilling off the coast of their state.

The leasing moratorium for the eastern Gulf of Mexico was set to expire in the middle of 2022. Under authority of the Outer Continental Shelf Lands Act, the president extended that moratorium from July 1, 2022, to June 30, 2032.

He also applied that 10-year moratorium to “the areas currently designated by the Bureau of Ocean Energy Management as the South Atlantic and Straits of Florida Planning Areas,” meaning Atlantic waters off Florida, Georgia, and South Carolina.

Oil industry responses to the announcement were moderate. Erik Milito, president of the National Ocean Industries Association, issued a statement advocating domestic energy production, but he did not sharply criticize Trump’s decision.

“The American offshore should be the region of choice for energy production,” Milito said. “Our preference always should be to produce homegrown American energy.”

The eastern Gulf of Mexico has long been known to have oil and gas reserves, and several companies maintain their leasing rights in the area under the moratorium. Those rights are not abrogated by the moratorium, but the leaseholders cannot develop their sites within 125 miles of Florida.

Development in the eastern Gulf could involve a practical expansion of existing oil and gas infrastructure from the central Gulf, in the view of petroleum geologists.

Rep. Raul Grijalva (D-Ariz.), issued a statement saying the Trump administration bowed to overwhelming public pressure in the decision on the moratorium.

Sempra LNG promotes Glatch to president, COO  

Sempra LNG has promoted Lisa Glatch, currently chief operating officer, to president and chief operating officer.

She will continue to serve as the board chair for Cameron LNG and lead Sempra LNG’s sustainability initiatives.

With more than 30 years of experience, Glatch joined Sempra Energy in 2018 as strategic initiatives officer and then joined Sempra LNG as chief operating officer.
Total resigns operatorship in Foz do Amazonas basin 

Total resigned as operator for five exploration blocks in Foz do Amazonas basin, 120 km offshore Brazil. Partners of exploration blocks FZA-M-57, FZA-M-86, FZA-M-88, FZA-M-125, and FZA-M-127 were notified Aug. 19 (OGJ Online, May 16, 2013).

Total informed the National Agency of Petroleum, Natural Gas and Biofuels (ANP) of the decision, setting into motion a 6-month period during which a new operator will be appointed. During this period, Total has the duty to continue monitoring all regulatory processes on behalf of partners Petrobras and BP.

Exploration & Development Quick Takes 

ExxonMobil Redtail discovery adds to offshore Guyana oil 

ExxonMobil made an oil discovery offshore Guyana at the Redtail-1 well, marking the 18th discovery on Stabroek block. The discovery adds to previously announced estimated recoverable resources of more than 8 billion boe on Stabroek.

Redtail-1 encountered 232 ft (70 m) of high-quality oil bearing sandstone reservoir. The well, about 1.5 miles (2.5 km) northwest of the recent Yellowtail discovery, was drilled in 6,164 ft (1,878 m) of water.

In addition to the Redtail-1 discovery, drilling at Yellowtail-2 encountered 69 ft (21 m) of net pay in newly identified, high-quality oil bearing reservoirs among the original Yellowtail-1 discovery intervals. This resource is currently being evaluated for development in conjunction with nearby discoveries.

ExxonMobil made the first commercial discovery in Guyana in 2015 and started production in December 2019 from the Liza Destiny floating production and offloading vessel (FPSO), which can produce up to 120,000 b/d.

ExxonMobil continues to advance the Liza Phase 2 project, which is expected to start up in 2022 and produce up to 220,000 b/d. Construction activities are under way in Singapore on the Liza Unity FPSO. A third production vessel for the Payara development, with production capacity of 220,000 b/d, is on hold pending government approval.

Stabroek block covers 6.6 million acres (26,800 sq km). ExxonMobil affiliate Esso Exploration and Production Guyana Ltd. is operator and holds 45% interest in Stabroek. Hess Guyana Exploration Ltd. holds 30% and CNOOC Petroleum Guyana Ltd., a wholly owned subsidiary of CNOOC Ltd., holds 25%.

Theia advances Great Sandy Desert exploration project  

Theia Energy has entered a land use agreement with the Karajarri Traditional Lands Association enabling the company to move forward with its unconventional oil and gas exploration plans in the onshore Canning basin permit EP 493.

Theia has 100% interest in the permit that covers one million acres and contains the prospective Mid-Ordovician-age Goldwyer shale play in the Great Sandy Desert region.

The company was formed in 2018 as a spin-off from Finder Energy following Finder’s Theia-1 well in the permit in 2015. The well encountered a 70 m oil column in the shale target.

Early assessment of the results validates the company’s geological model and derisks the play, Theia said.

Appraisal work is expected to begin with a second vertical well, Theia-2, to be drilled from the same location as Theia-1 and fracture stimulated.

