General Interest—Quick Takes
Shell posts quarterly decline in adjusted net income
Royal Dutch Shell PLC reported fourth-quarter earnings on a current cost of supplies basis, excluding identified items, of $2.9 billion, a decrease from the $4.8 billion reported in the year’s third quarter and 49% lower than the $5.7 billion recorded in fourth-quarter 2018.
The decrease, excluding identified items at $2.9 billion, reflected lower realized oil, gas, and LNG prices, weaker realized refining and chemicals margins, as well as negative movements in deferred tax positions compared with the fourth quarter 2018. This was partly offset by stronger contributions from LNG trading and optimization. Following its annual balance sheet review, identified items reflect the impact from impairments in the quarter of $2.2 billion, mainly associated with US natural gas assets.
Integrated gas earnings were $2 billion, down $400 million, reflecting lower realized LNG, oil and gas prices, higher depreciation with several projects ramping-up, partly offset by stronger contributions from LNG, gas and power trading and optimization.
In upstream, earnings were some $800 million, reflecting deferred tax charges, higher charges for provisions related to restoration and decommissioning obligations, lower oil and gas prices, and increased well write-offs.
Cash flow from operations, excluding working capital movements, was $12.3 billion, some $600 million lower than fourth-quarter 2018. In the integrated gas business, cash flow from operations in this year’s fourth quarter was $3.5 billion, some $2.3 billion lower than the year-ago quarter. In the upstream segment, cash flow from operations was $4.2 billion, around $2.7 billion lower than in the same quarter a year ago. In the downstream business, cash flow from operations was $2.3 billion, some $6.5 billion lower than in fourth-quarter 2018.
Valero Energy makes officer promotions
Valero Energy Corp. has approved officer promotions, effective Jan. 23.
Lane Riggs has been promoted and elected president of Valero and will hold the title of president and chief operating officer, reflecting the expansion of his responsibilities to also include renewables and logistics operations.
Gary Simmons has been promoted and elected executive vice-president and chief commercial officer. Gary has lead Valero’s commercial organization since 2014. He will continue in his new role with oversight of the company’s crude supply and products trading, wholesale marketing, transportation, and international commercial operations groups.
Eric Fisher has been promoted and elected senior vice-president of wholesale marketing and international commercial operations.
Gazprom, Petrobangla sign MOU
Vitaly Markelov, deputy chairman of the Gazprom Management Committee, and Syed Ashfaquzzaman, corporate secretary and member of the board of Bangladesh's state oil firm Petrobangla, signed a 5-year Memorandum of Understanding Jan. 29 for strategic cooperation.
The MOU comes after a working meeting headed by Mrkelov Sheikh Hasina, Prime Minister of the People's Republic of Bangladesh. The parties discussed the prospects of cooperation in the energy sector.
Gazprom's interests in Bangladesh are represented by Gazprom EP International BV. The company’s main partner in Bangladesh is Petrobangla.
In 2012 and 2015, Gazprom EP International and Petrobangla signed contracts to build exploratory and development wells at gas fields in Bangladesh. In 2017, a contract was signed to construct two prospecting and exploration wells on Bhola Island in the south of Bangladesh.
Since 2012, Gazprom EP International has designed and built 17 appraisal, exploration, and development wells at eight fields in Bangladesh. The total flow rate of these wells has reached 7 billion cu m/year of gas.
Exploration & Development—Quick Takes
Shell, Ecopetrol to develop gas province in Colombian Caribbean
Shell, through its subsidiary Shell EP Offshore Ventures Ltd., expects to drill an appraisal well in the deepwater Caribbean Sea offshore Colombia by the end of 2021 subject to government approval of an agreement to acquire a 50% stake in Fuerte Sur, Purple Angel, and COL-5 blocks in Sinu basin from Ecopetrol SA. Shell will assume operatorship.
In 2017, Gorgon-1 and Purple Angel-1 confirmed the extension of the gas reservoir discovered with Kronos-1 in 2015 (OGJ Online, July 30, 2015) The Gorgon discovery proved gas presence on a structured located in the same geological trend of the Kronos field, in zones with depths of 3,675-4,415 m below average sea level. Gorgon-1 is part of the Purple Angel block, which borders Fuerte Sur blocks (where Kronos-1 was discovered).
The confirmation of gas fields in the area opens the possibility for Colombia to develop a gas production specialized "cluster,” which would allow for sharing facilities and improving projects' profitability and efficiency, Ecopetrol said at the time.
