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UKRAINE OFFERS NEW PSAS IEA UPDATES EOR PROJECTS, OUTPUT IMPROVING NAPHTHA CRACKING MARCELLUS-UTICA OPTIONS
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DistNow_OGJ_190304 1 2/18/19 10:50 AM 190304OGJc1-c5.indd 2 2/26/19 3:09 PM CONTENTS Mar. 4, 2019 Volume 117.3
GENERAL INTEREST SPECIAL REPORT CAPITAL SPENDING UPDATE IEA: Crude oil quality matters amid lower supply Growth of US upstream 26 spending to decelerate in 2019 Conglin Xu Queensland’s CSG-LNG plants unlikely to reach full capacity 20 Rick Wilkinson 27 Capital investment continues BP lets rig contract for Ironbark wildcat to increase in Latin America off Western Australia Siddhartha Sen Rick Wilkinson 28 24 APLNG to buy Ironbark coal seam gas prospect from Origin Energy Rick Wilkinson 28
Aramco forms combine for $10-billion Chinese refining complex Robert Brelsford 29
Meridian Energy plots grassroots refinery for Permian basin Robert Brelsford 29 REGULAR FEATURES INTRODUCING NAPE: Croatia opens licensing round in NEWSLETTER 6 Dinarides onshore area LETTERS/CALENDAR 12 OIL & GAS Paula Dittrick JOURNALLY SPEAKING 16 30 EDITORIAL 18 COMMUNITY, MAR. 4, 2019 | USD 15 COVER SERVICES/SUPPLIERS 56 an Oil & Gas Journal online
International Petroleum News and Technology | www.ogj.com Devon Energy Corp. plans by yearend to sell STATISTICS 58 service enabling you to CAPITAL SPENDING UPDATE or spin-off its heavy oil properties in Canada MARKET CONNECTION 61 comment on articles, US OLEFINS and gas production in the Barnett shale to ADVERTISERS INDEX 63 communicate with OGJ focus on US oil. The moves will help Devon EDITOR’S PERSPECTIVE/ editors, and meet meet a cost-cutting target of at least $780 specialists in your field. WATCHING GOVERNMENT 64 million/year by 2021. Concentrating on US
UKRAINE OFFERS NEW PSAS IEA UPDATES EOR PROJECTS, OUTPUT oil, Devon expects to achieve production For instructions and to sign IMPROVING NAPHTHA CRACKING MARCELLUS-UTICA OPTIONS growth of 13-18% in 2019 with 10% less up, go to upstream capital than in 2018, self-funded www.ogj.com/ at an oil price of $46/bbl if service and sup- oilandgascommunity. ply prices don’t increase. Photo from Devon Energy.
190304OGJ001-005.indd 1 2/28/19 12:22 PM MARCH 5–7, 2019 | SAN ANTONIO, TX USA HENRY B. GONZALEZ CONVENTION CENTER | WWW.SUBSEATIEBACKFORUM.COM
Owned & Presented by: Supported by: Hosted by: Produced by:
SSTBDev_Petro_180219 1 2/19/18 2:55 PM 190304OGJ001-005.indd 2 2/28/19 12:22 PM UKRAINE LICENSING ROUNDS FIG. 1
BELARUS POLAND Dnipro-Donets basin
RUSSIA US NGPL PRODUCTION FIG. 1 Pre-Carpathian basin 2017 7 Kharkiv History Projections Lviv UKRAINE 6Rollava Ivano- Frankivsk 5 East Carpathian MountainsChernivtsi 4 Southwest MOLDOVA 3 Million b/d 2019 PSAs 2019 licenses Kherson 2 North Black Sea basin31 Valid contracts:* 49 Other US Exploration Odessa 1 ROMANIA Black Sea Azov Sea E&P Production T E C H N O L O G Y . . . 0 PSA 2000 2010 2020 2030 2040 2050 *Exploration licenses cover 5 years onshore, 10 years offshore, combined E&P licenses cover 20 years onshore, 25 years offshore, productionSource: licenses US cover Energy 20 Information years. Administration Source: GoUkraineNow
EXPLORATION & DEVELOPMENT DRILLING & PRODUCTION PROCESSING TRANSPORTATION Ukraine outlines latest IEA updates EOR project US olefins industry turns US DOE details concessions, production- data, doubling output to face global market Marcellus-Utica sharing agreements forecast Dan Lippe ethane, petrochemical Roman Opimakh 34 36 options 31 49 In-depth phase characterization improves naphtha cracker emulsion breaking Fabrice Cuoq Jérôme Vachon 44
MARCH 5–7, 2019 | SAN ANTONIO, TX USA HENRY B. GONZALEZ CONVENTION CENTER | WWW.SUBSEATIEBACKFORUM.COM
Owned & 44 Presented by: Supported by: Hosted by: Produced by:
SSTBDev_Petro_180219 1 2/19/18 2:55 PM 190304OGJ001-005.indd 3 2/28/19 12:22 PM HRM FOR THE OIL & GAS INDUSTRY OGJ® In Houston Steven Tobias Hess Corp., Houston Shree Vikas ConocoPhillips Co., Houston Vice President and Group Publisher Clark White Targa Resources Inc., Houston Paul Westervelt, [email protected] Colin Woodward Woodward International Ltd., Durham, UK Editor Bob Tippee, [email protected] Managing Editor-News Steven Poruban, Editorial Offices [email protected] Managing Editor-Technology Christopher E. Oil & Gas Journal Smith, [email protected] 1455 West Loop South, Suite 400, Upstream Technology Editor Paula Dittrick, Houston, TX 77027 [email protected] Tel 713.621.9720; Fax 713.963.6285 Downstream Technology Editor Robert Brelsford, www.ogjonline.com [email protected] Senior Editor-Economics Conglin Xu, Corporate Officers [email protected] President and Chief Executive Officer Editor-News Mikaila Adams Mark C. 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GENERAL INTEREST QUICK TAKES Greater Brae Area, and MOWOS holds a 28% interest in the BP PLC-operated Foinaven field unit and 47% in Foinaven Court nixes challenge to Alberta export bill East. The deal includes interests in the SAGE, Brae-Forties, and The government of British Columbia has received a setback WASPS infrastructure. At yearend 2018, Marathon Oil carried to its challenge of legislation that would empower the Alberta 21.4 million boe of proved reserves in the UK. Anticipated pro- energy minister to require licenses for the transport of energy duction is 13,000 boe/d in 2019, taking RockRose’s total net away from the province (OGJ Online, May 23, 2018). anticipated production to 24,000 boe/d for the year. Because the bill has not become law, BC’s claim is “prema- Subject to adjustments, closing consideration payable to Mar- ture and inappropriate for consideration by the court,” a Cal- athon Oil will be $140 million, which reflects the assumption gary justice ruled. by RockRose of MOUK and MOWOS working capital and cash The Alberta General Assembly passed the legislation last equivalent balances of some $350 million as of Dec. 31, 2018. May in response to BC opposition to the expansion by Kinder The MOUK and MOWOS assets and teams in Aberdeen, Pe- Morgan of the Trans Mountain Pipeline between Edmonton terhea, and offshore will transfer with MOUK and MOWOS to and Burnaby, BC. Since then, the Canadian government has RockRose upon the deal’s completion—expected in this year’s acquired the Trans Mountain system and expansion project. second half with an effective date of Jan. 1.
Targa divests Badlands assets for $1.6 billion Devon to shed assets, focus on US oil Targa Resources Corp., Houston, agreed to sell a 45% inter- Devon Energy Corp. plans by yearend to sell or spin off its est in Targa Badlands LLC, the entity that holds Targa’s North heavy oil properties in Canada and gas production in the Bar- Dakota oil and gas assets, to funds managed by GSO Capital nett shale to focus on US oil. The company has hired advisors Partners and Blackstone Tactical Opportunities for $1.6 billion for each group of assets to be separated. It will open data rooms A COMPANY in cash. Targa will continue to operate and hold majority rights. by this year’s second quarter. The Badlands assets and operations, in the Bakken and In Canada, Devon in 2017 produced 131,000 boe/d net to its Three Forks shale plays of the Williston basin, include some interests (98% liquids) via steam-assisted gravity drainage in 480 miles of oil gathering pipelines, 125,000 bbl of operational the Athabasca region of Alberta and cold flow in Saskatchewan. oil storage, about 260 miles of gas gathering pipelines, and the Its average 2017 net production from the Barnett shale of DEDICATED Little Missouri gas processing plant with a current gross pro- North Texas was 153,000 boe/d, of which 27% was liquids. cessing capacity of 90 MMcfd. Additionally, Badlands owns a The moves will help Devon meet a cost-cutting target of by DESIGN 50% interest in the 200 MMcfd Little Missouri 4 Plant antici- at least $780 million/year by 2021. Concentrating on US oil, pated to be completed in this year’s second quarter. Devon expects to achieve growth of 13-18% in 2019 with 10% Future growth capital is expected to be funded on a pro rata less upstream capital than in 2018, self-funded at an oil price of As the industry leader in compression, Ariel offers basis. Badlands will pay a minimum quarterly distribution to $46/bbl if service and supply prices don’t increase. design innovations inspired by our deep-rooted Blackstone and to Targa based on their initial investments, and The company’s core properties in the Delaware basin and commitment to our customers. Our engineers have Blackstone’s capital contributions will have a liquidation prefer- Eagle Ford play of Texas, STACK play in Oklahoma, and Pow- listened to partners in the field for over half a century, ence upon a sale of Badlands. der River basin of Wyoming produced an average 296,000 and the result is unrivaled quality. boe/d of oil and gas in the fourth quarter last year. RockRose Energy to buy Marathon Oil’s UK business Marathon Oil Corp. will exit the UK with a sale of its UK busi- QEP reviews options after Williston deal falls through nesses Marathon Oil UK LLC (MOUK) and Marathon Oil West QEP Resources Inc., Denver, has started a comprehensive re- of Shetland Ltd. (MOWOS) to RockRose Energy PLC to further view of strategic alternatives that could result in a merger or concentrate on its high margin, high return US resource plays. sale of the company or its assets and intends to engage in dis- MOUK holds a 37-40% operated interest in fields in the cussions with parties that have expressed interest, including
6 Oil & Gas Journal
ArielCor_OGJ_190304 1 2/11/19 10:50 AM 190304OGJ006-011.indd 6 2/28/19 12:22 PM A COMPANY DEDICATED by DESIGN
As the industry leader in compression, Ariel offers design innovations inspired by our deep-rooted commitment to our customers. Our engineers have listened to partners in the field for over half a century, and the result is unrivaled quality.