Theia has opened a data room for prospective farminees to share costs, but the well will be drilled even if no JV partner is found before the expected spud date of 2022, the company said.

Theia puts an estimated prospective resource of the Goldwyer shale in the region at more than 3 billion boe.

Vintage completes Vali test with strong gas flow 

The Vintage Energy Ltd. group in the southwest Cooper basin permit ATP 2021 has completed a successful 2-day flow test program at the Vali-1 ST1 well.

During the extended test, a flow rate of 4.3 million cu ft/d was measured through a 36/64-in. choke at a flowing wellhead pressure of 942 psi.

Transient tests were taken before the extended flow test with recorded rates between 3.7 million cu ft/day (through a 24/64-in. choke at 1,676 psi) and 7.5 million cu ft/day (through a 32/64-in. choke at 1,593 psi). Gas samples were taken and are being analyzed.

All fracture stimulated zones contributed to the overall gas flow and there were rapid pressure buildups during all shut-in periods with pressure levels quickly approaching 3,000 psi, said Neil Gibbins, managing director.

Estimated initial production flow rate for the well could be in excess of 5 MMcfd, he said.

All data will be assessed and incorporated into a field commercialization plan, including an estimate of the number of development wells required to efficiently produce gas and maximize returns.

Vali-1 ST1 will be completed with the installation of production tubing in October.

Discussions are underway with Cooper basin JV operator Santos for connection of Vali field to the Moomba gas gathering system.

Vintage is operator of the permit with 50% interest. Metgasco Ltd. and Bridgeport (Cooper basin) Pty Ltd. each hold 25%.

Kohat JV reports gas, condensate discovery, Kohat district, Pakistan 

The Kohat joint venture made a gas and condensate discovery at Togh Bala-01, Block 3371-10, Kohat district, Khyber Pakhtunkhwa Province. This is the second consecutive discovery in Kohat block (OGJ Online, Oct. 18, 2019).

The well was spudded on June 27 and drilled to 2,172 m into the Lockhart formation. Open hole testing flowed at the rate of 9.00 MMscfd of gas and 125 b/d of condensate with 1,690 psi flowing wellhead pressure through a 32/64-in. choke.

Oil and Gas Development Co. Ltd. (OGDCL) is operator (50%) with partners Mari Petroleum Co. Ltd. (MPCL) (33.33%) and Saif Energy Ltd. (SEL) (16.67%).

Drilling & Production Quick Takes 

Equinor begins additional Martin Linge drilling 

Equinor commenced drilling of new wells at Martin Linge oil and gas field in the North Sea after a review showed that four gas wells drilled before the company took over operatorship of the field from Total in 2018 do not have enough barriers for safe production. Petoro carried out an independent assessment of well barriers that support the operator’s view.

“The wells are considered safe as they are now, but we will keep them plugged and under continuous monitoring until we have reduced the pressure in the formation by producing from other wells,” said Geir Tungesvik, acting executive vice-president for technology, projects, and drilling.

“Our number one priority is to ensure safe start-up of the field. We will therefore plan to drill up to three new gas wells in addition to the two remaining wells from the plan for development and operation for the field to produce as originally planned,” he said.  

Martin Linge field lies 42 km west of Oseberg in water depth of 115 m. The main reservoir is structurally complex and contains gas and condensate at high pressure and high temperature. The field is scheduled to come on stream at the end of this year.

The costs for drilling up to three new wells total about 2 billion kroner. The Maersk Intrepid drilling rig recently started operations following an April contract award (OGJ Online, Apr. 30, 2020).  The Martin Linge plant is designed for a mixture of oil and gas and needs gas wells that produce at a certain rate for start up and production.    

Equinor is the majority shareholder and operator of Martin Linge (70%) with partner Petoro (30%).

Husky produces first oil at Spruce Lake, Saskatchewan

Husky produced first oil at the Spruce Lake Central thermal project in Saskatchewan and is moving towards startup of Liuhua 29-1 field at the Liwan gas project, offshore Pearl River Mouth basin in the South China Sea about 300 km south east of Hong Kong (OGJ Online, Apr. 20, 2020).

Spruce Lake Central, Husky’s sixth 10,000-b/d thermal bitumen project since 2015, has been completed safely, on schedule, and on budget. It began steaming in second-quarter 2020 and will ramp up to full production over the next couple of months.

Husky’s Saskatchewan thermal projects are directly linked to its Lloydminster upgrader, asphalt refinery, and Midwest US refineries, with access to secured pipeline capacity and ample storage. The projects are not subject to the government-mandated production quotas that remain in place in Alberta.

Offshore China, Husky and partner CNOOC tied in Liuhua 29-1 field at the Liwan gas project ahead of schedule and below budget, Husky said. First production and gas-liquids sales are expected to start by November. Target production is 45 MMcfd of gas and 1,800 b/d of liquids when fully ramped up, reflecting Husky’s 75% working interest plus exploration cost recovery volumes.