An April 2019 regulatory filing showed that, by December 2018, Ecopetrol has increased its participation to 100% from 50% in Fuerte Sur and Purple Angel blocks after they were relinquished by Anadarko Petroleum Corp. Block Col-5, the National Hydrocarbon Agency (ANH) approved the conversion of a Technical Evaluation Agreement to an Exploration and Production Contract, where the company holds 100% interest.
Following the commercial agreement, which includes the financing of Ecopetrol's investments by Shell, the discoveries could be further developed if the activities provide positive results, expanding the country's gas supply in the medium term, potentially exceeding 3 tera cu ft, Ecopetrol said.
The agreement is subject to approval by the ANH and fulfillment of customary transaction conditions.
Parex, Frontera evaluate options post Colombia discovery
Parex Resources Inc., Calgary, and Frontera Energy Corp., Toronto, will evaluate options to drill one or two additional delineation wells in the VIM-1 block in the Lower Magdalena Valley in Colombia following a recent discovery.
The La Belleza-1 exploration well, drilled to 11,680 ft TD, encountered 179 ft total MD (155 ft total vertical depth) of potential hydrocarbon bearing reservoir in the Cienaga De Oro formation, Frontera said in a release Feb. 6.
The well was tested under natural flowing conditions over a 328-hr period and produced 32,728 bbl of 43° API oil, 147 MMcf of natural gas and 3,996 bbl water. The average flow rate during the test was 2,395 b/d and 10.7 MMcf/d (4,272 boe/d combined) at an average water cut of 12%. The flow rate during the final 24-hr of the test was 2,696 b/d and 11.8 MMcf/d (4,766 boe/d combined) at an average watercut of 10%.
The initial shut-in wellhead pressure was 4,700 psi. Wellhead pressure during the test remained relatively flat at 3,700 psi. The producing rate was limited by the test facilities on location. Bottom hole flowing pressures remained relatively stable at about 6,000 psi indicating an average drawdown of 14%. The initial bottom hole pressure was 7,031 psi and the final extrapolated pressure after the 174-hr buildup was 7,011 psi. The well will be flow tested for one additional week followed by an extended 30-day pressure buildup period which will provide additional information on the final reservoir pressure.
Additional wells, to be drilled from the existing La Belleza well pad, are expected in this year’s second half. The partners are also evaluating different options for gas commercialization and infrastructure requirements.
Parex Resources is operator of the block with 50% interest. Frontera holds the other 50%.
Also in the Lower Magdalena Valley, Frontera spud the Asai-1 exploration well in the Guama block where it is operator with 100% interest. The company is targeting oil, natural gas condensate, and natural gas in the Porquero formation at 12,000 ft. The well is expected to take 75 days to drill with results expected in May.
GeoPark makes gas discovery in Chile
GeoPark Ltd., Santiago, reported a gas field discovery in the Fell Block in Chile's Tierra del Fuego region. Part of the Dicky geological structure in the block, Jauke Oeste field opens the potential for multiple development drilling opportunities, the company said (OGJ Online, Aug. 20, 2018).
The Jauke Oeste 1 exploration well was drilled to 9,596 ft TD. A production test, through different choke sizes, in the Tobifera formation resulted in an average production rate of 4.4 MMscfd of gas (729 boe/d) and 52 bo/d of condensate with a wellhead pressure of 3,141 psi. Additional production history is required to determine stabilized flow rates of the well and the extent of the reservoir, the company said.
Surface facilities are in place, the well is in production, and the gas and condensate are being sold to offtakers.
Jauke Oeste lies about 1 km north of Jauke gas field, which is currently producing 8.4 MMscfd from two wells (1,400 boe/d). Jauke and Jauke Oeste gas fields are part of the Dicky geological structure in the block, opening the potential for multiple development drilling opportunities, GeoPark said.
Additional exploration activities with a focus on oil prospects will be carried out in Chile in this year’s first quarter. The company will spud the Leun 1 exploration well in the Flamenco Block (GeoPark operated, 100%) in February, to be followed by the Huillin 1 exploration well in the Isla Norte Block (GeoPark operated, 60%), and the Koo 1 exploration well in the Campanario Block (GeoPark operated, 50%).
GeoPark is operator of the Fell block with 100% interest.
Drilling & Production—Quick Takes
Badin IV South Block begins commercial production
Jura Energy Corp., Calgary, said commercial production from the Ayesha, Aminah, and Ayesha North leases in the Badin IV South Block in the Sindh Province of Pakistan has begun following successful testing and commissioning of production facilities.
