OGJ Newsletter

GENERAL INTEREST Quick Takes

Oxy reduces 2020 capital spending by $1.7 billion  

Due to the sharp decline in global commodity prices, Occidental Petroleum Corp., Houston, said it will reduce 2020 capital spending to $3.5-3.7 billion from its previously guided $5.2-5.4 billion and will implement additional operating and corporate cost reductions.

Previously, the company planned to allocate $2.2 billion to Permian Basin resources in 2020—down from $3.3 billion the year prior—with expected production growth in the region of 6%. Permian production guidance for the year was previously 465,000-475,000 boe/d. Total company production guidance for the year was previously 1.36–1.39 MMboe/d. A breakdown of the revised 2020 capital program by asset was not provided.

The company’s 2019 spending reached $6.3 billion, nearly 70% of which was allocated to US assets, mostly in the Permian Basin.

Vicki Hollub, Occidental’s president and chief executive officer, said the actions lower the company’s cash flow breakeven level to the low $30s WTI, excluding the benefit of its hedges.

International rig count up 7 units in February  

The international rig count for February reached 1,085, an increase of 7 units from January and up 58 units from the 1,027 counted in February 2019, according to Baker Hughes data (OGJ Online, Feb. 7, 2020).

The international offshore rig count for February was 245, unchanged from January, and down 5 units from the 250 counted in February 2019.

The worldwide rig count for February was 2,125, up 52 units from the 2,073 counted in January, and down 181 units from the 2,306 counted in February 2019.

The average US rig count for February was 791, unchanged from January, and down 258 from the 1,049 counted in February 2019.

Europe was down 3 units with 130 in February and up 36 units year-over-year. Effective June 7, 2019, Ukraine has been added to the Baker Hughes International Rig Count.

Latin America is up 5 units from the previous month with 184 units and up 2 units year-over-year.

The Asia-Pacific region is up 2 rigs with 224 units month-over-month and down 16 units from its year-ago average.

The Middle East is down 3 units month-over-month at 427 and up 29 units year-over-year.

The average Canadian rig count for February was 249, up 45 units from the 204 counted in January, and up 19 units from the 230 counted in February 2019. 

Devon cuts 2020 capital spending by $500 million  

Devon Energy, Oklahoma City, has reduced its 2020 capital spending budget by $500 million to $1.3 billion. The 30% reduction compared to its previous 2020 capital plan is in response to the current commodity price environment, Devon said Mar. 12.

While the capital reductions will be spread across the company’s portfolio, the company expects to focus development activity in the Delaware Basin and Eagle Ford, with the most substantial cuts applied to the Powder River Basin and STACK assets.

In February, the company noted 30-day production rates of Powder River Basin Niobrara wells as high as 1,500 boe/d with oil representing more than 85% of the production mix during in 2019 and had previously planned to double its Niobrara drilling activity in 2020 in an attempt to ready a portion of the field for development in 2021.

In the STACK, the company formed a drilling partnership with Dow to develop a portion of the company’s acreage. The partnership was expected to begin drilling its initial development project in the second quarter of 2020.

Details about specific changes to Powder River Basin and STACK activity programs were not released, but the company said an update is expected with concurrent with its first-quarter reporting.

The company entered 2020 with $1.8 billion of cash and an undrawn credit facility of $3 billion. The company has no outstanding debt maturities occurring until the end of 2025.

Meantime, the company is expected to close on the sale of Barnett shale assets to Banpu Kalnin Ventures for $770 million on Apr. 15 (OGJ Online, Dec. 18, 2019).

Exploration & Development Quick Takes

Predator Oil & Gas progresses Guercif drilling plans onshore Morocco  

Predator Oil & Gas Holdings Plc (PRD) has received environmental approval for drilling onshore Morocco after an environmental impact statement regarding the Guercif prospect was ratified by local authorities.

The approval is valid for 5 years from the Jan. 29 effective date of issue.

Predator is operator of the Guercif Petroleum Agreement which is prospective for Tertiary gas in a prospect 4 km from the Maghreb gas pipeline, and deeper Triassic gas. A well location has been selected for drilling in this year’s second quarter and a rig option agreement has been exercised.

The initial drilling program will comprise drilling of the Moulouya-1 prospect, subject to regulatory consents and approvals, to a depth of 2,000 m. Drilling rig mobilization and drilling operations are expected to take up to 30 days.

Completion of the first well will release $1 million of PGVL’s $1.5 million bank guarantee with Office National des Hydrocarbures et des Mines (ONHYM), subject to final delivery of all well data.

Predator Gas Ventures (PGVL), a wholly owned subsidiary of PRD, has the option—subject to approvals and regulatory consents—to extend the drilling program with either an appraisal well or a follow-up exploration well.