ArielCor_OGJ_190304 1 2/11/19 10:50 AM 190304OGJ006-011.indd 7 2/28/19 12:22 PM ICE BRENT / NYMEX LIGHT SWEET CRUDE $/bbl US INDUSTRY SCOREBOARD — 3/4 67.00 65.00 4 wk. 4 wk. avg. Change, YTD YTD avg. Change, 63.00 Latest week 2/15 average year ago1 % average1 year ago1 % 61.00 59.00 Product supplied, 1,000 b/d 57.00 Motor gasoline 9,021 9,054 (0.4) 8,907 8,920 (0.1) 55.00 Distillate 4,195 4,139 1.4 4,225 4,143 2.0 53.00 Jet fuel 1,600 1,636 (2.2) 1,609 1,661 (3.1) Feb. 20 Feb. 21 Feb. 22 Feb. 25 Feb. 26 Residual 253 309 (18.1) 266 285 (6.7) Other products 5,553 5,508 0.8 5,725 5,660 1.1 TOTAL PRODUCT SUPPLIED 20,622 20,646 (0.1) 20,732 20,669 0.3 WTI CUSHING / BRENT SPOT Supply, 1,000 b/d $/bbl Crude production 11,925 10,178 17.2 11,902 10,007 18.9 67.00 NGL production 4,576 4,033 13.5 4,581 4,007 14.3 65.00 Crude imports 6,990 7,808 (10.5) 7,318 7,852 (6.8) 63.00 Product imports 2,066 2,237 (7.6) 2,127 2,113 0.7 Other supply2 2,429 2,374 2.3 2,434 2,273 7.1 61.00 TOTAL SUPPLY 27,986 26,630 5.1 28,362 26,252 8.0 59.00 Net product imports (2,961) (2,508) — (2,825) (2,729) — 57.00 55.00 Refining, 1,000 b/d 53.00 Feb. 20 Feb. 21 Feb. 22 Feb. 25 Feb. 26 Crude runs to stills 16,144 15,673 3.0 16,630 16,282 2.1 Input to crude stills 16,400 16,619 (1.3) 16,909 16,639 1.6 % utilization 88.2 89.5 — 90.9 89.6 — NYMEX NATURAL GAS / SPOT GAS - HENRY HUB Latest Previous Same week Change, Latest week 2/15 week week1 Change year ago1 Change % $/MMbtu 2.980 Stocks, 1,000 bbl 2.930 Crude oil 454,512 450,840 3,672 423,498 31,014 7.3 2.880 Motor gasoline 256,847 258,301 (1,454) 251,817 5,030 2.0 2.830 Distillate 138,683 140,200 (1,517) 137,985 698 0.5 2.780 Jet fuel–kerosine 43,365 42,113 1,252 43,068 297 0.7 2.730 Residual 29,411 30,305 (894) 32,056 (2,645) (8.3) 3 2.680 Stock cover (days) Change, % Change, % 2.630 Feb. 20 Feb. 21 Feb. 22 Feb. 25 Feb. 26 Crude 28.2 27.4 2.9 26.0 8.5 Motor gasoline 28.5 28.6 (0.3) 27.5 3.6 Distillate 33.1 32.5 1.8 33.6 (1.5) ICE GAS OIL / NYMEX ULSD HEATING OIL2 Propane 31.1 34.7 (10.4) 25.6 21.5 4 Change Change Change,% ¢/gal Futures prices 2/22 202.00 200.00 Light sweet crude ($/bbl) 56.81 53.88 2.93 62.48 (5.67) (9.1) 198.00 Natural gas, $/MMbtu 2.68 2.62 0.06 2.63 0.04 1.7 196.00 194.00 1Based on revised figures. 2Includes other liquids, refinery processing gain, and unaccounted for crude oil. 3Stocks divided by aver- 192.00 age daily product supplied for the prior 4 weeks. 4Weekly average of daily closing futures prices. 190.00 Source: US Energy Information Administration, Wall Street Journal 188.00 Feb. 20 Feb. 21 Feb. 22 Feb. 25 Feb. 26 BAKER HUGHES INTERNATIONAL RIG COUNT: TOTAL WORLD / TOTAL ONSHORE / TOTAL OFFSHORE 2,400 PROPANE - MT. BELVIEU / BUTANE - MT. BELVIEU 2,260 2,100 ¢/gal 1,997 85.50 1,800 85.00 84.50 1,500 84.00 1,200 72.00 71.00 300 264 70.00 0 69.00 Jan. 18 Feb. 18 Mar. 18 Apr. 18 May 18 Jun. 18 Jul. 18 Aug. 18 Sept. 18 Oct. 18 Nov. 18 Dec. 18 Jan. 19 Feb. 20 Feb. 21 Feb. 22 Feb. 25 Feb. 26 Note: Monthly average count
3 4 BAKER HUGHES RIG COUNT: US / CANADA NYMEX GASOLINE (RBOB) / NY SPOT GASOLINE 1,100 1,047 978 ¢/gal 1,000 166.00 900 164.00 800 162.00 700 160.00 600 158.00 400 306 156.00 300 212 154.00 200 100 152.00 1 Feb. 20 Feb. 21 Feb. 22 Feb. 25 Feb. 26 0 12/8/17 12/22/17 1/5/18 1/19/18 2/2/18 2/16/18 12/7/18 12/21/18 1/4/19 1/18/19 2/1/19 2/15/19 1Not available 2Ultra-low sulfer diesel 3Reformulated gasoline blendstock for 12/15/17 12/29/17 1/12/18 1/26/18 2/9/18 2/23/18 oxygen blending 4Nonoxygenated regular unleaded 12/14/18 12/28/18 1/11/19 1/25/19 2/8/19 2/22/19 Note: End of week average count
8 Oil & Gas Journal | Mar. 4, 2019
190304OGJ006-011.indd 8 2/28/19 12:22 PM Elliott Management Corp. The hedge fund manager made an with 25% ownership reserved for Thai state enterprises, the unsolicited cash offer to buy QEP for $8.75/share in January. Bangkok Post reported. Also, given the deterioration in commodity prices, QEP said Jirapongphan spoke at the signing by PTTEP Energy Devel- that it was unlikely to meet conditions to close the $1.7-bil- opment Co. Ltd. of PSCs covering Erawan and Bongkot natural lion deal to sell its Willison basin assets to Vantage Acquisi- gas fields in the Gulf of Thailand. tion Operating Co. LLC and the parties agreed to terminate the Those contracts became available as concession expirations transaction (OGJ Online, Nov. 7, 2018). QEP will continue to approached for Erawan in 2022 and Bongkot in 2023 (OGJ On- operate and develop the assets consisting of more than 100,000 line, Dec. 14, 2018). net acres currently producing 46,000 boe/d (67% oil, 83% liq- PTTEP is the current Bongkot operator and will be sole uids), including the company’s South Antelope and Fort Ber- stakeholder. It will replace a Chevron Corp. subsidiary as thold leaseholds. Erawan operator with a 60% interest. Mubadala Petroleum As the firm has reduced its operational footprint over the holds the remaining Erawan interest. last year, QEP said it intends to reduce its general and adminis- The Thai company has committed to holding production at trative expense by about 45%, when comparing 2018 to 2020. 800 MMcfd at Erawan and 700 MMcfd at Bongkot. The 21st licensing round had been scheduled in 2014 but Netherlands becomes a net gas importer was delayed by an economic lull and political instability. The Netherlands became a net importer of natural gas last year Thailand closed its 20th licensing round in 2008. for the first time since the commissioning in 1963 of giant Groningen gas field, production of which is being phased out Contracts let for gas fields off Sarawak by the government. GasTerra, which markets Groningen gas Sarawak Shell Bhd. and Sapura Exploration & Production have for NAM, the ExxonMobil-Shell joint venture that operates the let contracts to McDermott for work related to the linked devel- field, reported the shift in Dutch gas trade in a financial report. opment of three natural gas fields offshore Malaysia. GasTerra said NAM produced 20.1 billion cu m of gas from The Shell unit’s contract covers transportation and instal- Groningen in 2018, 1.5 billion cu m below a ceiling set by the lation of jackets, topsides, and pipelines for Gorek field. The government, which began limiting output several years ago be- Sapura contract is for the same work for Larak and Bakong cause of earthquakes (OGJ Online, Feb. 18, 2015). The govern- fields. McDermott also will fabricate risers and spools under ment last year called for the termination of Groningen output. both contracts. “Safety perception as well as actual safety can only be guar- The fields are on the 4,400-sq-km SK408 production-shar- anteed for the near future in Groningen by fully eliminating ing contract area in the Central Luconia Gas Province in shal- the source of the earthquake risk,” it said in a March 2018 an- low water off Sarawak. The area is 130 km northwest of Miri. nouncement. It set an output cap of 12 billion cu m in 2022, to Each field will have a wellhead platform tied back to an ex- be followed by a phaseout of Groningen production. isting processing facility. Shell, with a 30% interest in the PSC, is development and EXPLORATION & DEVELOPMENT QUICK TAKES production operator for Gorek field. Sapura, with 40%, is devel- opment and production operator for Larak and Bakong fields. ExxonMobil makes gas discovery offshore Cyprus Petronas Carigali holds the remaining SK408 interest. ExxonMobil Corp. announced a natural gas discovery offshore Sapura discovered the fields in Late Miocene carbonate Cyprus in the Eastern Mediterranean on Block 10. The Glau- build-ups during a drilling campaign that began in 2014. cus-1 well cut 436 ft of reservoir rock. Evaluation of the poten- tial of Block 10 continues. The well was drilled to 13,780 ft in DRILLING & PRODUCTION QUICK TAKES 6,769 ft of water. ExxonMobil said preliminary interpretation of the well data indicates gas resources of 5-8 tcf although ad- Woodside-led group lets Senegal SNE field contract ditional analysis will determine resource potential. The Woodside Energy Ltd.-operated development phase of the Glaucus-1 was the second well drilled on Block 10. The first SNE oil field offshore Senegal has let the front-end engineering well, Delphyne-1, did not encounter commercial quantities of hy- and design contract for the floating production, storage, and drocarbons. Block 10 covers 635,554 acres. ExxonMobil Explo- offloading facility to MODEC International Inc. ration & Production Cyprus (Offshore) Ltd. operates the block This follows award of the subsea FEED scope to Subsea In- with 60% interest. Qatar Petroleum International Upstream tegration Alliance last December. Woodside said that following holds the remaining interest. FEED and subject to necessary government and joint venture approvals, it anticipated that further contracts will be awarded Official: Thai licensing round due in June to MODEC to supply, charter, and operate the FPSO facility. Thailand will open its 21st round of bidding for offshore oil CEO Peter Coleman said securing an FPSO facility is a huge and gas licenses in June, according to Energy Minister Siri Ji- step for the joint venture and will allow the project team to rapongphan. The official said terms will be production-sharing complete the technical and commercial activities required to
Oil & Gas Journal | Mar. 4, 2019 9
190304OGJ006-011.indd 9 2/28/19 12:22 PM support a final investment decision, targeted for midyear. It plans to install a flour-slot subsea template and drill two The development concept is a stand-alone FPSO facility oil production wells, one gas producer, and possibly another with 23 subsea wells comprising 11 producers, 10 water injec- oil producer. tors, and 2 gas injectors plus supporting subsea infrastructure. Duva is to produce at a peak rate of 30,000 boe/d from re- The FPSO is expected to have a capacity of about 100,000 coverable resources of 88 million boe. b/d to be brought on stream in 2022. The FPSO will be designed to allow for the integration of sub- Algeria’s Touat gas project on track for exports sequent SNE development phases, including gas export to shore Neptune Energy Group, London, and Algeria’s Sonatrach have and future subsea tie-backs from other reservoirs and fields. started natural gas production as part of the commissioning Phase 1 of the SNE development is targeting an estimated of the partnership’s Touat project in the Sbaa basin, 1,500 km 230 million bbl of oil reserves. southwest of Algiers, near Adrar. The development, which will produce about 450 MMcfd of Equinor lets contract to boost Vigdis field output gas at plateau, remains on track to begin gas export production Norway’s Equinor has let a $13-million engineering, procure- by the end of this year’s first half, Neptune Energy said. ment, construction, and installation contract to Wood for the Touat comprises eight gas fields and a gas processing plant. boosting station to increase production from Vigdis subsea field Project development involved drilling 18 development in the Tampen area on Block 34/7 in the Norwegian North Sea. wells, along with building a road, aircraft runway, living quar- Under the contract, Wood will provide topside modifica- ters, gathering network, and gas treatment complex, as well as tions to enable the tie-in of subsea equipment to the Snorre A installation of a connection to the main GR5 pipeline, built by and B offshore platforms, which process oil from Vigdis. Sonatrach, to collect the gas from southwest Algeria to bring to This contract follows Wood’s completion of the front-end en- Hassi R’Mel, about 800 km north. gineering design and concept study for the asset. Wood currently provides maintenance, modification, and operations services on Aramco lets contracts for Marjan oil field work Snorre A and B under a framework agreement with Equinor. Saudi Aramco has let two contracts to McDermott International In late 2018 Equinor and its partners reported plans to in- Inc. for engineering, procurement, construction, and installa- vest some 1.4 billion kroner in the boosting station for the field, tion services for Marjan oil field offshore Saudi Arabia. Aramco which has been producing oil through Snorre field for more is expanding production capacity of Marjan field, now 500,000 than 20 years (OGJ Online, Dec. 5, 2018). Equinor expects to b/d, by 300,000 b/d. bring the station online in first-quarter 2021. One contract—valued at $50-100 million—is for services On completion of the project, production from Vigdis field for the upgrade of two existing platforms related to the installa- will be increased by almost 11 million bbl. tion of associated equipment for electrical submersible pumps Vigdis field came on stream in 1997 and it was estimated and space for a future high integrity pressure protection sys- at the time that the field would produce 200 million bbl of oil. tem, subsea composite cable lay, and topside cable tie-ins. The field has now produced 394 million bbl and recoverable The project is scheduled to be fully executed from McDer- resources have been increased to 455 million bbl of oil. mott’s Al Khobar office and Dammam fabrication facility. A second contract—valued at $500-700 million—includes Neptune plans Gjoa tie-back developments the design, procurement, fabrication, and installation, testing Neptune Energy and partners plan to develop in parallel Duva oil and precommissioning of the TP-10 tie-in platform, six gas lift and gas field and an extension designated P1 of Gjoa oil and gas topside modules, and associated pipeline and subsea cables. field in the Norwegian North Sea with subsea completions tied The total weight of the structures will exceed 27,000 tonnes back to the Gjoa platform on PL153 (OGJ Online, Oct. 2, 2019). and pipelines totaling more than 65 km. Neptune Energy Norge operates both fields, where water depth is about 360 m. PROCESSING QUICK TAKES It seeks to develop Gjoa P1 under the plan for development and operation (PDO) covering the Gjoa license, for which it is IOC inks term contract for US crude supplies operator, as a northern extension. Neptune said in a news release Indian Oil Corp. Ltd. has finalized a term contract to import as it plans to install a subsea template but didn’t specify drilling. An much as 3 million tonnes/year of crude oil from the US as part image with the news release indicates two oil and one gas well. of the operator’s strategy to diversify its term crude sources. Neptune estimates Gjoa P1 recoverable resources at 32 mil- IOC finalized the contract—valued at $1.5 billion—on Feb. lion boe and expects the extension to produce at a maximum 15, the company said. This is the first term contract for US crude rate of 24,000 boe/d. grades secured by any Indian state-run refining company. Neptune has applied for a PDO for Duva field, formerly IOC did not confirm a duration of the contract or the pro- Cara, on PL636, 6 km northeast of Gjoa field and 12 km north- ducers from which it has secured the term shipments. east of the Gjoa platform. With an overall group refining capacity of more than 1.6
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190304OGJ006-011.indd 10 2/28/19 12:22 PM million b/d, IOC controls 11 of India’s 23 refineries to account project-related marine vessels would be substantial. for a 35% share of total national refining capacity. NEB carried out the reconsideration and met a 155-day dead- line after a federal appeals court cancelled the crude oil and prod- ADNOC Refining lets contract for Ruwais refinery ucts pipeline project’s 2016 authorization last year (OGJ Online, Abu Dhabi National Oil Co. (ADNOC) subsidiary ADNOC Re- Aug. 31, 2018). The proposed $7.4-billion (Can.) crude oil and fining (formerly Takreer) has let a contract to John Wood Group products pipeline would be near one that was built in 1953 and PLC to deliver preliminary front-end engineering and design increase capacity to 890,000 b/d from 300,000 b/d. (pre-FEED) for a refinery to be built in Ruwais, in the western While a credible worst-case spill from the project or a relat- region of Abu Dhabi (OGJ Online, May 14, 2018). ed marine vessel is not likely, environmental effects would be With a proposed nameplate capacity of 600,000 b/d, the weighty if one occurred, the report said. “While these effects new refinery will be designed to have full-conversion capability weighed heavily in the NEB’s consideration of project-related as well as the ability to be integrated with existing petrochemi- marine shipping, the NEB recommends that the government of cal infrastructure in Ruwais, Wood said. Canada find that they can be justified in the circumstances, in As part of the contract—valued at $8 million—Wood will light of the considerable benefits of the project and measures to also provide services, including licensor selection, site master- minimize the effects,” it said. plan development, scope of work for the FEED phase, as well as These benefits include increased access to diverse markets a schedule and cost estimate for the engineering, procurement, for Canadian oil; jobs created across Canada; the development and construction phase. of capacity of local and indigenous individuals, communities, Wood said it expects to complete the pre-FEED phase by and businesses; direct spending on pipeline materials in Cana- yearend. Once completed, the new refining and petrochemicals da; and considerable revenues to various levels of government. complex will become the world’s largest. The latest contract follows ADNOC’s May 2018 announce- ADNOC completes pipeline system investment deal ment that it would expand refining capacity at Ruwais, now Abu Dhabi National Oil Co. (ADNOC) entered into a landmark a combined 817,000 b/d, with the addition of a 600,000-b/d multibillion-dollar midstream pipeline infrastructure partner- refinery and to expand petrochemical capacity at the complex ship with institutional investors KKR and BlackRock. Newly as part of its broader $45-billion program to become a global formed ADNOC Oil Pipelines will lease ADNOC’s interest in downstream leader under a new combined model of strategic 18 pipelines transporting stabilized crude oil and condensate partnerships and investments (OGJ Online, Jan. 28, 2019). across ADNOC’s offshore and onshore upstream concessions A cornerstone of the downstream investment plan is expan- for a 23-year period. The entity will, in turn, receive a tariff sion of the company’s existing refining capacity by more than payable by ADNOC, for its share of volume of crude and con- 65% to 1.5 million b/d by 2025, ADNOC said. densate that flows through the pipelines, backed by minimum volume commitments. Aramco, Total form Saudi retail venture The 18 pipelines leased by ADNOC Oil Pipelines have a to- Saudi Aramco and Total SA have signed an agreement to form tal length of more than 750 km and a total aggregate capacity a 50-50 joint venture that will invest $1 billion to develop a of about 13 million b/d. These assets move most of Abu Dhabi’s network of fuel and retail services in Saudi Arabia. crude oil production to sites for either conversion to other prod- Total will be the first major international oil company to ucts or shipment to global energy markets. The pipelines have invest in the kingdom’s fuel retail network. underlying long-term minimum volume commitments and are The companies also agreed to acquire Tas’helat Marketing supported by stable crude oil production from ADNOC On- Co. and Sahel Transport Co., owners of 270 service stations and shore and ADNOC Offshore with global international oil com- a fuel tanker fleet. panies as joint-venture partners, each with an average remain- ing concession life greater than 35 years. TRANSPORTATION QUICK TAKES ADNOC plans oil storage in Fujairah NEB recommends approval of Trans-Mountain pipeline Abu Dhabi National Oil Co. plans to build in Fujairah what Canada’s National Energy Board recommended the approval it calls “the world’s largest single underground project ever of the Trans-Mountain Pipeline expansion project as it de- awarded for oil storage.” It let an engineering, procurement, and livered its reconsideration report with 156 conditions and construction contract to SK Engineering & Construction Co. 16 new recommendations to the federal government on Feb. Ltd., Seoul, for three underground storage caverns with capaci- 22. NEB’s recommended approval came despite the board’s ties of 14 million bbl each. conclusion that project-related marine shipping would likely ADNOC said the $1.21-billion contract is “the largest for a cause adverse environmental effects on the southern resident single project award for underground crude oil storage in the killer whale and on indigenous cultural uses associated with world.” the animal. It also found that greenhouse gas emissions from Completion is due in 2022.