Badin IV South Block lies in the Lower Indus basin or Badin sub-basin. The discovery well, Ayesha-1 drilled in early 2014, found commercial accumulation of gas and condensate in the Lower Goru 'A' and 'B' sands. The exploratory efforts during 2015 and early 2016 resulted in gas and condensate discoveries in the Lower Goru Upper Sands at Aminah-1 and Ayesha North-1 wells (OGJ Online, Mar. 7, 2016).
Current production from the leases comprises 22 MMcf/d (net to Jura 6.05 MMcf/d) of conventional natural gas (CNG) and 174 bbl/d (net to Jura 46.85 Bbl/d) of natural gas liquids (NGLs) at an average NGL yield of 7.90 bbl/MMcf.
CNG production from the leases is being sold to Sui Southern Gas Co. Ltd. NGLs production is sold directly to refineries in Pakistan.
Petroleum Exploration (Pvt.) Ltd. is operator of the block. Jura Energy holds 27.5% interest.
TransGlobe details 2020 drilling program
TransGlobe Energy Corp., Calgary, expects to spend $37.1 million for a 2020 drilling program that includes 16 wells in Egypt wells four wells in Canada.
Average production in 2020 is expected to be 14,500-15,500 boe/d with a midpoint of 15,000 boe/d, with Egypt expected to produce 11,900-12,700 boe/d and Canada expected to produce 2,600–2,800 boe/d. Production in 2019 averaged 16,000 boe/d for the year.
In Egypt, the company expects to spend $23.7 million this year on 12 development wells and four exploration wells, principally focused on the Eastern Desert. The program has $5.4 million (23%) allocated to exploration and $18.3 million (77%) to development.
Development wells include four wells in West Bakr, one Red Bed appraisal well in the NW
Exploration wells include one well in West Bakr, two wells in NW Gharib in the East Desert, and one well in South Ghazalat in the Western Desert.
Gharib 3X pool, six wells targeting the Arta Nukul reservoir in West Gharib and NW Gharib, and a single well in the SGZ-6X pool, targeting the lower Bahariya reservoir in the Western Desert.
Additional activity for 2020 involves ten recompletions in West Bakr, four recompletions in West Gharib, water handling expansion at West Bakr, and development/ maintenance projects in the Eastern Desert (West Bakr, NW Gharib, and West Gharib). Negotiations continue with the Egyptian government to amend, extend, and consolidate the company’s Eastern Desert concession agreements.
In Canada, $13.4 million is earmarked for a 2020 drilling program of four horizontal, multi-stage stimulated wells targeting the Cardium light oil resource at Harmattan with additional maintenance/development capital.
Hess reports first gas from North Malay Basin Phase II
Hess Malaysia, Kuala Lumpur, started first gas from the Zetung wells in Phase II of the North Malay Basin (NMB) integrated gas development project in Malaysia. Phase II includes development of Zetung and Anggerik fields south of the Bergading Central Processing Platform 300 km offshore, and installation of a three-legged terminal wellhead platform with associated pipelines. Anggerik wells are expected to come onstream in April.
Phase I comprised an early production system and full-field development which achieved first gas in 2013 and 2017, respectively. Hess earlier this year sanctioned Phase 3 with first gas planned for fourth-quarter 2021.
NMB is a long-life natural gas asset comprised of nine discovered natural gas fields with an estimated gross recoverable resource of more than 1.5 tcf natural gas and more than 20 million bbl condensate.
In January, the company said $170 million of its 2020 budget is allocated for production activities at NMB and the Malaysia/Thailand joint development area in the Gulf of Thailand (OGJ Online, Jan. 28, 2020).
Hess Malaysia, a subsidiary of Hess Corp. is operator of NMB with 50% interest. Partner is Petronas Carigali Sdn Bhd with 50%.
Processing—Quick Takes
ADNOC lets contracts for Abu Dhabi gas mega project
Abu Dhabi National Oil Co. (ADNOC) has let two contracts to Petrofac Ltd. subsidiary Petrofac Emirates LLC and a joint venture of Petrofac and Sapura Energy Bhd. to provide engineering, procurement, and construction (EPC) for ADNOC’s Dalma gas development project located 90 km northwest of Abu Dhabi City, UAE, a key part of the Ghasha Concession portfolio of projects encompassing Hail, Ghasha, and Dalma ultra-sour gas fields in the Emirate of Abu Dhabi (OGJ Online, Aug. 15, 2017).