SapuraOMV brings Bakong field on stream 

SapuraOMV Upstream, Kuala Lumpur, put on stream its operated Bakong gas field, under the SK408 production sharing contract (PSC), after achieving stable production. Production started in June. Phase 1 of SK408 development is now entirely on stream.

SK408 fields are part of discoveries made by the company in 2014. Phase 1 development aims to commercialize gas reserves from Gorek, Larak, and Bakong fields, to help meet the growing gas demand in Asia. Larak started production in December 2019, and Shell-operated Gorek started in May 2020. Under a long-term agreement with Petronas, SapuraOMV and SK408 partners will supply gas from these fields to the Petronas LNG complex in Bintulu, Sarawak.

The fields are SapuraOMV’s second major upstream gas development project in East Malaysia, following successful development and commencement of production from SK310 B15 gas field. With full ramp-up of the first phase of SK408, SapuraOMV’s production is scheduled to increase to more than 30,000 boe/d in 2020, which will more than double 2019’s production rate.

SapuraOMV, a partnership between Sapura Energy Bhd. and OMV Exploration & Production GmbH, a subsidiary of Austria’s OMV Aktiengesellschaft, holds a 40% interest in SK408 PSC with partners Sarawak Shell Bhd. (30%) and Petronas Carigali Sdn Bhd (30%).

PROCESSING Quick Takes 

Emperor Energy moves to pre-FEED at Judith field 

Emperor Energy Ltd., Sydney, commenced a pre-front end engineering design (pre-FEED) stage for development of its 100%-owned Judith gas-condensate field in offshore Gippsland basin permit Vic/P47 in Victoria.

The pre-FEED study comprises early design concepts for a gas processing plant to operate adjacent to and in parallel with the existing Orbost plant that is currently processing gas from Cooper Energy’s Sole gas.

There will also be initial design for a 40-km long subsea pipeline from the field to a shoreline crossing along with an export pipeline from the shore plant to the Eastern Gas Pipeline that carries gas up the east coast to Sydney.

In addition, the study will refine indicative project cost estimates and project scheduling.

Emperor said the pre-FEED work, which is being done by the APA Group, will take about 4 months to complete. The design basis is for production and processing of 80 million cu ft/day of gas (90 terajoules/day) across a projected 25-year project life. The pre-FEED stage follows a memorandum of understanding between Emperor and APA for Judith field signed in October 2019.

Emperor has also revised the field production well stimulation model to include four vertical production wells at the beginning of the project with a fifth production well added in the 15th year. Initial well design for the proposed Judith-2 appraisal-exploration well has also been completed. Negotiations for a suitable drilling rig will begin once a farm-in partner is secured. Potential farminees are currently assessing field data.

Emperor estimates contingent 2C resources at the field of 150 bcf along with 2.2 million bbl of condensate.

Uzbekneftegaz wraps upgrade, expansion of Mubarek gas plant 

JSC Uzbekneftegaz has completed a modernization and expansion project at its Mubarek gas processing plant in Uzbekistan’s Kashkadarya region. Alongside modernizing the plant’s three existing propane-butane production (UPPBS) units, Uzbekneftegaz has completed construction and commissioning of a fourth $58.25-million UPPBS unit at the site, Uzbekistan’s Ministry of Energy (MOE) said.

Built over a period of 3 years, the new UPPBS unit is equipped to process up to 3 billion cu m/year of natural gas feedstock to produce an additional 38,400 tonnes/year of LPG to help meet Uzbekistan’s growing domestic demand, MOE said.

Completed as of Aug. 28, the portion of the project involving implementation of the fourth UPPBS unit also included construction of a booster compressor station; a zeolite gas dehydration unit; and additional tanks for receiving, storing and shipping liquefied gases to consumers, according to a Mar. 18 project update from Uzbekneftegaz.

While neither Uzbekneftegaz nor MOE disclosed details regarding specific modernization works carried out at Mubarek’s existing UPPBS units, Uzbekneftegaz said in an Aug. 28 release that overall cost of the upgraded and newly constructed unit amounted to $75 million.

Chinese chemical producer lets contract for C3 Oleflex unit 

Shanghai Huayi (Group) Co. subsidiary Guangxi Huayi New Material Co. Ltd. has let a contract to Honeywell UOP LLC to provide its proprietary C3 Oleflex technology for a propane dehydrogenation (PDH) plant at its integrated petrochemical complex in Qinzhou, Guangxi, China.

As part of the contract, Honeywell UOP will deliver licensing for the Oleflex technology, in addition to catalysts, adsorbents, and other unidentified services for the plant, which will produce 750,000 tonnes/year of polymer-grade propylene to help meet China’s growing demand for propylene derivatives, the service provider said.