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Denotes new listing or Brussels, web site: SPE/ICoTA Coiled Tub- PE-2019), Milan, web Engineers’ (EAGE) IOR Society of Petroleum a change in previously https://www.wplgroup. ing & Well Intervention site: scientificfederation. 2019—European Sym- Engineers-Kingdom of published information. com/aci/event/gasifica- Conference & Exhibition, com/wceogpe-2019/ posium on Improved Oil Saudi Arabia Section tion/ 13-14. The Woodlands, Tex., index.php 28-29. Recovery, Pau, France, (SPE-KSA) Annual web site: www.spe. web site: https://events. Technical Symposium Australasian Oil & Gas org/events/en/2018/ APRIL 2019 eage.org/2019/IOR%20 & Exhibition (ATS&E MARCH 2019 Exhibition & Conference conference/18ctwi/ 2019 8-10. 2019), Dammam, web (AOG 2019), Perth, web home.html 26-27. International Confer- site: www.spe-ksa.org/ Power & Gas M&A site: https://aogexpo. ence & Exhibition on SPE Oklahoma City atse 14-18. Symposium 2019, New com.au/ 13-15. Guyana International Liquefied Natural Gas, Oil & Gas Symposium, York, web site: https:// Petroleum Business Shanghai, web site: Oklahoma City, web Global Congress on www.spglobal.com/ American Fuel & Petro- Summit & Exhibition www.lng2019.com/ 1-5. site: https://www. Renewable & Non-Re- marketintelligence/en/ chemical Manufactur- (GIPEX), Georgetown, speokcsymposium.org/ newable Energy 2019, events/in-person/power- ers Annual Meeting & web site: https://guy- Independent Petro- 8-12. Venice, web site: www. and-gas-ma-symposium Exhibition (AFPM 2019), anaoilexpo.com/ 26-28. leum Association of cognizancescientific. 5-6. San Antonio, web site: America (IPAA) and IADC/SPE Managed com/renewable-non- https://www.afpm.org/ International Petroleum Texas Alliance of Energy Pressure Drilling & renewable-energy/ Saudi Downstream Conferences/ 17-19. Technology Conference Producers (TAEP) Texas Underbalanced Op- 16-17. Forum, Yanbu, web site: (IPTC), Beijing, web site: Alliance Expo & Annual erations Conference & https://www.saudidown- SPE Middle East Energy www.iptcnet.org/19iptc/ Meeting, Irving, Tex., Exhibition, Amsterdam, Oil & Fuel Supply Chain stream.com/ 5-6. Summit, Manama, web home/ 26-28. web site: https://www. web site: www.iadc.org/ Security Summit 2019, site: https://www.spe. ipaa.org/events/alliance- event/iadc-spe-mpd- London, web site: Subsea Tieback Forum org/events/en/2019/ European Fuels Markets expo-and-annual-meet- ubo-2019/ 9-10. https://oilandfuelsup- & Exhibition, San An- summit/19baes/middle- & Refining Strategy Con- ing/ 2-3. plychainsecurity.iqpc. tonio, web site: https:// east-energy-summit. ference 2019, Frankfurt, API Pipeline Conference com 16-18. www.subseatiebackfo- html 18. web site: https://www. 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Papua New Guinea Exhibition, Beijing, web seapexconf.org/ tion, Mumbai, web symposium/20sm01/ Petroleum & Energy site: www.ciooe.com.cn/ event-2019 2-5. site: www.spe.org/ committee.html 23-24. LNG Supplies for Asian Summit, Port Moresby, en 27-29. events/en/2019/ Markets 2019 Confer- web site: https://www. Mexico Energy Assem- conference/19ogic/ Society of Petroleum ence (LNGA 2019), pngsummit.com/ 19-21 China International bly, Mexico City, web oil-and-gas-india-con- Engineers (SPE) West- Singapore, web site: Petroleum & Petro- site: oilandgascouncil. ference-and-exhibition. ern Regional Meeting, www.lng-conference. American Fuel & Petro- chemical Technology & com/event-events/Mex- html 9-11. San Jose, Calif., web com 6-7. chemical Manufacturers Equipment Exhibition ico-energy-assembly/ site: https://connect. International Petrochem- (CIPPE), Beijing, web 3-4. SPE Reservoir spe.org/goldengate/ Petcoke Conference, ical Conference (AFPM site: https://10times. 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Manama, web site: SPE International International Confer- napec-dz.com/Default. https://europetro.com/ International Petro- Conference on Oilfield ence on Combustion & RefComm Galveston, aspx?lg=en&idsalon=& week/gsfopexmena2019 leum & Petrochemical Chemistry, Galveston, Processes, Rome, web Galveston, Tex., web std= 10-13. 25-28. Technology Confer- Tex., web site: www. site: https://cspconfer- site: https://refiningcom- ence (IPPTC), Beijing, spe.org/events/en/2019/ ence.org/ 10-12. munity.com/refcomm- International Confer- European Association web site: www.ipptc. conference/19occ/ galveston-2019 Apr. ence on Oil & Gas, of Geoscientists & Engi- org/2019/index.html oilfield-chemistry-inter- Gas Processors 29-May 3. Singapore, web site: neers (EAGE) Scientific 27-29. national-conference. Association (GPA) https://oil-gas.pulsus- Conference, Tyumen, html 8-9. Midstream Convention, MAY 2019 conference.com 11-12. web site: https://events. 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Houston, web site: www. Canada Gas & LNG Ex- Future Oil & Gas, Ab- show.com/ 11-13. International Association Gas-To-Power Africa otcnet.org/ 6-9. hibition & Conference, erdeen, web site: www. of Drilling Contractors Congress, Paris, web Vancouver, BC, web futureoilgas.com 11-12. Upstream West Africa (IADC) World Drilling site: https://oilandgas- CEE Small-Scale LNG site: https://canada- Summit 2019, Dakar, 2019 Conference & Ex- council.com/event- Forum, Vilnius, Lithu- gaslng.com/ 21-23. Global Petroleum Show, Senegal, web site: hibition, Milan, web site: events/gtp-africa- ania, web site: https:// Calgary, web site: https://www.upstream- iadc.org/event/world- congress/ 24-25. ceesslng.com/ 7-8. Canada Assembly & https://globalpetroleum- westafrica.com/ 18-20. drilling-2019 19-20. Dinner, Calgary, web GeoConvention, Calgary, site: https://oilandgas- web site: https://www. council.com/event- geoconvention.com/ events/canada-assem- 13-17. bly-and-dinner/ 30.
SPE Gulf Coast Section International Caspian Electric Submersible Oil & Gas Conference, REMOVING 99% Pumps Symposium, Baku, web site: www. The Woodlands, Tex., oilgas-events.com/ OF FROM THE web site: www.spe. Events/Caspian-Oil- FUEL org/events/en/2019/ Gas-Conference-2019 symposium/19esp/ 30-31. electric-submersible- pumps-symposium.html JUNE 2019 HOT ZONE 13-17. European Associa- SPE Norway One Day tion of Geoscientists & Seminar, Bergen, web Engineers (EAGE) site: https://www.spe. Conference & Exhibi- org/events/en/2019/ tion, London, web site: conference/19berg/ https://events.eage.org/ spe-norway-one-day- en/2019/eage-annu- seminar.html 14. al-2019 3-6.
International Associa- Digital Refining tion of Drilling Contrac- Summit 2019, London, tors (IADC) Drilling web site: https://www. Onshore Conference wplgroup.com/aci/ & Exhibition, Houston, event/digital-refining- web site: iadc.org/ summit/ 5-6. event/2019-iadc- drilling-onshore-confer- SPE Latin American ence-exhibition 16. & Caribbean Petro- leum Engineering World Fuel Oil Summit Conference, Bogota, XII, Limassol, Cyrus, website: www.spe.org/ web site: http://axel- events/en/2019/ rodenergyprojects. conference/19lacp/ com/#world-fuel-oil- latin-american-and- summit 16-18. caribbean-petroleum- engineering-conference. Frac Fuel Solutions is changing the way AAPG 2019 Annual html 5-7. Convention & Exhibi- frac pumps are fueled. tion, San Antonio, web IIoT & Digital Solutions Safety: our system keeps employees AND large amounts of fuel out of the hot zone— site: www.aapg.org/ for Oil & Gas, Amster- significantly reducing the risk of fire. events/conferences/ dam, web site: https:// Direct Fueling: our system delivers diesel directly to frac pumps, which keeps your site running uninterrupted. ace/ 19-22. www.globuc.com/digi- our system reduces day rate and increases operational efficiencies— talsolutions/ 6-7. Cost savings: adding up to substantial cost savings. World Congress on Petroleum & Refinery, Iberia Gas & LNG The only direct engine fueling system, Patented Technology Osaka, Japan, web Conference & Exhibi- site: https://petroleum. tion, Madrid, web site: www.fracfuelsolutions.com 713-907-4371 conferenceseries.com/ https://www.iberiagas. 20-21. com/ 10-11.
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Brasil Offshore Confer- Innovation Summit, International Trade Ex- the-americas-exhibition SPE Offshore Europe home 17-19. ence & Exhibition, Rio Denver, web site: www. hibition, Nairobi, Kenya, 27-28. 2019 Oil & Gas Confer- de Janeiro, web site: arpae-summit.com/ web site: https://www. ence & Exhibition, International Association www.brasiloffshore. Home 8-10. expogr.com/kenyaoil/ American Association Aberdeen, web site: of Drilling Contractors com/en/home/ 25-28. 25-27. of Petroleum Geologists www.offshore-europe. (IADC) Drilling Health, US Fuels Markets (AAPG) International co.uk/ 3-6. Safety, Environment & JULY 2019 & Refining Strategy Gas Indonesia Summit Conference & Exhibi- Training (HSE&T) Eu- Conference, Houston, & Exhibition 2019, tion, Buenos Aires, European Associa- rope 2019 Conference & Nigeria Oil & Gas web site: https://www. Jakarta, web site: www. web site: aapg.org/ tion of Geoscientists & Exhibition, Amsterdam, Conference & Exhibi- wplgroup.com/aci/ gasindosummit.com/ events/conferences/ Engineers (EAGE) web site: iadc.org/event/ tion, Abuja, web site: event/fuel-market- July 31-Aug. 2. ice/announcement/ International Conference euro-hset-2019 18-19. https://www.cwcnog. refining-strategy-confer- Articleid/46646/aapg- on Fault & Top Seals, com/ 1-4. ence-usa/ 10-11. AUGUST 2019 2019-international- Palermo, Italy, web site: Oil & Gas Indonesia, conference-exhibition- https://events.eage.org/ Jakarta, web site: www. Energy & Sustainability Society of Petroleum Summer NAPE, Hous- buenos-aires 27-30. en/2018/fault-and-top- oilgasindonesia.com 2019—International Engineers (SPE)/ ton, web site: napeexpo. seals-2019 8-12. 18-21. Conference on Energy American Association com/summer 21-22. SEPTEMBER 2019 & Sustainability, Coim- of Petroleum Geologists World Energy Congress, US Base Oils & bra, Portugal, web site: (AAPG)/Society of Ex- International As- European Associa- Abu Dhabi, web site: Lubricants Summit, wessex.ac.uk/confer- ploration Geophysicists sociation of Drilling tion of Geoscientists & www.wec24.org 9-12. New Orleans, web site: ences/2019/energy- (SEG) Unconventional Contractors (IADC) Well Engineers’ (EAGE) Con- https://www.wplgroup. and-sustainability-2019 Resources Technology Control Conference ference on Petroleum Conference on Oil & Gas com/aci/event/us-base- 3-5. Conference, Denver, of The Americas & Geostatistics, Florence, Geological Exploration & oils-lubricants-summit/ web site: www.urtec. Exhibition, Galveston, web site: https://events. Development (GEO- 28-29. Advanced Research org/2019 22-24. Tex., web site: iadc.org/ eage.org/en/2019/ MODEL 2019), Gelen- Projects Agency-En- event/2019-iadc-well- petroleum-geostatistics dzhik, Russia, web site: Society of Petroleum ergy (ARPA-E) Energy Africa 2019 Oil & Gas control-conference-of- 2-5. https://events.eage.org/ Engineers (SPE) Annual en/2019/Geomodel%20 Technical Conference & %202019 9-13. Exhibition (ATCE), Cal- gary, web site: connect. South America Energy spe.org/Calgary/ Week, Buenos Aires, events/eventdescription? web site: https://www. CalendarEventKey=908 energycouncil.com/ 65ae7-ffe0-4930-8c8c- event-events/south- 6c71aa america-energy-week/ 257757&Home=/home 10-11. Sept. 30-Oct. 2.