The two EPC contracts, which have a total combined value of more than $1.65 billion, cover EPC services—including novated long-lead items, transportation, offshore installation, and commissioning—for Dalma gas field development, as well as offshore packages at Arzanah island and surrounding offshore fields about 140 km off Abu Dhabi’s northwest coast, ADNOC and Petrofac said in separate Feb. 18 releases.
As part of the first $1.065-billion, 33-month, lump-sum contract, Petrofac will provide EPC services for gas processing installations at Arzanah island, including inlet facilities with gas processing and compression units, power generation units, utilities, and other associated infrastructure, the service provider said.
Under the second 30-month, lump-sum contract—valued at $591 million—the Petrofac-led JV with Sapura Energy will deliver EPC services for three new wellhead platforms, removal and replacement of an existing topside, new pipelines, subsea umbilicals, composite, and fiberoptic cables, according to Petrofac.
Scheduled to be completed in 2022, work under both contracts will enable the Dalma gas development project—which is central to ADNOC’s strategic objective of enabling the UAE’s gas self-sufficiency—to produce around 340 MMcfd of natural gas, ADNOC said.
The Hail, Ghasha, and Dalma ultrasour gas development project will tap into the Arab basin, which is estimated to hold multiple trillions of standard cubic feet of recoverable gas, according to ADNOC’s web site. More than 120,000 b/d of oil and condensates also are expected to be produced when the project is fully on stream.
ADNOC most recently let a contract to KBR Inc. to provide project management consultancy (PMC) services for the Ghasha Concession portfolio of projects (OGJ Online, Feb. 3, 2020).
Linde starts units to support Texas petrochemical plant
Linde PLC has commissioned a new air separation unit (ASU) in Freeport, Tex., as part of a long-term agreement to supply MEGlobal Americas Inc.’s new monoethylene glycol (MEG) plant at Dow Chemical Co.’s Oyster Creek petrochemical complex in Freeport (OGJ Online, Oct. 14, 2019).
Alongside supplying oxygen and nitrogen to MEGlobal Oyster Creek for use in its MEG manufacturing process, the new ASU also will supply Linde's industrial gas pipeline system, adding new argon capacity, Linde said.
In addition to the ASU, Linde started a new carbon dioxide (CO2) plant in Freeport that will recycle crude CO2 supplied from an unidentified MEGlobal process.
The crude CO2 will be purified and liquefied into commercial grades to serve customers in a variety of industries, including food and beverage, where it is used to carbonate drinks, as well as to freeze, chill, preserve, and package food, the service provider said.
"The new ASU and the expansion of our [US] Gulf Coast pipeline system further strengthen Linde's ability to reliably supply customers throughout the region and positions us for future growth in the USGC," said Jeff Barnhard, Linde’s vice-president for the US South region.
The service provider disclosed no details regarding capacities of either the ASU or CO2 plant.
MEGlobal Americas—a subsidiary of Equate Petrochemical Co. of Kuwait’s Dubai-based MEGlobal International FZE—officially began production at its 750,000-tonne/year MEG plant on Oct. 14, 2019, as part of MEGlobal’s program to create greater flexibility to satisfy growing demand for ethylene glycol products in the US and Asia-Pacific markets, as well as its strategy to expand the company’s global footprint (OGJ Online, Sept. 12, 2019).
Equate Petrochemical is an international JV of Kuwait’s state-owned Petrochemical Industries Co., 42.5%; Dow, 42.5%; Boubyan Petrochemical Co., 9%; and Qurain Petrochemical Industries Co., 6%.
BPGIC proposes storage, refining expansions at Fujairah
Brooge Holdings Ltd. subsidiary Brooge Petroleum & Gas Investment Co. FZC (BPGIC) has signed a land lease agreement with Fujairah Oil Industrial Zone (FOIZ) for additional land on which BPGIC plans to expand its crude oil storage and refining operations in Fujairah, UAE, near the East coast port of Fujairah on the Gulf of Oman.
As part of the agreement, BPGIC will lease a strategically located and prime plot of land with a total area of about 450,000 sq m for its proposed Phase 3 expansion of operations that, if completed, would make BPGIC the largest oil storage and service provider in Fujairah, BPGIC said in a series of posts to its official Twitter account as well as a separate news release.
“We are thrilled to announce that we have secured a lease for this strategic and sizeable plot of land in [FOIZ], which can accommodate additional capacity of over [three and a half] times our facilities currently operating and under construction. When the Phase 3 expansion is completed, we expect to become the largest oil storage and service provider in the increasingly important FOIZ [and] port of Fujairah,” said Nicolaas Paardenkooper, chief executive officer of both Brooge Holdings and BPGIC.