Predator holds 75% interest in a joint venture with ONHYM acting on behalf of the State (25%).

Lead FEED contract awarded for Etinde, offshore Cameroon 

Bowleven Plc and partners have let a front-end engineering design contract to TechnipFMC plc for the proposed development of Isongo Marine (IM) gas condensate field in the Etinde license are offshore Cameroon.

Under the terms of the contract, Technip would work alongside and report to the integrated JV partner operations team to lead the onshore and offshore elements of the FEED program in respect of the proposed development. The reservoir engineering and sub-surface development aspects of the wider FEED process will be undertaken by the operator, New Age (African Global Energy) Ltd.

The initial phase of the development comprises an onshore gas processing, storage, and export facility linked to an unmanned well head platform with associated pipeline infrastructure.

The Etinde permit (former Block 7) lies in shallow water in the Rio del Rey basin and comprises four proven reservoir intervals within the Pliocene and Miocene formations.

The IM primary development area includes three major pay intervals containing gas condensate with a high liquid yield. A 2019 Degoyler & McNaughton report identified 2C (P50) contingent resources of 183 MMboe including 65 MMbbl of condensate and 12 MMbbl of LPGs. According to Bowleven, the structure is relatively simple with Upper Isongo and Mid Isongo mapped as 4-way closures while Intra Isongo is fault trapped.

A final investment decision on Etinde is expected this year with with first production expected in 2022.

Operator NewAge holds 37.5% in Etinde. Lukoil holds 37.5% and Bowleven holds 25%.

Murphy lets contract for GoM development 

Murphy Exploration and Production Co. – USA, a unit of Murphy Oil Corp., has let a contract to Subsea 7 for subsea installation services related to its deepwater Gulf of Mexico Khaleesi-Mormont and Samurai field developments tying back to the King’s Quay semi-submersible. The King’s Quay host facility lies 175 miles south of New Orleans in the Green Canyon area (OGJ Online, Dec. 12, 2019).

The contract, valued at $150-300 million by Subsea 7, covers the tie back of seven subsea wells to the King’s Quay host facility. The project scope includes engineering, procurement, construction, installation, and commissioning of all subsea equipment including PLETs, PLEMs, umbilicals, and distribution hardware, production and export flowlines and jumpers, as well as the wet tow in the Gulf of Mexico to the fields and mooring system installation of the semi-submersible FPS.

Project management and engineering will begin immediately at Subsea 7’s offices in Houston, Tex. Fabrication of flowlines and risers will take place at Subsea 7’s spoolbase in Ingleside, Tex., with offshore operations occurring in 2021.

Drilling & Production Quick Takes 

ExxonMobil completes first West Barracouta well  

ExxonMobil has reached total depth in the first of two planned development wells in the West Barracouta gas field in Bass Strait, designed to bolster gas supplies to Australia’s domestic market in 2021.

The development, in license VIC/L1 in the offshore Gippsland basin of Victoria, will be tied back to the existing Barracouta production infrastructure (OGJ Online, Dec. 13, 2018).

ExxonMobil and partner BHP first began drilling in Bass Strait in 1965 and Barracouta was the first discovery. Since then, 10 tcf of gas and 4 billion bbl of oil have been produced from Bass Strait fields.

The new project builds on more than $5.5 billion (Aus.) invested by the joint venture in other recent offshore Victorian projects, including Kipper Tuna Turrum fields and the onshore Longford gas conditioning plant.

Panoro Energy increases activity in Tunisia 

Panoro Energy ASA, London, plans to increase drilling activity in Tunisia.

The company and its joint venture partner, state oil enterprise ETAP, approved drilling a production well on Guebiba oil field, onshore Tunisia, part of the Thyna Production Services SA (TPS) operated assets (OGJ Online, Nov. 6, 2018). It will be the first drilling operation on the assets since 2015.

The well is expected to spud in May using Tunisian state-owned drilling contractor Compagnie Tunisienne de Forage’s land drilling rig CTF-06. From an existing top-hole section, the well will target a new production interval in the Bireno formation at 3,600 m in a known fault block compartment, where a further drainage point is required to effectively exploit the resource potential present in the western panel of the field.

It will be drilled in advance of the Salloum West exploration well, which also will be drilled by rig CTF 06, targeting the Bireno formation. The well has been delayed due to outstanding regulatory approvals.

Additionally, three wells are in the final stages of completion and will be brought online in stages by the end of this year’s first quarter. Collectively, these workover activities are expected to increase the TPS-operated assets gross production to about 5,000 b/d. A workover rig has been on site since December 2019. Workover activities have contributed to a rise in gross production to over 4,000 b/d, up from the third-quarter 2019 average production of 3,450 b/d.