European Associa- OCTOBER 2019 tion of Geoscientists & Engineers’ (EAGE) MSGBC Basin Summit International Conference & Exhibition, Dakar, on Fault & Top Seals web site: https://oiland- 2019, Palermo, web gascouncil.com/event- site: https://events.eage. events/msgbc-basin- Driving results through continuous org/2018/Fault%20 summit/ 7-9. improvement is one of the values on TO EXACTING and%20Top%20 which our company was built. Seals%202018 15-19. Louisiana Gulf Coast Oil STANDARDS With focused operations in Oklahoma’s Exposition (LAGCOE) fast-growing STACK Play, our team Gastech Exhibition & 2019, New Orleans, web of oil and natural gas experts is Conference, Houston, site: https://www.lagcoe. API 676 PUMP Energizing America’s Heartland™ and website: www.gastech- com/events/lagcoe-2019 event.com 17-19. delivering safe, cost-efficient ways to 9-11. unlock the vast potential of our almost Society of Petroleum Society of Exploration The new BNA pump ensures compliance with API 676 and API 682 while reducing costs in 127,000 STACK acres. Engineers (SPE) Reser- Geophysicists (SEG) petrochemical applications. Act now to experience the benefi ts of this API pump for yourself. voir Characterization & International Conference Simulation Conference on Engineering Geophys- YOUR BENEFITS BNA & Exhibition, Abu Dhabi, ics (ICEG), Al Ain, UAE, web site: https://www. web site: https://seg. API 676 and API 682 compliant Simple integration into piping systems spe.org/events/en/2019/ org/Events/ICEG-2019 Extremely robust design Non-welded casing means reduced conference/19rcsc/ 21-24. SEEPEX GmbH High containment pressure and documentation and fewer inspections T +49 2041 996-0 corrosion resistance Shorter lead time, high operational safety www.seepex.com ChapEne_OGJ_19030414 1 2/20/19 10:15 AM Oil & Gas Journal | Mar. 4, 2019
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Society of Petroleum 121 Oil & Gas Invest- event/2019-iadc-annual- site: https://oilandgas- JANUARY 2020 & Social Responsibil- Engineers (SPE) ment, London, web site: general-meeting 6-8. council.com/event- ity, Bogota, web site: Russian Petroleum https://www.weare121. events/north-america- Energy Council Gas to https://www.spe. Technology Conference com/121oilgasinvestment- US-Mexico Natural Gas assembly-and-dinner/ Power APAC Congress, org/events/en/2020/ (RPTC), Moscow, web london/ 29-30. Forum, San Antonio, web 21. Singapore, web site: conference/20hse/ site: https://www.spe. site: www.usmexiconatu- https://oilandgascouncil. health-safety-and-envi- org/events/en/2019/ SPE/IATMI Asia Pacific ralgasforum.com/ 11-13. Nigeria Assembly, com/event-events/gtp- ronment.html 17-19. conference/19rptc/ Oil & Gas Conference Lagos, web site: https:// apac-congress/ 29. spe-russian-petroleum- & Exhibition, Bali, web Abu Dhabi International oilandgascouncil.com/ Society of Petroleum technology-conference- site: https://www.spe. Petroleum Exhibition event-events/nigeria- Oil & Gas Council Asia Engineers (SPE) Latin moscow.html 22-24. org/events/en/2019/ & Conference (ADI- assembly/ 25. Pacific Energy Assem- American & Caribbean conference/19apog/ PEC), Abu Dhabi, web bly, Singapore, web site: Petroleum Engineering International Associa- asia-pacific-oil-and- site: https://www.spe. DECEMBER 2019 https://oilandgascouncil. Conference (LACP), tion of Drilling Contrac- gas-conference-and- org/events/en/2019/ com/event-events/ Bogota, web site: tors (IADC) Advanced exhibition 29-31. conference/19adip/ World Energy Capital asia-pacific-energy- https://www.spe. Rig Technology 2019 abu-dhabi-international- Assembly, London, assembly/ 30-31. org/events/en/2019/ Conference & Exhibi- Offshore Technology petroleum-exhibition- web site: https://oiland- conference/19lacp/ tion, Amsterdam, web Conference Brazil (OTC and-conference-adi- gascouncil.com/event- MARCH 2020 latin-american-and-ca- site: iadc.org/event/ Brasil 2019), Rio de pec-2019.html 11-14. events/world-energy- ribbean-petroleum-en- rig-technology-2019 Janeiro, web site: www. capital-assembly/ 2-3. SPE EOR Conference gineering-conference. 22-23. otcnet.org/Brasil 29-31. RefComm Santiago, at OGWA, Muscat, web html 17-19. Santiago, web site: International Associa- site: www.ogwaexpo. Asia Petroleum Geosci- NOVEMBER 2019 https://refiningcom- tion of Drilling Contrac- com/index.php 8-11. Offshore Technology ence Conference & munity.com/refcomm- tors (IADC) Drilling Conference Asia (OTC Exhibition (APGCE), International Associa- santiago-2019 18-21. Middle East 2019 Society of Petroleum Asia), Kuala Lumpur, Kuala Lumpur, web tion of Drilling Contrac- Conference & Exhibi- Engineers International web site: 2020.otcasia. site: events.eage.org/ tors (IADC) Annual Oil & Gas Council North tion, Abu Dhabi, web Conference & Exhibi- org/welcome 24-27. en/2019/APGCE%20 General Meeting, Austin, America Assembly & site: iadc.org/event/ tion on Health, Safety, 2019 29-30. web site: iadc.org/ Dinner, Houston, web me19 10-11. Security, Environment
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UKCS volcanoes questioned Researchers said recent study results suggest the “What we found has completely overturned possibility of oil and natural gas discoveries in a decades of accepted knowledge,” Scholfield said. 7,000-sq km area of the UK North Sea because of “Our study has shown these volcanoes never ex- “phantom” volcanoes. isted at all. Essentially this gives us back a huge Geologists said a large swathe of the UK Con- amount of gross rock volume that we never knew tinental Shelf was unexplored for more than 50 existed.” years because of beliefs about the existence of Schofield added: “There is a huge area under volcanoes based upon what researchers now call there that hasn’t been looked at in detail for a long “incorrect geological models.” time” because of an incorrect geological model. Scientists from the University of Aberdeen led Meanwhile, discoveries still are being made in the PAULA DITTRICK a study resulting in an article entitled “Phantom North Sea, such as the Central Graben and Viking Upstream Technology volcanoes discovery signals new hope for North Graben areas. Editor Sea oil and gas exploration” that was published in November 2018 in the Journal of the Geological UKCS discoveries Society. Wood Mackenzie Ltd. said the UK Central Graben Previously, scientists believed the Middle Ju- basin is in less than 100 m of water. The Mesozoic rassic Rattray volcanic province off northwest high-pressure, high-temperature play remains of Scotland contained three volcanoes that erupted interest following the large Culzean discovery in 165 million years ago. The notion that the area 2008, which is expected on stream late this year. contained empty magma chambers ruled out pos- In January, CNOOC Petroleum Europe Ltd. sible oil and gas discoveries. discovered natural gas and condensate pay in the The volcanoes were believed to have been Glengorm prospect in the Central Graben area. formed millions of years ago during seismic ac- The CNOOC subsidiary drilled an exploration tivity under the North Sea that almost created an well to 5,056 m TD in 86 m of water, encounter- ocean between Britain and Europe—a rifting epi- ing net gas and condensate pay with a total net sode geologists have described as a failed ‘Jurassic thickness of 37 m in a Upper Jurassic reservoir. Brexit’ attempt. Recoverable resources are estimated at about 250 million boe, said partner Total E&P UK North Assumption overturned Sea Ltd. Nick Schofield and Ailsa Quirie from the University Further drilling and testing will be carried out of Aberdeen along with colleagues from Heriot-Watt to appraise resources and the productivity of the and the University of Adelaide have questioned this reservoir, Total said. assumption. The discovery was in the P2215 license, previ- Schofield said reinterpretation using 3D seis- ously part of the Maersk Oil portfolio, and close mic data and well data shows no volcanic centers to existing Total-operated infrastructures offering are present, and the Rattray volcanics were instead tie-back possibilities, such as the Elgin-Franklin sourced in fissure eruptions from linear vents. platform and the Culzean project. Norway’s Petroleum Geo-Services provided the CNOOC is operator with 50% working inter- 3D seismic. est. Partners include Total and Euroil, a wholly The fissures run parallel to the Highland owned subsidiary of Edison E&P SPA, each with Boundary Fault, which intersects the Rattray vol- 25% working interest. canics at the Buchan-Glenn Fissure System.
16 Oil & Gas Journal | Mar. 4, 2019
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1401OGJmarFP_petroRM_140131_1 1 2/3/14 11:16 AM 190304OGJ016-017.indd 17 2/28/19 12:22 PM EDITORIAL FERC’s breakthrough
Breakthrough came to more than a queue of LNG casieu LNG’s fractional contribution to national export projects when the US Federal Energy Regu- GHG emissions was environmentally insignifi- latory Commission approved Venture Global LNG’s cant. “The result is that climate change plays no Calcasieu Pass venture on Feb. 21. Compromise meaningful role in the commission’s public-inter- enabling this welcome move shows hope for prog- est determination,” he wrote. ress away from the all-or-nothing approach that fre- His conclusion suffers from overstatement but quently mires regulation addressing climate change. nevertheless identifies a genuine problem. FERC Approval of a 12 million-tonne/year gas lique- has no framework within which to distinguish be- faction project by a commission split 2-2 over a tween environmentally significant and insignifi- crucial topic of regulation is important by itself. cant levels of GHG emissions from individual proj- Twelve other LNG export plants await FERC ap- ects. This indicates no procedural lapse. It instead proval, and five more are in prefiling stages. Not reflects the core vexation of climate regulation and all those ventures will advance to construction. the futility of applying it project by project. But LNG is a rapidly growing export commodity Climate change is a global phenomenon. No one as gas production increases from unconventional project can affect it much. Activists therefore try to
resources. Liquefaction projects are vital to re- block as many CO2-emitting activities as they can, alization of this economic promise and must be hoping to make a collective difference. Yet, even if ready when the market needs them. they were to succeed in foreclosing projects that would have accounted for, say, one third of global A ‘new approach’ GHG emissions, what would the effect be on glob- Just as important as buildout of export capacity, ally averaged temperature? The answer depends though, is the way commissioners eased political on equilibrium climate sensitivity, the long-term
deadlock. FERC “applied a new approach for con- temperature response to a doubling of CO2 in the sideration of direct greenhouse gas [GHG] emis- atmosphere. About that, the generally accepted sions from LNG facilities,” reported Chairman Neil scientific estimate varies by a factor of three. With Chatterjee in a press statement. “I anticipate we’ll such a wide range of uncertainty, warming—the be able to use the framework developed in this or- core concern of climate change—from incremental
der to evaluate the other LNG certificates that the CO2 loading of the atmosphere under reasonable commission is considering.” assumptions might or might not be significant. It For Calcasieu Pass, the commission assessed di- thus might threaten human welfare, or it might not. rect emissions of GHGs—3.9 million tpy of carbon dioxide-equivalent, according to the environmen- Skirting myopia tal impact statement—as a share of total US emis- Glick and LaFleur wish for some way to condense sions in 2016—0.07%. Under a 2016 court ruling, these perplexities into manageable quanta conve- FERC doesn’t review indirect GHG emissions up- nient for regulation. Both extol the social cost of stream and downstream of projects. The Depart- carbon (SCC), which estimates costs attributable to
ment of Energy accounts for indirect emissions in CO2 emissions. But the SCC is arbitrary and subject its public-interest decisions about LNG exports, to political manipulation. Given the complexity of
which precede FERC review of project facilities. climate phenomena and uncertainty about the CO2- The new approach cited by Chatterjee didn’t temperature relationship, it is, at best, guesswork. fully satisfy Commissioner Cheryl A. LaFleur, a Regulation of GHGs is prudent and necessary. Democrat, but enabled her to join the commission’s To be effective, however, it must apply at meaning- Republicans, Chatterjee and Bernard L. McNamee, ful scale, avoid unreasonable precision in perfor- in support of the project. The other Democratic mance metrics, and work within broader environ- commissioner, Richard Glick, dissented. FERC has mental programs with clearer benefits in relation been politically balanced since the Jan. 3 death of to cost. By skirting project-level climate myopia, former Chairman Kevin McIntyre, a Republican. the FERC decision moves constructively in that Glick disagreed with FERC’s finding that Cal- direction.