BPGIC plans to use the additional land to expand its storage and refining capacity to complement installations built at part of the Phase 1 and Phase 2 developments at the site, which following Phase 2’s completion, will total 1 million cu m of storage.
BPGIC’s initial studies indicate that the newly leased land could accommodate up to about 3.5 million cu m of storage tanks, as well as a potential refinery with a capacity of up to 180,000 b/d.
Currently in discussions with potential collaborators that include several top global oil majors who have expressed interest in collaborating on the expansion, BPGIC said it also has a signed memorandum of understanding (MOU) in place for the Phase 3 development. The operator, however, revealed no further details regarding the MOU.
Last year, BPGIC announced it was building a 250,000-b/d refinery at Fujairah designed to produce bunker fuel that would become the first plant of its kind in the Middle East and North Africa to comply with the International Marine Organization’s (IMO) new regulations requiring ships to use marine fuels with a sulfur content below 0.5% (OGJ Online, May 13, 2019).
While the first phase of BPGIC’s proposed refinery was scheduled to be completed by first-quarter 2020, the operator has yet to confirm official commissioning of the plant.
Transportation—Quick Takes
Kosmos inks Greater Tortue LNG deal with BP
Kosmos Energy, Dallas, signed a contract with BP Gas Marketing Ltd., a subsidiary of BP Plc, for the supply of 2.45 million tonnes/year (mtpy) of LNG from Phase 1 of the Greater Tortue Ahmeyim natural gas project offshore Mauritania and Senegal for an initial 20-year term.
The Greater Tortue Ahmeyim Phase 1 development was sanctioned in December 2018 (OGJ Online, Dec. 21, 2018). The project will produce gas from a deepwater subsea system and mid-water floating production, storage, and offloading vessel to a 2.5-million mtpy floating LNG unit at a nearshore hub on the Mauritania and Senegal maritime border. Kosmos estimates total recoverable gas in the field at around 15 tcf.
The project will provide LNG for export, as well as make gas available for domestic use in both Mauritania and Senegal. First gas for the project is expected first-half 2022.
Following signing of the agreement, Kosmos intends to book net proved reserves of 100 MMboe associated with Phase 1, as evaluated by reserve auditor Ryder Scott Co. LP.
Tortue Ahmeyim field development is on the C-8 block offshore Mauritania and the Saint-Louis Profond block offshore Senegal. BP operates Tortue with 61%. Partners are Kosmos 29%, Senegal-state Petrosen 5%, and Mauritania state firm SMHPM 5%.
Rio Grande LNG receives non-FTA export authorization
NextDecade Corp. received an order from the US Department of Energy granting authorization to export LNG from its Rio Grande LNG facility at the Port of Brownsville in South Texas to non-free trade agreement (non-FTA) countries.
In combination with a free trade agreement (FTA) order previously issued in August 2016, NextDecade is now authorized to export LNG equivalent to 1,318 bcf/year of natural gas from Rio Grande LNG to both FTA and non-FTA countries.
The 27 million-tonne/year Rio Grande LNG project will consist of three liquefication trains, two 180,000-cu m storage tanks, and two marine berths to link natural gas from the Permian Basin and Eagle Ford Shale to the global LNG market. There is an opportunity to build an additional storage tank and LNG truck loading facilities.
In November 2019, FERC issued an order authorizing the siting, construction, and operation of Rio Grande LNG and the associated Rio Bravo Pipeline (OGJ Online, Nov. 21, 2019). On January 23, FERC issued its final order denying rehearing requests on Rio Grande LNG and Rio Bravo Pipeline.
Qatargas delivers commissioning cargo to Mundra terminal
Qatargas Operating Co. Ltd. (Qatargas) supplied a commissioning LNG cargo for India's newest LNG receiving terminal, Mundra, on the west coast of India. The cargo was loaded in Ras Laffan on Jan. 17, on the Q-Flex LNG vessel, Murwab, with an overall cargo carrying capacity of 216,000 cu m. It arrived at Mundra terminal on Jan. 22.
Mundra is the second LNG terminal Qatargas helped commission in India within the past year. It followed an earlier commissioning cargo delivered to the Ennore LNG receiving terminal near the southern Indian city of Chennai in February 2019 (OGJ Online, Mar. 7, 2019).
The 5-million tonne/year capacity LNG import terminal in Gujarat, India, can receive vessels with a capacity of 75,000-260,000 cu m. The terminal is comprised of two storage tanks–each with an overall capacity of 160,000 cu m.