Huayi will use on-purpose propylene production from the plant as feedstock for the complex’s downstream acrylic acid unit, as well as cumene and phenol units, to support creation of industrial and consumer products, according to Honeywell UOP.

The service provider disclosed neither a value of the contract nor a timeframe for the project’s targeted completion.

This latest contract award follows Huayi’s selection of Johnson Matthey and Dow earlier this year to license their LP Oxo SELECTOR 10 technology for a new 300,000-tonnes/year butanol plant to be built at the Qinzhou complex, according to a Feb. 13 release from Johnson Matthey. Alongside technology licensing, the service providers will deliver customized plant design, performance warranties, technical support pre- and post-plant startup, as well as ongoing technology updates.

A timeline for commissioning of the butanol plant project, however, was not revealed.

TRANSPORTATION Quick Takes 

EPP cancels Midland-to-ECHO 4 crude pipeline 

Enterprise Products Partners LP (EPP) has cancelled its 450,000-b/d Midland-to-Enterprise Crude Houston (ECHO) 4 crude oil pipeline project (M2E4). The company amended long-term agreements with customers to reduce the volume of near-term shipping commitments in exchange for extending the term of the agreements, allowing cancellation of the pipeline.

M2E4’s cancellation will reduce EPP’s aggregate growth capital expenditures for 2020, 2021, and 2022 by a combined $800 million. Based on currently sanctioned projects, the company expects growth capital expenditures, net of contributions from joint-venture partners, for 2020, 2021, and 2022 to be $2.8 billion, $1.6 billion, and $900 million, respectively.

These estimates do not include capital investments associated with EPP’s proposed deep water offshore crude oil terminal (SPOT), which remains subject to government approvals. The company does not expect to receive approvals for SPOT in 2020.

Energy Transfer completes Lone Star Express Pipeline expansion  

Energy Transfer LP has added over 400,000 b/d of NGL capacity out of the Permian and Delaware basins with the completion of its Lone Star Express Pipeline expansion project. The project was completed on budget and ahead of schedule, the company said Sept. 1.

The new 352-mile, 24-in. pipeline originates in Winkler County, Tex., and connects into the existing Lone Star Express 30-in. pipeline at the Morgan Junction in Bosque County, Tex., south of Fort Worth.

The pipeline system ultimately connects into Energy Transfer’s Mont Belvieu integrated liquids storage and fractionation facility. Energy Transfer’s seventh fractionator at Mont Belvieu was brought on line earlier this year, bringing the partnership’s total fractionation capacity to more than 900,000 b/d.

BG contracts Corinth to provide Colibri gas export line pipe 

BG International, a subsidiary of Royal Dutch Shell PLC, signed Corinth Pipeworks to manufacture and supply steel pipes for development of Block 22 and North Coast Marine Area (NCMA)-4, Colibri, an offshore natural gas field in Trinidad and Tobago. The agreement covers 93 km of 16-in. OD high-frequency welded and longitudinal submerged arc-welded coated line pipe for construction of the export pipeline to bring gas from Block 22 and Colibri to the Shell-operated Poinsettia platform, also in Trinidad’s NCMA.

Pipe manufacturing and coating will begin in Greece later in 2020 and pipeline installation will start in 2021.

BG holds the two blocks in partnership with Trinidad and Tobago national oil company, Heritage Petroleum Co. Ltd.

Corinth describes the work as the first offshore project for which pipes will be supplied in ultralong 24-m (80-ft) lengths. This will allow an almost 50% reduction in the number of offshore pipe-to-pipe welds, the company said.

Neptune begins installing heated North Sea crude production line 

Neptune Energy has begun installation of a heated subsea production pipeline in the Norwegian sector of the North Sea. Once completed, the 36 km electrically trace-heated (ETH) pipe-in-pipe line will transport oil from Neptune-operated Fenja field to the Njord A platform, operated by Equinor ASA.

Phase 1 installation included lay and testing of 9 km. Neptune said that the heated pipe-in-pipe solution permitted it to tie the field back to existing infrastructure, reducing costs. The company described the pipeline as the longest ETH project in the world.

The project was developed and qualified with TechnipFMC. The companies expect to complete installation during 2021 using TechnipFMC’s Deep Energy pipelay vessel.

The high wax content of Fenja’s oil requires that the pipeline’s contents be warmed to above 28° C. before starting flow after a shut down. During normal production, the temperature in the pipeline would be well above this temperature.

Fenja lies about 120 km north of Kristiansund, Norway, at a water depth of roughly 320 m. Neptune Energy’s (30%) partners in the field include Vår Energi (45%), Suncor Energy (17.5%), and DNO ASA (7.5%).