18 Oil & Gas Journal | Mar. 4, 2019
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PPBks_Petro_161117 1 11/18/16 10:35 AM 190304OGJ018-019.indd 19 2/28/19 12:22 PM GENERAL INTEREST Growth of US upstream spending to decelerate in 2019
Conglin Xu Senior Editor-Economics
Upstream oil and gas capital expenditures in US es. Despite the overall capex decline, producers are this year will increase only 2%, following an 23% SPECIAL forecasting strong production gains, as they will increase last year, as independent producers focus REPORT decrease the inventory of drilled but uncompleted on capital discipline and cashflow neutrality. (DUC) wells. Total spending for exploration, drilling, and pro- Meanwhile, IOC activities will expand rapidly duction will total almost $152 billion, OGJ forecasts. Firms’ this year. IOCs have been building out supply chain and in- spending plans show a divergence between US independents frastructure to support large, multiwell pad developments in and international oil companies (IOC). Combined spending the Permian basin. IOCs’ spending plans are usually with of the US independent group could drop 6-8% from a year lower commodity price sensitivity. ago, while IOCs will expand their activities. According to preliminary company data and OGJ esti- In 2018, upstream spending surged 23% compared with mates, Chevron Corp., ExxonMobil Corp., ConocoPhillips, an original guidance of 9% because of increased activity and Royal Dutch Shell PLC, and BP PLC will all increase their US higher costs as oil prices held firm for most of the year. onshore capital spending. BP just completed its $10.5-billion Capital expenditures on the other categories—including purchase of BHP Billiton’s US onshore assets last October. refining, petrochemicals, and pipelines—continue to in- Bonus payments related to Outer Continental Shelf lease crease this year. sales will rise slightly this year. The US Bureau of Ocean En- Meanwhile, E&P capital spending in Canada will decline ergy Management has scheduled two lease sales, Nos. 252 and this year, partly because of production curtailments an- 253, to take place during 2019. OGJ forecasts that such pay- nounced by the Albertan government. However, spending ments will total $310 million, up from $303 million last year. for oil sands development there will climb. During 2018, BOEM held two lease sales. The first one, International upstream spending outside North America No. 250, resulted in $124.76 million in bonus payments. The is expected to increase. According to the latest Barclays E&P other, No. 251, produced $178 million in bonus payments. survey, growth will reach at least 8% from almost every in- ternational region, with the exception being Russia and the US firms’ spending plans former Soviet Union. International spending is forecast to ExxonMobil expects 2019 capex of $30 billion, up from reach $286 billion in 2019. $25.9 billion in 2018 and $23 billion in 2017. ExxonMobil All dollar amounts reported are in US dollars unless oth- spent $7.67 billion on US upstream in 2018, up from only erwise indicated. $3.7 billion for such outlays in 2017. Key drivers of upstream growth in the US this year are in the Permian, where the US upstream spending company has trebled the size of its resource since 2017. The growth of US independents takes a back seat. Consis- Chevron has budgeted $20 billion for capital and explor- tent with the commitment to capital discipline and in re- atory expenditures for 2019, with $17.3 billion earmarked sponse to recent volatile commodity price trends, most US for upstream spending. Upstream expenditures were $17.6 E&P companies have announced reductions in rig and frac billion for 2018 and $16.4 billion for 2017, respectively. spread counts and intend to reduce 2019 capital spending. Despite a lower total upstream spending, Chevron’s up- Most companies made their 2019 budgets assuming a stream capital outlays on projects in the US will rise to $7.6 West Texas Intermediate oil price of $50-55/bbl and a Henry billion this year from $7.1 billion last year and $5.1 billion Hub natural gas price of $3/MMbtu. in 2017. Specifically, upstream spending for the Permian is Combined spending of US independents could decline budgeted at $3.6 billion. About $1.6 billion is allocated to 6-8% this year, based on estimates from their budget releas- other shale and tight investments.
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190304OGJ020-030.indd 20 2/28/19 12:22 PM ConocoPhillips anticipates capital WHERE FUNDS WILL GO FOR US PROJECTS Table 1 spending of $6.1 billion in 2019, which 2019 2019-2018 2018 2018-2017 2017 is flat with the expected full-year 2018 million $ change, % million $ change, % million $ capital expenditures excluding acqui- Exploration-production Drilling-exploration 127,969 2.0 125,460 23.0 102,000 sition costs. The company’s full-year Production 24,314 2.0 23,837 23.0 19,380 OCS lease bonus 310 2.3 303 150.4 121 2019 production guidance is 1.3 mil- –––––––– ––––– –––––––– ––––– –––––– lion boe/d to 1.35 million boe/d, up Subtotal 152,593 2.0 149,600 23.1 121,501
from $1.26 million boe/d last year. Other Re ning and Marketing 14,820 3.0 14,388 9.0 13,200 This represents the first production Petrochemicals 10,101 7.5 9,396 8.0 8,700 Crude and products pipelines 26,200 4.8 25,000 4.4 23,941 gain since 2015. Natural gas pipelines 24,000 28.0 18,750 144 7,685 About $3.1 billion, or 51%, is allo- Other transportation 5,160 20.0 4,300 19.4 3,600 Miscellaneous 3,938 5.0 3,750 25.0 3,000 cated to the Lower 48, roughly flat to ––––––– ––––– ––––––– ––––– ––––––– Subtotal 84,218 11.4 75,584 25.7 60,126 2018 spending. About $1.2 billion, or –––––––– ––––– –––––––– ––––– ––––––– 20%, is allocated to Alaska compared TOTAL 236,811 5.2 225,184 24.0 181,627 with $900 million in 2018. Capital expenditures in Canada also will in- crease to $500 million from $300 mil- CANADIAN SPENDING PLANS Table 2 lion last year, reflecting ongoing ac- 2019 2018 2017 tivity in the Montney unconventional million $ 2019-18 million $ 2018-17 million $ (Can.) change, % (Can.) change, % (Can.) program and Surmont upgrades. Exploration-production Antero Resources Corp. is trim- Drilling-exploration 19,630 -1.5 19,929 11.0 17,954 ming its drilling and completion bud- Production 11,763 -1.5 11,942 11.0 10,759 ––––––– –––– –––––– –––– –––––– get to $1.2 billion in 2019 from $1.5 Subtotal 31,393 -1.5 31,871 11.0 28,714
billion last year. The company plans Oil sands* 12,969 8.0 12,009 -13.0 13,803
to operate an average of 5 drilling rigs Other and 4 completion crews, down 1 to 2 Re ning and Marketing 3,270 2.5 3,190 10.0 2,900 Petrochemicals 1,590 60.0 994 1.4 980 crews from 2018. Antero is expecting Pipelines 7,000 48.1 4,725 5.0 4,500 Other transportation 618 6.0 583 6.0 550 to increase production by 18%. Miscellaneous 600 9.1 550 5.8 520 Apache Corp. is slashing spending –––––– ––––– –––––– ––––– –––––– Subtotal 13,078 30.2 10,042 6.3 9,450 by 22% to $2.4 billion, with 75% al- –––––– ––––– ––––––– ––––– –––––– located to its Permian basin assets. It TOTAL 57,440 6.5 53,921.8 3.8 51,967 still expects 6-10% production growth *In situ, mining, and upgrading. after adjusting for divestitures. Anadarko Petroleum Corp. expects full-year capital investments ranging $4.3-4.7 billion (excluding WES), which represents a 9% $9.5-billion acquisition of RSP Permian last July. decrease relative to its 2018 program and still delivers 10% Devon Energy Corp. reported a plan to sell its Barnett oil growth year over year. Specifically, 70% of investments shale and Canadian oil assets, which represents more than are directed towards US onshore assets, mainly in the Dela- 40% of its fourth-quarter 2018 production. Devon stated ware and DJ basins. While spending in the Gulf of Mexico that its upstream capital spending this year will range $1.8- is lower than in 2018, the number of wells and production 2 billion, with the midpoint about 10% less than in 2018. will be similar. Devon expects to achieve oil production growth of 13-18% Continental Resources Inc.’s capital expenditures budget in 2019. for 2019 is $2.6 billion compared with $2.8 billion spent in Diamondback Energy Inc. plans capital expenditures in 2018, with the majority of 2019 drilling and completion bud- 2019 to reach $2.7-3 billion, including $2.3-2.55 billion for get focusing on oil-weighted areas in the Bakken and SCOOP. drilling and completion. During 2018, capital expenditures Under the current commodity price environment, planned for drilling, completing, and equipping wells were $1.4 bil- capital expenditures for 2019 are expected to be funded en- lion. tirely from operating cash flows. Gas-weighted EQT Corp., embroiled in a spat with Rice Chesapeake Energy Corp. plans to reduce its 2019 capital Energy Inc. founders, is slashing outlays from $2.7 billion expenditures by lowering its rig count by 20%, expecting to last year to $1.9 billion this year to reduce leverage and re- average 14 rigs vs. a current rig count of 18. turn additional free cashflow to shareholders. About 80% of Concho Resources Inc. is expecting an increase its capi- its capital spending will be deployed in the Marcellus shale, tal spending during 2019 to $2.9 billion after closing its with the balance being invested in the Utica shale.
Oil & Gas Journal | Mar. 4, 2019 21
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EOG Resources Inc.’s exploration and development ex- from the International Maritime Organization’s enforcement penditures for 2019 are expected to range $6.1-6.5 billion of a 0.5% global sulfur cap on fuel content from Jan. 1, 2020, compared with $6.2 billion in 2018. EOG expects to increase lowering it from the current 3.5% limit. US crude oil production by 12-16%, fund capital investment, OGJ projects that capital spending at US refining and mar- and pay the dividend with net cash from operating activities keting this year will increase 3% to $15.5 billion from 2018 in 2019 at $50/bbl oil. spending of $15 billion. The growth in investments focuses EOG expects to complete about 740 net wells in 2019 on upgrading capabilities, yield flexibility, and conversion ca- compared with 763 net wells in 2018. Activity will remain pacity. focused in EOG’s highest rate-of-return oil assets in the Del- PBF Energy will spend $625-675 million in net capital aware basin, Eagle Ford, Rockies, Woodford, and Bakken. expenditures during 2019 for facility improvements and Hess Corp. is expected to spend $2.9 billion, maintenance. about 40% more than in 2018, due to higher spend- Marathon Petroleum Corp. spent $1 billion and ing in the Bakken and Guyana. About $1.4 billion $832 million on its refining and marketing busi- will be used to fund an increase to 6 rigs from an ness in 2018 and 2017, respectively. The 2018 average of 4.8 rigs in 2018, and the shift to higher spending included part of Andeavor’s results since intensity plug and perforated wells in the Bakken. October. In 2019, Marathon Petroleum’s key proj- The company expects to drill about 170 new SPECIAL ects include increasing Garyville coking capacity wells and to bring online 160 new wells in 2019. REPORT by 50%, Galveston Bay STAR Program, and others. Marathon Oil Corp.’s 2019 capital budget totals Phillips 66’s capital budget, excluding Phillips $2.6 billion, down slightly from 2018. More than 66 Partners, is $2.3 billion this year. Phillips 66 95% of its $2.4-billion development capital budget plans $923 million of capital spending in refin- will be allocated to the four US resource plays: Eagle Ford ing, with $512 million for reliability, safety, and environ- and Bakken (60%) and Oklahoma and the Northern Del- mental projects. Refining growth capital of $411 million is aware (40%). Marathon Oil expects oil growth of 10% in for high-return projects to enhance the yield of higher-value 2019. products, including an upgrade of the fluid catalytic crack- Occidental Petroleum Corp. announced a 2019 capital ing unit at the Sweeny refinery, as well as other low-capital, program of $4.5 billion compared with 2018 spending of $5 quick-payout projects. billion. Upstream spending in the Permian will account for Valero Energy Corp. expects to invest about $2.5 bil- $3.1 billion, down from $3.3 billion spent last year. lion of capital in both 2019 and 2020, of which 60% is for sustaining the business and 40% is for growth projects. In US refining, petrochemical outlays 2018, Valero’s capital investments totaled $2.7 billion. Given their access to low-cost natural gas and price-advan- US petrochemical manufacturers remain advantaged with taged crudes, US refiners still face a favorable business envi- access to cheaper and more abundant feedstocks and energy. ronment. Distillate demand growth outpaces gasoline, driv- Phillips 66’s capital contributions to Chevron Phillips en by transportation and industrial sectors and the impact Chemical Co. will rise to $572 million from $339 million a year ago. Since 2010, 333 chemical indus- US FIRMS’ CAPITAL SPENDING, 2017-2019 try projects cumulatively valued at more than $200 billion have been an- 8,000 2019 nounced, with 53% of the investments 7,000 2018 completed or under construction and 2017 6,000 41% in the planning phase, according to The American Chemistry Council. 5,000 4,000 US pipelines $ million 3,000 Many pipeline construction projects are under way in the US to aid in de- 2,000 bottlenecking oil and gas from the 1,000 Permian basin and other plays. 0 According to OGJ’s most recent SM Oxy EQT CNX QEP COP WPX
Hess Worldwide Pipeline Construction re- SWN Cabot PDCE Noble Devon Antero Parsley Apache Concho Pioneer Murphy Cimarex port, plans call for a total of 2,571 Chevron* Anadarko Continental
Marathon Oil miles of gas pipelines to be constructed *Only US upstream spending Diamondback Source: Preliminary company data available, OGJ analysis in the US in 2019, mostly larger than
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32 in. (OGJ, Feb. 4, 2019, p. 48). In addition, plans call for The Canadian rig count decreased to 212 in February the construction of 3,763 miles of crude and product pipe- from 342 in the same time last year, with oil rigs down 90 lines in the US this year. Many of these lines will be 22-30 units and gas rigs down 40 units, according to Baker Hughes. in. According to OGJ forecasts, oil sands capital spending, The US Federal Energy Regulatory Commission’s annual which includes funds for in-situ extraction, mining, and up- report of oil pipeline companies showed that investment in graders, will climb 8% from a year ago to about $13 billion. US oil pipelines totaled $23.9 billion in 2017 and $23.1 bil- This follows a decrease of 13% last year. lion in 2016. The Canadian Association of Petroleum Producers re- Given the strong boom in pipeline constructions, OGJ ported that oil sands capital expenditures totaled $13.8 bil- forecasts that US capital spending on pipelines will increase lion in 2017, the latest year for which the association has 5% for crude and product pipelines and 28% for gas pipe- reported such data. lines this year from a year ago. Suncor Inc. has set a 2019 capital spending program of $4.9-5.6 billion, and average upstream production of 780,000- Canadian E&P, oil sands 820,000 boe/d. The midpoints of these ranges represent a flat All Canadian spending figures in this section are expressed capital spend compared with 2018 and a year-over-year pro- in Canadian dollars. duction increase of 10%, including estimated mandatory pro- Capital expenditures for oil and gas exploration, drilling, duction curtailments, from 730,000 boe/d in 2018. and production in Canada will decline 1.5% to $31.4 billion Suncor’s upstream oil sands spending this year ranges $3- (Can.) in 2019, following a 11% increase in 2018. 3.4 billion. This compares with $3.5 billion and $5 billion Faced by record discounts for its crude and brimming for 2018 and 2017, respectively. Upstream E&P spending inventories, Alberta announced mandated temporary pro- ranges $1-1.2 billion, up from $9.5 million and $8 million duction cuts of as much as 325,000 b/d for an initial period for 2018 and 2017, respectively. of 3 months of 2019. Canadian Natural Resources Ltd.’s 2019 base capital bud-
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EnvGlo_OGJ_190304 1 2/18/19 1:25 PM Oil & Gas Journal | Mar. 4, 2019 23
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get is targeted to be $3.7 billion, about $1 billion less than curtailments in Alberta, and the temporary suspension of the 2018 forecast due to increased capital flexibility. operations at the SeaRose floating production, storage, and The company’s 2019 capital budget for total oil sands offloading vessel in the Atlantic region. mining and upgrading will increase to a base budget of $1.5 Husky’s capital budgets for thermal and oil sands this year billion, up from $1.3 billion estimated for 2018. Budgets for ranges $730-760 million, down from $915 million last year. North America E&P will decrease to $1.1 billion Spending for conventional heavy oil and Western from $1.55 billion a year ago, while its interna- Canada resource play drilling ranges $280-300 tional E&P spending will increase to $460 million million, down from $350 million a year ago. from $410 million last year. Cenovus Energy Inc. plans to invest $1.2-1.4 Husky Energy Inc.’s capital spending budget billion in 2019, with much of the budget going to ranges $3.3-3.5 billion, including $1.8 billion in sustain base production at its Foster Creek and sustaining and corporate capital. Midrange aver- SPECIAL Christina Lake oil sands operations. The company age annual 2019 production of 295,000 boe/d in- REPORT also plans to complete construction of the Chris- cludes reductions related to government-mandated tina Lake Phase G expansion.