Other activities include a recent well stimulation exercise in Rhemoura field, part of TPS operated assets, resulting in a fourfold increase in production. The JV partners are planning a similar campaign in other TPS fields.

The TPS assets comprise five oil field concessions (Cercina, Cercina Sud, Rhemoura, El Ain/Gremda, and El Hajeb/Guebiba) in the region of the city of Sfax, onshore, and shallow water offshore Tunisia.

Panoro Tunisia Production AS holds 49% indirect interest in the fields and 50% interest in the TPS operating company. The remaining interests are held by ETAP. Panoro’s net interest in TPS operations is 29.4%.

Second well from Tortue Phase 2 reaches first oil  

BW Energy has reached first oil from the DTM-4H Gamba well drilled as part of the Tortue Phase 2 development project in the Dussafu Marin permit offshore Gabon.

The well began production Mar. 7, 3 days after first oil from the DTM-5H well. With the addition of the two wells, the overall field production continues to stabilize, the operator said, with current output of 20,000 b/d of oil gross.

Phase 2 consists of four production wells tied back to the FPSO BW Adolo. DTM-4H and DTM-5H are the first of two clusters. The second cluster is being drilled and is scheduled to begin production by June. Total production after Phase 2 completion is projected to be 17,300-21,600 b/d of oil gross for 2020 from six producing wells, compared with an average of 11,800 b/d of oil gross produced in 2019.

The Dussafu Marin JV consists of BW Energy (operator, 73.5%), Tullow Oil (10%), Gabon Oil Co. (9%), and Panoro Energy (7.5%).

PROCESSING Quick Takes

Fire halts ethylene production at Lotte Chemical’s Daesan complex 

Lotte Chemical Corp. has indefinitely shuttered the naphtha cracking complex at its petrochemical plant in Daesan, South Korea, following a fire that broke out at the unit’s compressor on Mar. 4.

While an investigation into the fire as well as an assessment of damages resulting from the incident are under way, the operator has no definitive timeline for when the cracker will reopen, Lotte said in filing to the Korea Exchange.

The company, however, said it plans to minimize disruptions to supply during the production outage.

The Daesan cracker produces 1.1 million tonnes/year of ethylene, which in turn feeds production of 290,000 tpy of linear low-density polyethylene (LLDPE) and 130,000 tpy of low-density polyethylene (LDPE) at the manufacturing site, according to Lotte’s website.

The latest official capacity data from Lotte shows the Daesan petrochemical complex also produces the following: 550,000 tpy propylene, 500,000 tpy polypropylene, 190,000 tpy butadiene, 730,000 tpy ethylene oxide-ethylene glycol, 50,000 tpy ethylene oxide adduct, 50,000 tpy glycol ether, 240,000 tpy benzene, 120,000 tpy toluene, 60,000 tpy xylene, and 577,000 tpy styrene monomer.

Lotte did not reveal whether the cracker fire impacted other units at the Daesan complex, or if production from these units has been affected by the incident.

Egyptian refiner advances grassroots hydrocracking complex 

Assiut National Oil Processing Co. (ANOPC), a subsidiary of Egyptian General Petroleum Corp.’s Assiut Oil Refining Co. (ASORC), has let a contract to a consortium of Engineering Co. for Petroleum & Chemical Industries (ENPPI), Petroleum Projects & Technical Consultation Co. (Petrojet), and TechnipFMC PLC for construction of ANOPC’s previously announced hydrocracking complex in Assiut, Egypt (OGJ Online, Oct. 8, 2018).

As part of the contract, ENPPI will deliver detailed engineering, procurement, construction (EPC), precommissioning, commissioning, and start-up tests for the complex’s vacuum distillation unit (VDU), distillate hydrotreating unit (DHU), sulfur recovery unit (SRU), and sulfur solidification unit (SSU), ENPPI said in posts to its official LinkedIn and Facebook accounts.

Once completed, the $2.5-billion hydrocracking complex will process 2.5 million tonnes/year of heavy fuel oil (mazut) from ASORC’s nearby 4.5 million-tpy Assiut refinery to produce about 2.8 million tpy of Euro 5-quality diesel and other high-value products to help meet Upper Egypt’s rising demand for petroleum products as well reduce the country’s reliance on imports, according to project documentation from Egypt’s Ministry of Petroleum & Mineral Resources (MOPMR) dated January 2020, as well as a Feb. 14 post to Petrojet’s official Facebook account.

While ENPPI did not disclose further details regarding its partners’ current scope of work on the project, TechnipFMC previously confirmed it most recently was awarded a contract for basic design of the complex, as well as an earlier contract to provide preliminary works on a former iteration of the project (OGJ Online, Oct. 31, 2018; July 27, 2015).