long-term contracts (3-7 years) with extension periods, hence Capital investment the day rates of a lot of their current drilling rig fleets are based on old contracts. Brazil is one of the most important countries for subsea continues to increase activity, followed by Mexico. Latin America will remain the largest regional deepwater rig market. Demand is expected to continue in Latin America to grow as activity picks up in deepwater exploration in Mexico. Recently operators have pushed towards having shorter-term Siddhartha Sen contracts to enable them to shift gears and maneuver volatility in IHS Markit, Houston commodity prices. Crude pipeline infrastructure in Argentina is located around IHS Markit expects global gross domestic product to remain the main crude-producing basins, thus connecting the produc- resilient over the next few years, backed by low interest rates tion to the main refineries in the region. In Brazil, pipeline infra- across regions and a relatively low inflation rate. Latin America structure is limited in its reach and for the population not living upstream spend is still expected to see an increase of 37%, from close to a refinery, the common mode to transport is rail, barge, $80 billion in 2018 to $110 billion in 2022. However, the main or truck. Mexico’s pipeline infrastructure is quite extensive and countries—Argentina, Brazil, and Mexico—are experiencing fis- reforms have opened opportunities for private players to invest in. cal and external deficits and weak economic recovery. A breakeven price for a major field like Cerro Dragon in Activity remains strongest in Brazil, Argentina, and Mexico. Argentina is estimated to be $30/bbl. For projects such as Brazil deployed four floating production, storage, and offload- Lapa, the producing phases have very competitive breakevens ing vessels in 2018: one in Tartaruga Verde field, one in Buzios at $25/bbl, while new phases have breakeven close to $46/bbl. field, and two in Atlanta field. Of the seven FPSOs that Brazil’s With increased activity in the region, the pressure on contrac- state oil firm Petroleo Brasileiro SA (Petrobras) had plans to tor’s market, supply chain, and infrastructure is expected to award in 2018, four are currently in the bidding process and rise. Countries like Argentina are expected to manage these are expected to be awarded soon. The total capacity addition constraints by balancing development activity between onshore from these seven FPSOs would be 910,000 b/d. unconventional and offshore conventional activity. Production Argentina was planning its first offshore bid round in nearly for Argentina’s unconventional assets is expected to contribute 2 decades in February. The blocks to be put up in these bid 33% of total production by 2020, increasing to 64% by 2025. rounds are the Argentina Norte, Austral, and Malvinas Oeste. Most of the upstream activity in Latin American countries is For Mexico, uncertainty exists with the new administration driven and managed by state oil companies. However, with the and three bid rounds had been postponed from late 2018 to opening of the region, there are opportunities for international February 2019. companies to collaborate with state oil companies and develop Utilization rates for the global offshore rig markets have the oil and gas resources in the region. A fair exchange of tech- come down from an average of 90% in 2014 to about 60% nological knowhow, along with fair and equitable fiscal regime, currently. Supply has exceeded demand, and while 160 rigs could lead to increased exploration and development activity in were retired globally since 2014, only 12 were from Latin the region. This is expected to bring with it cost pressures and America. The average drilling rig day rate in Latin America is hence it will be important for international operators to enter close to $265,000. Most of the Latin American countries have the region while the opportunities exist.
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The 4% reduction in total planned capital spending com- million b/d, the Middle East is expected to lead international pared with Cenovus’s 2018 forecast is largely the result of ef- spending, up 8% to about $43 billion. Spending grew only ficiency improvements at the company’s oil sands operations 2% in 2018, according to the report. and reduced development plans for the Deep basin. Most of the estimated spend will come from Saudi Aram- Imperial Oil Ltd.’s capital expenditures totaled $1,427 co, which awarded several notable oil field services contracts million in 2018. In 2019, capital expenditures are expected in 2018 for onshore and offshore rigs and unconventional to range $2.3-2.4 billion, including about $800 million as- gas stimulation services. The amount is more than twice that sociated with the Aspen in-situ project. of the second-highest spender, Abu Dhabi National Oil Co. Imperial Oil’s $2.6 billion Aspen project in northern Al- Latin America’s spending is expected to grow 11% to an berta is the first new oil sand development to be greenlight- estimated $34 billion (see sidebar, p. 24). This is up from a ed since 2013. decline of 6% in 2018. Brazil’s Petroleo Brasileiro SA (Petro- bras) and Mexico’s Petroleos Mexicanos (Pemex) are the top Elsewhere in Canada Latin American spenders at $13.2 billion (+19%) and $10.5 Imperial Oil’s capital spending on Canadian refining is ex- billion (+15%), respectively. For Petrobras, about 56% of pected to rise from $383 million last year. Cenovus Energy E&P capital is expected to go toward presalt, while the bal- and Husky Energy may also increase their spending on Ca- ance will go to postsalt. nadian refining this year. In Africa, Barclay’s report shows 12% spending growth Suncor’s spending on Canadian downstream ranges for 2019 to about $18 billion compared with 1% spending $700-770 million this year compared with $856 million for growth in 2018. The growth is driven by Algeria’s Sonatrach, 2018 and $634 million for 2017. Nigerian National Petroleum Corp., and Angola’s Sonangol Enbridge Inc., the country’s largest pipeline operator, se- along with Tullow Oil Ltd. and Kosmos Energy Ltd. cured total 2019 and 2020 capital program of $16 billion. Offshore spending is poised to fall another 7% in 2019. The company’s $5.3 billion Canadian Line 3 replacement Barclays expects 2019 to mark the fifth consecutive year of program is expected to enter service in this year’s second half. The $500-million Spruce Ridge expansion program and $1-billion T-South expansion program are both in pre- construction status. Fluor Builds. In 2019, TransCanada expects to spend $8 billion in 2019 Engineering ∙ Procurement ∙ Fabrication ∙ Construction ∙ Maintenance on growth projects, maintenance capital expenditures, and contributions to equity investments. TransCanada’s capital spending on Canadian natural gas pipelines totaled $2.18 billion in 2017 and $2.47 billion in 2018. As a comparison, its spending on US natural gas pipe- lines totaled $3.8 billion in 2017 and $5.7 billion in 2018. The estimated cost for secured gas pipeline projects in Cana- da could reach $5 billion in 2019, according to OGJ. Canada’s petrochemical industry is headed for its biggest surge of expansion spending in 5 years in 2019, thanks in large part to incentive programs by federal and provincial governments. EXCELLENCE EXECUTION • Several capital-intensive petrochemical projects have been announced in Canada, including Inter Pipeline’s $3.5-billon propane dehydrogenation and polypropylene complex in Strathcona County, Alta., Kuwait Petrochemi- cal’s $4-billion propylene complex, and NOVA Chemical’s $1.2-billion polyethylene plant expansion. Delivering integrated solutions for global International spending LNG liquefaction and regasification projects The latest Barclay’s E&P Spending Survey, released on Jan. for more than 50 years. 8, expects spending growth of at least 8% from almost every INNOVATION COST-COMPETITIVE www.fluor.com international region, with the exception being Russia and the FSU. International spending is forecast to reach $286 © 2019 Fluor Corporation. ADHO178019-B
billion in 2019. SAFETY • Despite the Dec. 6 decision to reduce production by 1.2
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offshore spending declines, although early signs point to a of their capital budget plans outside North America. potential 2020 inflection as the floater rig count is expected ExxonMobil’s spending for international upstream de- to end 2019 at 130 units, up from 116 currently. creased slightly to $12.5 billion in 2018 from $13 billion Barclays also reported that international upstream spend- in 2017. A key driver of international upstream growth in ing by NOCs and European IOCs are both expected to rise 2019 is in Guyana, where exploration success has added 3.2 by 8%. Spending growth from the European IOCs come af- billion boe (gross) of recoverable resource and plans are in ter international upstream spending fell by 4% in place for development and further exploration. 2018. Chevron’s international upstream spending will BP’s capital expenditures are expected to range decrease consecutively to $9.7 billion this year, $15-17 billion this year compared with $15 billion down from $10.5 billion for 2018 and $11.2 billion last year and $16.5 billion in 2017. for 2017. In 2019, about $4.3 billion is associated Equinor and Total SA’s capital budgets are esti- with the Future Growth Project at the Tengiz field mated at $11 billion and $16 billion this year com- SPECIAL in Kazakhstan. Global exploration funding is ex- pared with $9.9 billion and $15.5 billion last year. REPORT pected to be about $1.3 billion. US-based companies have also released details
IEA: Crude oil quality matters amid lower supply Global supply fell 1.4 million b/d to 99.7 million b/d in Janu- However, with less exports from PDVSA, headline bench- ary, according to data from the International Energy Agen- mark crude oil prices have hardly changed on news of the cy’s latest Oil Market Report. sanctions. This is because, in terms of crude oil quantity, The decline reflected factors including sanctions against markets may be able to adjust after initial logistical dislo- Iran, a supply fall in the Organization of Petroleum Ex- cations. Stocks in most markets are currently ample and, porting Countries of 930,000 b/d in January, US sanctions with the implementation of the new Vienna Agreement at against Venezuela’s state oil company Petroleos de Venezuela the start of the year, there is more spare production capacity (PDVSA), and Alberta supply cuts. available, IEA explained. These production cuts, however, all directly impact the supply of heavy, sour oil. Therefore, crude oil quality be- Crude oil quality spreads comes another important issue in the wider context of sup- The price of Mars—a medium, sour crude oil produced in ply in the early part of 2019, IEA said. the US Gulf of Mexico—has increased compared with light, sweet crude oil. Less exports from PDVSA The premium of Light Louisiana Sweet crude over Mars In 2018, about 450,000 b/d of Venezuelan crude oil was crude has fallen to below $1/bbl from more than $4/bbl in shipped to the US. This is only a fraction of the 1.7 million November. Since the US sanctions against Venezuela were b/d exported in 1998 when President Hugo Chavez was on announced, the premium of Mars over WTI has soared from the verge of power. Much of the oil is used in PDVSA’s US $4.50/bbl to over $7.50/bbl. refining system, run by its subsidiary Citgo Petroleum Corp. IEA said, “The collapse in exports mirrors the collapse Fundamentals of production over the same period from 3.4 million b/d to IEA’s global demand estimate for 2018 is unchanged at 1.3 about 1.3 million b/d today. In addition, Venezuela took a million b/d. Growth in demand in 2019 is expected to be political decision to ship oil to China; initially to diversi- 1.4 million b/d, unchanged from last OMR. The growth is fy export markets as Canada’s shipments to the US soared, supported by lower prices and the start-up of petrochemi- but more recently as repayment for tens of billions of dol- cal projects in China and the US. Slowing economic growth lars of loans. Shipments to India too, have grown, reaching will, however, limit any upside potential. 360,000 b/d in 2017, but last year they fell by 11%.” Global supply fell 1.4 million b/d to 99.7 million b/d in Meanwhile, PDVSA’s oil is typically of the heaviest quality January as the Vienna Agreement and Alberta’s cuts took and requires the addition of sufficient quantities of imported effect. Non-OPEC growth estimates have increased to 2.7 diluents or domestic blending. “With the import of diluents million b/d in 2018 and to 1.8 million b/d in 2019. This is now sanctioned by the US, and problems in producing its mainly due to higher US output. own lighter crudes, PDVSA will have a tough job to make OPEC crude output was 930,000 b/d lower in January at enough on spec barrels available for export. This is before it 30.83 million b/d, a near 4-year low. Compliance with the gets to the issue of who will buy them,” IEA said. Vienna Agreement was 86%, with Saudi Arabia, UAE and
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Kuwait cutting by more than promised. Compliance by non- feedstock based on gas reserve estimates that could fall well OPEC participants was only 25%. below delivery expectations. In December, global refining throughput fell 700,000 b/d The three plants, each with two LNG trains, are the year-over-year instead of an expected increase due to lower world’s first LNG producers to use CSG rather than gas from activity in Asia’s four largest refiners: China, India, Japan, conventional sources. The CSG is sourced from the Surat and South Korea. IEA’s 2019 forecast is unchanged, with and Bowen basins in southeast Queensland, however the runs expected to grow by 1.2 million b/d. wells supplying the gas have been less productive than ex- At yearend 2018, OECD oil company stocks were 5.6 pected. million bbl below the November level at 2,858 million bbl, Consequently the three plants have been running below up 4.6 million bbl compared with yearend 2017. The major capacity, operating at an average of 82% during 2018. stock build in the second half of 2018 was in non-OECD Queensland Curtis LNG (QCLNG) operated by Royal countries. Government stocks increased in 2018 by 22.1 Dutch Shell PLC, averaged 87% capacity last year, while million bbl, mainly in the US and Europe. Gladstone LNG (GLNG) operated by Santos Ltd., only aver- Brent futures reached a 2-month high of $62.75/bbl in aged 65% according to EnergyQuest Chief Executive Officer early February, with WTI prices about $10/bbl below aver- Graeme Bethune. age. The Brent-Dubai EFS narrowed to an 8-year low as sour “The emerging and critical shortages are resulting from crude markets tightened. Ample supplies of gasoline saw the fact that the CSG-LNG projects were sanctioned on am- cracks decline into negative territory. bitious estimates of 2P reserves, not proven (1P) reserves that underpin conventional LNG projects,” Bethune said. “Building six LNG trains in Queensland using CSG was bold and visionary, but ultimately a bridge too far,” he said. Queensland’s CSG-LNG plants The consultancy has made a detailed study of government unlikely to reach full capacity and company drilling and production data and reserves booked for CSG prospects and permits. It found that only Rick Wilkinson 56% of booked proved and probable reserves have shown OGJ Correspondent commercial productivity. Bethune forecasts that by 2025 at least two trains will The three LNG plants on Curtis Island near Gladstone in have to be shut down to keep four trains running at full ca- Queensland are unlikely to ever fulfill their combined name- pacity. This will reduce medium-term exports to about 17 plate capacity of 25.3 million tonnes/year, according to a million tpy, down from 21 million tpy in 2018. About 70% new study by Adelaide-based energy analyst EnergyQuest. of the LNG exports go to China, 16% to South Korea, and The problem is a shortage of coal seam gas (CSG) reserves 9% to Japan. on which they rely. The consultancy’s report indicates that Bethune said the supply problem has been exacerbated by the supply concerns come from an emerging reliance on the pressure on the producers to increase gas sales into the
• Reduce Time in Recycle • Minimal Deadtime • Expand Compressor Map • Fast Stroking Speeds • Increase Throughput • Accurate Modulating Control
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Eastern Australian domestic market to shore up falling supply tential to hold up to 15 tcf of recoverable gas resource and is from aging conventional gas fields, particularly offshore. Not seen as a world-scale prospect in a proved gas-prone basin. helping the shortage is the attitude of some states, notably New Ironbark is a Mungaroo formation prospect with a South Wales and Victoria, which restrict onshore exploration mapped area of up to 400 sq km. It lies less than 50 km from drilling. The three CSG projects in Queensland supplied about the North West Shelf joint venture’s North Rankin platform. 25% of Australia’s eastern demand last calendar year. It is also close to Chevron Corp.’s Wheatstone infrastructure and Woodside Petroleum Ltd.’s Pluto infrastructure, thus providing multiple development options if gas is found. The permit partners BP PLC, Cue, Beach Energy Ltd., and BP lets rig contract for New Zealand Oil & Gas Ltd. (NZOG) reported a coordina- tion agreement in October 2018 that provides for BP to act as Ironbark wildcat off operator on behalf of Cue in planning the Ironbark wildcat prior to title transfers and creation of a formal joint venture. Western Australia As required under this agreement, Cue has contributed $8.087 million from its existing cash reserves into an es- Rick Wilkinson crow account to secure the proportion of its costs that are OGJ Correspondent not carried by other parties. With funding from the other parties on completion of the agreement, full funding for the BP Developments Australia Pty. Ltd., acting operator of a well is agreed. joint venture in Western Australian offshore exploration Execution of the rig contract and Cue’s funding of the es- permit WA-359-P, has signed a contract for a rig to drill the crow account satisfy two outstanding conditions of comple- Ironbark-1 wildcat well. tion of the coordination agreement, the BP Option agree- Diamond Offshore Drilling Inc.’s Ocean Apex semisub- ment and farm-in agreements with Beach and NZOG. mersible drilling rig will begin the program during next Regulatory approval of an extension to the WA-359-P year’s second half. Ironbark-1 is expected to drill to a depth permit to allow time to drill is also required and Cue is cur- of 5,500 m. rently preparing an extension application for submission to After many delays, mostly to do with permit leasehold- the Australian National Offshore Petroleum Titles Admin- er Cue Energy Ltd. offsetting the forthcoming exploration istrator. program costs through farm-in deals, the rig contract sets a When all conditions are satisfied, and regulatory approv- path to fulfillment of the drilling program. BP has now ini- als are received, the coordination agreement provides for BP tiated environmental planning activities for a site survey of to become official operator. The participating interests in the well location and the drilling activities. the well will then be BP 42.5%, Cue 21.5%, Beach 21%, and Ironbark, in the offshore Carnarvon basin, has the po- NZOG 15%.
APLNG to buy Ironbark coal seam gas prospect from Origin Energy Rick Wilkinson ment of Ironbark. Company Chief Executive Officer Frank OGJ Correspondent Calabria explained, however, that the sale represents the best way for Origin to maximize value from the project. The Australia Pacific LNG (APLNG) combine has agreed to “APLNG is able to realize additional value from the Iron- acquire the Ironbark coal seam gas (CSG) project from Ori- bark asset by utilizing its existing nearby gas and water gin Energy Ltd., Sydney, for $231 million (Aus.). Ironbark— processing infrastructure to efficiently bring the gas to not to be confused with the BP PLC-led group’s conventional market,” Calabria said. “Origin will derive value from the gas prospect of the same name offshore Western Australia— development of the prospect through its investment in lies near Tara in the Surat basin of southeast Queensland. APLNG.” APLNG uses CSG from southeast Queensland coal seams If Origin still owned Ironbark, the company would have to produce LNG at its liquefaction plant on Curtis Island, had to enter negotiations with its APLNG partners (Cono- near Gladstone. coPhillips with 37.5% and Chinese state-owned Sinopec Ironbark has been a disappointment for Origin, which with 25%) to process and transport the gas and this could halved the project’s production potential last year from 249 have caused concern. petajoules down to 129 petajoules of gas resource. Origin acquired Ironbark for $660 million (Aus.) in 2009 Origin is a 37.5% interest holder and operator of the and initially estimated the resource at 840 petajoules. It sub- APLNG group, so it will retain responsibility for develop- mitted proposals in 2015 for the drilling of up to 600 wells
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so that the project could supply about 21 petajoules/year of tries Co. Ltd. and Liaoning Transportation Construction CSG over 40 years. Investment Group Co. Ltd. to develop a retail fuel stations Development plans dwindled at regular intervals as more network in target markets. exploration and engineering work was carried out. The com- pany finally began a Stage 1 front-end engineering and design Additional Chinese agreements program in August 2018, but it was obvious by then that per- Separately, Aramco also signed three memoranda of under- meability problems in the coal seams had halved the potential standing aimed at expanding its downstream presence in reserves such that the project would contribute less volumes China’s Zhejiang province. of gas over fewer years. Aramco signed the first MOU with the government of Origin entered the FEED program, but at the same time Zhoushan to acquire its 9% ownership interest in Zhejiang began assessing alternative strategic options for development. Petrochemical Co. Ltd.’s (ZPC) grassroots 800,000-b/d re- The result has been the sale of Ironbark to APLNG, albeit at a fining and chemical integrated complex currently under third of the price it paid for the asset 10 years ago. construction in Zhoushan, with a second MOU signed with ZPC’s other shareholders Rongsheng Holding Group Co. Ltd., Juhua Group Corp., and Tongkun Group Co. Ltd. (OGJ Online, Feb. 14, 2017). Aramco forms combine Aramco inked a third MOU with Zhejiang Energy Group to invest in construction of a large-scale retail fuel network for $10-billion Chinese to be built during the next 5 years in Zhejiang province that will be integrated with ZPC’s complex as an outlet for re- refining complex fined products produced at the site. The new MOUs follow Aramco’s previous agreements Robert Brelsford with ZPC under which Aramco agreed to acquire owner- Downstream Technology Editor ship interest in and supply crude on a long-term basis to the new complex, as well as use ZPC’s crude storage at the site Saudi Aramco has signed a $10-billion agreement to form to serve Aramco customers in the Asia-Pacific region (OGJ a joint venture with China North Industries Group Corp. Online, Oct. 26, 2018). (Norinco) and Panjin Sincen to develop a fully integrated, The project will come with a long-term crude supply grassroots refining and petrochemical complex in Panjin, in agreement and the ability to utilize Zhejiang Petrochemical’s China’s Liaoning province. large crude oil storage facility to serve its customers in the Under the agreement—the largest Sino-foreign JV to Asian region. date—the partners will create a new company—Huajin Previously scheduled for commercial startup by year- Aramco Petrochemical Co. Ltd.—as part of a project that end 2018, Phase 1 of ZPC’s project includes a newly built will include a 300,000-b/d refinery as well as a 1.5 million- 400,000-b/d refinery, a 1.4 million-tpy ethylene cracker tonne/year ethylene cracker and 1.3 million-tpy paraxylene unit, and a 5.2 million-tpy aromatics unit. unit, Aramco said. Phase 2 of the project—which will double processing Alongside supplying up to 70% of required crude feed- and production capabilities at the site, as well as include stock for the proposed complex, Aramco will hold 35% deeper chemical integration than Phase 1—most recently interest in the newly formed company while Norinco and was scheduled for commissioning during first-quarter 2021 Panjin will hold the remaining 36% and 29% interest, re- (OGJ Online, Jan. 17, 2019). spectively. The new complex is scheduled for commercial startup sometime in 2024. “Our participation in the integrated refining and petro- Meridian Energy plots grassroots chemical project in Panjin will strengthen our collaborative refinery for Permian basin efforts to enhance energy security, revitalize key growth sectors and industries in Liaoning, and also meet rising de- Robert Brelsford mand for products and goods in China’s northeast region,” Downstream Technology Editor said Amin Nasser, Aramco’s chief executive officer. The JV agreement also includes additional plans to es- Meridian Energy Group Inc. has let a contract to Winkler Cos. tablish a fuels retail business, which will further integrate LLC to provide site control for a full-conversion refinery in into the value chain, Aramco said. Winkler County, Tex., in the heart of the Permian basin. By yearend, Aramco said it expects to form a three-party The Permian basin refinery, which will process local marketing JV company with North Huajin Chemical Indus- crude from the Delaware basin into a full slate of refined
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products for local and regional markets, will have a through- put capacity of about 60,000 b/d and be modeled after Me- NAPE: Croatia opens ridian’s grassroots 49,500-b/sd high-conversion Davis refin- ery currently under construction in Billings County in the licensing round in heart of southwestern North Dakota’s Bakken shale region, Meridian said. Dinarides onshore area With site control now established for the new Permian basin plant, Meridian said it will proceed with design and Paula Dittrick permitting of the newly proposed refinery that—like its Da- Upstream Technology Editor vis refinery—the operator intends will be permitted under classification as a synthetic minor source (SMS) of air con- Croatia has opened a licensing round for oil and gas explora- taminants (OGJ Online, Dec. 5, 2018; Dec. 6, 2017). tion in its central and southern regions with the bid deadline “Meridian’s success on the Davis [r]efinery demonstrates being Sept. 10. Licenses are tentatively scheduled to be an- that the domestic refining industry is ready for fundamen- nounced in December, a spokesman with the Croatia Hy- tal change, and Meridian believes that the crude supply and drocarbon Agency (CHA) said. strong demand from the refined products markets indicate CHA Pres. Marijan Krpan told the North American that the Permian [b]asin is the next place for Meridian to Prospect Expo in Houston on Feb. 14 that Croatia recently locate a Davis-style crude refinery,” said William Prentice, enacted a hydrocarbon law to attract investors and ensure Meridian’s chairman and chief executive officer. what he calls a smoother transition from exploration into Prentice said Meridian’s analysis indicates that there may production. even be a need for more than one such plant to fully serve Since the 1940s, Croatia has produced more than 400 the needs of the Permian basin. million boe, most of which has been natural gas. Krpan said The proposed refinery comes amid a growing need for Croatia has produced more than 700 million bbl of oil. regional refining capacity as well as additional crude storage Available exploration blocks in Croatia’s Dinarides thrust and blending in the rapidly expanding Delaware basin, said belt cover 12,134 sq km. Krpan said some seismic surveys Winkler Manager David Lynch. were shot in this area during the 1950s. “With [the International Maritime Organization’s 2020 Meanwhile, Croatia has an ongoing bid round for the regulations requiring reduced sulfur levels in marine fuels Pannonian basin that started in November 2018 with a bid in 2020] bearing down on the US refining industry, Merid- deadline of June 28. Awards are expected to be awarded in ian could not be better positioned to take advantage of the October. building demand for [ultralow-sulfur diesel (ULSD)] that The second round involves seven exploration blocks in can be transported from this location by truck, rail, or pipe,” the Pannonian basis, Krpan said. “Total acreage available is said Lynch. 14,272 sq km. The available blocks range in size from 1,361 Once the refinery is in operation, Indeca Crude Express to 2,634 sq km.” LLC—a sister company of Winkler and regional crude haul- He said at least 37 unevaluated wells exist in this area. er—will participate in the project by enabling gathering The Pannonian basin is characterized by Palaeozoic to Me- of trucked crude barrels as well as distribution of finished sozoic sedimentary deposits. product to a ready market, Lynch confirmed. Previously, Croatia offered six onshore exploration Meridian has yet to reveal a definitive timeline for the blocks in its first onshore bid round, which it launched in newly proposed Permian basin refinery. July 2014. That round covered the Pannonian subbasins of The North Dakota Department of Health’s division of air Drava, Sava, and Eastern Slavonia. quality previously issued Meridian the final permit-to-con- Croatia awarded a block to Croatia’s state-owned INA struct the Davis project—under the first application in his- Group and four blocks to Canada’s Vermilion Energy Inc. tory for a full-conversion refinery of this size and complexity In Croatia, Vermillion holds 100% working interest in acre- to seek and receive permitting to construct under classifica- age covering nearly 2.35 million acres. tion as SMS of air contaminants—in June 2018 (OGJ Online, The American Association of Petroleum Landmen is the June 13, 2018). chief sponsor of NAPE, where industry buys and trades Scheduled for startup sometime in 2020, the Davis re- prospects and producing properties. finery, once in operation, will produce ULSD and premium gasoline from prolific crude feedstocks from the Bakken shale basin using advanced technologies intended to maxi- mize operational efficiencies while minimizing environmen- tal impacts (OGJ Online, Dec. 7, 2018).