TechnipFMC also previously awarded a contract to ENPPI as a subcontractor for early works on the hydrocracking complex, the scope of which—alongside the VDU, DHU, SRU, SSU, as well as on-site and off-site storage areas—was to cover basic engineering, finalization of the licencors’ process design package, procurement services for long-lead items, and open-book cost estimates to define the project’s overall EPC cost, according to ENPPI’s 2018 annual report.

Alongside Euro 5-quality diesel, ENPPI and MOPMR said the new hydrocracking complex also will produce 360,000-400,000 tpy of naphtha, 91,000-101,000 tpy of LPG, 331,000 tpy of coke, and 57,000-66,400 tpy of sulfur.

In a series of June 2019 posts to its official LinkedIn account, ANOPC—which was established in 2018 specifically to build and operate the hydrocracking complex—confirmed Petrojet already had undertaken site preparation works in Assiut for construction of the complex.

The hydrocracking complex currently is scheduled to be completed in 2022, according to MOPMR.

TRANSPORTATION Quick Takes 

Phillips 66, Trafigura form JV to develop deepwater port 

Phillips 66 and Trafigura Group Pte. Ltd. have formed a 50-50 joint venture, Bluewater Texas Terminal LLC, to develop an offshore deepwater port project 21 nautical miles east of the entrance to the Port of Corpus Christi, Tex.

Phillips 66 submitted its application to Maritime Administration (MARAD) for a Deepwater Port License under the Bluewater Texas franchise in mid-2019.

The proposed project, to be constructed by Phillips 66, will consist of up to two single point mooring buoys capable of fully loading very large crude carriers (VLCCs) to export crude oil. The project is in the permitting stage and a final investment decision is expected later this year, pending permit approval and customer volume commitments that support economic return thresholds.

Trafigura has withdrawn its application to develop the Texas Gulf Terminals deepwater port facility near Padre Island National Seashore that was submitted to the United States Maritime Administration (MARAD) in July 2018.

Venture Global Plaquemines LNG, EDF sign LNG agreement  

Venture Global Plaquemines LNG LLC has signed an agreement with Électricité de France SA (EDF) for the supply of 1 million tonnes/year of LNG from the Plaquemines LNG export facility in Plaquemines Parish, La. (OGJ Online, Oct. 16, 2019).

Under the 20-year agreement, EDF will purchase LNG on a free on board basis for a 20-year term starting from the commercial operation date of the Venture Global Plaquemines LNG export facility. Plaquemines LNG plans to begin commercial operations of Phase 1 in late 2022 and Phase 2 in 2023.

The project has received its final authorizations from both the US Federal Energy Regulatory Commission and the US Department of Energy.

Inpex lets marine survey contract for Abadi LNG project 

Inpex Masela Ltd., a subsidiary of Inpex Ltd., Tokyo, has let a marine survey contract to Fugro for the Abadi LNG project in eastern Indonesia (OGJ Online, Oct. 11, 2019).

Fugro will perform geophysical and geotechnical surveys and the associated studies needed to support front-end engineering design (FEED) for offshore production facilities and the submarine pipeline to the onshore LNG terminal. Geo-data will be acquired using Fugro’s deepwater autonomous underwater vehicle Echo Surveyor and their robotic seafloor drill, Seafloor Drill 2, deployed from Indonesian support vessels.

The project, expected to liquefy natural gas from offshore Abadi field, will produce a total output of natural gas (LNG equivalent) of 10.5 million tons/year and up to 35,000 b/d of condensate. The field is in 400-800 m of water on the 2,503-sq-km Masela Block in the Arafura Sea, 150 km offshore Saumlaki, Maluku Province.

Freeport LNG commissioning Train 3 

Freeport LNG Development LP’s liquefaction plant on Quintana Island in Freeport, Tex., has reached final commissioning of its 4.64-million tonne/year (tpy) Train 3 and is introducing feed gas to the unit.

Zachry Group, as Freeport’s contracting joint-venture lead, partnered with McDermott International Inc. for the project’s pre-front end engineering and design (FEED) in 2011, followed by FEED work for Trains 1 and 2. Chiyoda International Corp. joined the joint venture for work related to Train 3. Project scope includes three pre-treatment trains, a liquefaction plant with three trains, a second loading berth, and a 165,000-cu m full containment LNG storage tank.

Freeport LNG Train 3 is on track to reach initial LNG production by end-March 2020, with commercial operations slated for May.

Freeport last year received US Federal Energy Regulatory Commission approval for Train 4 (OGJ Online, May 17, 2019), which will increase total capacity to 20 million tpy. Train 4 is expected to start operations in 2023.