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Roman Opimakh Association of Gas Producers of Ukraine Kyiv, Ukraine
Ukraine has outlined a series of licensing rounds The 2019 first round, announced Dec. 6, 2018,
through online auctions and production-sharing EXPLORATION & offers 10 blocks in six regions, covering more than agreement (PSA) tenders in ongoing efforts to re- DEVELOPMENT 1,120 sq miles.A second round, announced in Lon- duce its dependence on natural gas imports. The don Jan. 29, offers another 7 blocks in five regions, 2019 licensing rounds offer 42 onshore blocks cov- covering over 621 sq. miles. Bidders were asked to ering nearly 12,000 sq miles. submit applications within 90 days with the online auctions Government officials have improved the fiscal regime, sim- scheduled for Mar. 6 and May 2, respectively. plified the permitting system, and adjusted the rules for access In addition, the Ukrainian government approved PSA ten- to gas and oil reserves to increase Ukraine’s upstream attractive- der terms for 12 onshore blocks covering more than 8,200 sq ness to international oil companies. miles. PSA tenders are expected to be announced in February The licensing rounds are being offered in stages. The or beginning of March, at which time bidders will have three State Geological Service of Ukraine released 30 onshore pe- months to submit their applications. The onshore blocks hold troleum blocks for sale in online auctions on public trading both conventional and unconventional resources. platform ProZorro.Sale. Royal Dutch Shell and other IOCs showed interest in Fig. 1 shows the licensing offerings for 2019 plus valid Ukraine during 2010-12, particularly in the possibility of de- exploration and production licenses. veloping unconventional gas resources (OGJ, June 6, 2013,
UKRAINE LICENSING ROUNDS FIG. 1
BELARUS POLAND Dnipro-Donets basin
RUSSIA Pre-Carpathian basin
Kharkiv Lviv UKRAINE Rollava Ivano- Frankivsk
Carpathian MountainsChernivtsi
MOLDOVA 2019 PSAs 2019 licenses North Black Sea basin Kherson Valid contracts:* Odessa Exploration ROMANIA Black Sea Azov Sea E&P Production PSA
*Exploration licenses cover 5 years onshore, 10 years offshore, combined E&P licenses cover 20 years onshore, 25 years offshore, production licenses cover 20 years. Source: GoUkraineNow
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p. 54). But changing market conditions NE G O CT ON FIG. 2 caused Shell to pull out of a May 2012 PSA. Shell was the winning bidder for 70 68.4 the Yuzivske PSA in the Kharkiv and 20% 60 Donetsk regions of Eastern Ukraine. 5.5% 20.5 Resources were estimated at 4 trillion 50 bcm cu m of gas, trapped primarily in tight sand formations. Estimated explora- 40 74.5%
tion costs were at least $20 million. bcm 30 UGV Ukrnafta Shell and state-owned Nadra Yuz- Private companies 20.5 ivske were each to hold a 50% interest 20 with Shell to be the operator. Howev- er, Shell withdrew from the project in 10 2015, citing high costs and dropping 0 commodity prices. 1945 1955 1965 1975 1985 1995 2005 2015 2017 The 2019 Ukrainian PSAs are the Western Ukraine Eastern Ukraine Offshore first to be offered since then. As of Feb. Source: Ukraine Ministry of Energy 1, EP Holding (EPH) was working to gain Shell’s stake in the 2012 Yuzivska PSA. Ukrainian government officials expect to finalize that mand at 30-35 bcm/year until 2035. as soon as EPH submits a bank guarantee that EPH can in- Prices for Ukrainian gas are in parity with imported gas vest $200 million. prices, ensuring profits for gas producers. In 2018, the av- In a different deal, EPH agreed to drill at least 15 explora- erage wholesale price for Ukrainian gas was $9.20/MMbtu. tion wells within 5 years. Finalization of the pending agree- Ukraine has 905 bcm of gas reserves across two proved ment remains subject to approval by regional councils and petroleum basins with another 408 bcm estimated resourc- an anti-monopoly committee. es. The reserves-production (R-P) ratio is nearly 45 years EPH currently holds 90% interest. Its partner is Nad- compared with an average European R-P of 12 years. ra Yuzivska, which represents Ukraine in this legacy deal. Fig. 2 shows gas production by region and by company EPH’s subsidiary, Nafta, will operate the project. The Slovak in Ukraine. Producers operating in Ukraine believe they can Republic owns 25% interest of Nafta. EPH holds 75% inter- produce most proved, undeveloped reserves through im- est. proved recovery methods and by expanding existing fields Government officials also see opportunities to redevel- with satellite fields. op legacy fields. Mature fields require technologies and ex- Ukraine has a well-developed gas pipeline system with pertise from international service companies. State-owned surplus capacity, which is used both for domestic gas distri- UkrGasVydobuvannya (UGV) has signed multiservice bution and for transporting Russian gas to Europe. agreements with Schlumberger Ltd., Halliburton Corp., The state-run transmission system operator ensures Baker Hughes GE, and Weatherford. third-party access to gas pipelines under equal, non-dis- UGV also seeks additional cooperative partnerships un- criminatory, and transparent terms in line with European der Production Enhancement Contracts (PEC) to develop energy laws. depleted fields and unconventional formations. The PEC The National Regulatory Commission sets gas transpor- tender was launched in October 2018. Results are scheduled tation, distribution, and storage tariffs using Regulatory As- to be announced in May. set-Based (RAB) methodology and based on the European Ukraine produced more than 21 billion cu m (bcm) of entry-exit booking capacity approach. gas in 2018, one of Europe’s largest outputs, yet still depends Ukraine has no restrictions or special duties on gas im- heavily on imported gas. The Ukrainian government is pri- ports or exports, and gas exports to central Europe were oritizing domestic production to reduce imports and en- scheduled for January. No trade permits are required. hance energy supply security. Rigs are readily available in Ukraine, where 150 onshore gas wells were spudded in 2018. A qualified local workforce, Gas supply, demand wide range of services, and existing supply chain for pipes Gas accounts for 35% of Ukraine’s energy mix. In 2018, and cement also ensure companies can increase gas produc- Ukraine consumed 31.5 bcm, making it the seventh largest tion volumes quickly. Yet, Ukraine needs additional IOC in- consumer in Europe. Imports accounted for 34% of 2018 vestment and technology to reach its production potential. domestic consumption. The Ukraine Parliament enacted upstream reforms in 2018 The Energy Strategy of Ukraine estimates future gas de- to attract more international investment.
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Ukraine revised its taxation system for onshore gas wells reserves, 73% are found at depths of 3,000 m or deeper. In drilled in 2018 and later to help attract investors from outside Western Ukraine, 65% of reserves are found above 3,000 m. Ukraine. Currently, gas produced from such wells is subject to The 17 blocks offered in Round 1 and Round 2 and 12 6% or 12% royalties depending on depth of reserves. PSAs blocks are in proved petroleum provinces with well- The government guarantees the stability of these rates developed midstream infrastructure and completed seismic through a 5-year stabilization clause. Five percent of the roy- surveys. License terms for 16 of the concession blocks call alty payment is allocated to local communities’ development for 20 years of exploration and production, the final block to motivate their cooperation with industry. calling for a 5-year exploration period. All PSAs block have Ukrainian regulators simplified a prescriptive, outdated 50-year duration, unless otherwise agreed by the parties. permitting system by signing a deregulation law which cut The web site GoUkraineNOW outlines the geology and government red tape and updated exploration and produc- overview for the auction and PSA blocks.2 tion rules. This streamlining means production could start Ukraine officials offered large parcels in known petro- 18 months after licensing. leum provinces to give oil and gas companies a better chance Parliament also approved an Extractive Industries Trans- to find discoveries. parency Initiative (EITI) covering international standards of The table shows the three biggest PSA blocks in eastern public reporting. Government officials adjusted reserves-ac- Ukraine are Varvinska, Sofiyvska, and Ichnyanska. Most gas cess and transparency rules by authorizing online auctions, in this petroleum basin is trapped in the Carboniferous sec- improving public access to geological data, and liberalizing tion below a lower Permian salt seal. companies’ turnover of geoscience information to the gov- ernment. References 1. Association of Gas Producers of Ukraine, “Ukraine Geology National Gas Production, Playbook 2018.” Ukraine offers three main hydrocarbon basins: Dniepr-Do- 2. Gas and Oil Ukraine Now, “Ukraine 2019 licensing nets basin, Pre-Carpathian basin, and the North Black Sea rounds: A big attraction for oil and gas investors,” www. basin. Almost all production comes from onshore fields.1 goukrainenow.com The Dnieper-Donestsk region in eastern Ukraine is devel- oped with several thousand gas, oil, and condensate wells. The author Companies have found gas in depths ranging 5,000-5,800 m Roman Opimakh is executive director of the As- and oil as deep as 4,500 m. The Association of Gas Produc- sociation of Gas Producers of Ukraine (AGPU). ers of Ukraine (AGPU) reports 244 conventional oil and gas Opimakh previously advised the Minister of fields producing in this province. Energy of Ukraine. During 2011-15, he worked The Pre-Carpathian (Foreland) basin in Western Ukraine as a coordinator for oil and gas at the Economic covers 7,500 sq km and reaches the borders of Hungary, Po- Reforms Center where he supervised various land, Slovakia, and Romania. AGPU reports 116 convention- energy projects. Opimakh obtained an MS al oil and gas fields producing in this area. (2006) from the Institute of International Relations of Taras The North Black Sea basin is less explored, with 42 oil Shevchenko National University of Kyiv. He later participated in and gas fields, including 15 offshore fields, AGPU reports a 1-year Hubert H. Humphrey Fellowship Program at Michigan About 95% of gas production and most onshore oil and State University and completed his professional affiliation with gas reserves are concentrated in eastern Ukraine, primarily the Center for Energy Studies at Louisiana State University. in the Kharkiv and Poltava regions. Of Eastern Ukrainian
UKRAINE’S INITIAL 2019 PSA TENDERS Block name Region Area, Minimum sq km investment, million $ Varvinska Poltava-Chernihiv 3,471 35.7 Rusanivska Sumy-Poltava 766 28.5 Grunivska Sumy-Poltava 1,108 30.3 Ohtirska Sumy-Poltava-Kharkiv 717 21.4 Buzivska Kharkiv-Dnipro 669 21.4 Zinkivsha Sumy-Polava 571 17.8 Ivanivska Kharkiv 841 28.5 Ichnyanska Chernihiv 2,477 35.7 Balaklijska Kharkiv 1,119 28.5 So yivska Chernihiv-Sumy-Poltava 2,716 35.7 Berestyanska Lviv-Kharkiv 286 16.0 Ugnivska Lviv-Ivano-Frankivsk 967 21.4 Source: GoUkraineNow
Oil & Gas Journal | Mar. 4, 2019 33
190304OGJ031-033.indd 33 2/26/19 3:09 PM TECHNOLOGY IEA updates EOR project data, doubling output forecast
The International Energy Agency (IEA) estimated PDO and GlassPoint are building Miraah solar plant about 375 enhanced oil recovery projects world- (OGJ, Jan. 1, 2018, p. 46). A separate solar EOR tech- wide produced slightly more than 2 million b/d in nology center is being developed in Muscat, Oman. 2018. They forecast this could grow to 4.5 million PDO reported 16% of its oil production came from b/d, or around 4% of world production, by 2040. various types of EOR in 2016 compared with 3% in
EOR projects accounted for about 2% of world DRILLING & 2012. oil production since 2014. IEA analysts expect mod- PRODUCTION Abu Dhabi National Oil Co. Onshore (ADNOC
est EOR production growth until about 2025, not- Onshore) injects CO2 into Bab-Rumaitha field. AD- ing industry currently focuses on shale production NOC uses low-molecular-weight hydrocarbon-im- growth in US, Brazil, and Canada. miscible (HC) gas injection to increase production from Abu
They also suggest carbon dioxide (CO2) EOR could ad- Al Bukhoosh (ABK) field offshore Abu Dhabi. UAE’s goal is to
dress climate change concerns. IEA expects CO2 EOR to play expand EOR production 30% by 2020 from 2014. an increased role in carbon capture, utilization, and storage Currently, North American EOR accounts for 40% of all (CCUS) projects. EOR projects compared with 75% of 2013 EOR projects, IEA released an updated list of EOR projects1 and evaluated which provided 800,000 b/d. the outlook for future EOR in different scenarios presented in its World Energy Outlook.2 EOR incentives Fig. 1 shows IEA’s tally of EOR production to be 700,000 While EOR projects can be cost competitive with other pro- b/d higher than an Oil & Gas Journal EOR survey reported in duction, they frequently involve high upfront capital re- 2014 (OGJ, May 5, 2014, p. 92). While updating EOR produc- quirements and long payback periods. Consequently, EOR tion statistics from the OGJ database, IEA added new proj- production historically relied on financial incentives such ects and reviewed EOR in regions sparsely covered previously, as tax breaks. such as China and the Middle East. More than 80% of world EOR production benefits from Industry traditionally used EOR primarily for US and Ca- government incentive programs. National oil companies pri- nadian projects but the technology increasingly is being used oritize EOR in efforts to maximize production and profits. worldwide, both onshore and offshore. IEA reported 15 off- IEA said US policy demonstrates how government can shore EOR projects worldwide as of 2018. promote EOR projects. Faced with declining US oil produc- ExxonMobil Exploration and Production Malaysia Inc. tion, the Crude Oil Windfall Profit Tax Act of 1980 promot- started EOR production at Tapis field offshore Malaysia dur- ed EOR by reducing producers’ EOR-related taxes. ing 2017. Last year, a federal tax credit was amended under sec- The Tapis EOR project marked Malaysia’s first large-scale tion 45Q of the US tax code to promote underground carbon EOR project and remains one of the largest offshore EOR proj- storage. The amendment increased the amount of money ects in Southeast Asia. ExxonMobil’s joint venture partner is available to companies willing to capture and store carbon
Petronas Carigali Sdn Bhd (PCSB). Each holds 50% interest. emissions in geologic formations or to use CO2 EOR on ex- IEA’s EOR update lists projects in the United Arab Emir- isting wells. ates, Kuwait, Saudi Arabia, India, Colombia, and Oman. The tax credit was amended to provide a tax reduction
Oman has increased its oil production since 2007 through of $35/tonne of CO2 for 12 years for CO2 stored in EOR op- steam injection, polymer injection, miscible gas injection, erations. Previously, the tax credit was $10/tonne but it will and other EOR methods. Oman is evaluating large-scale so- increase to $35/tonne by 2024. lar EOR projects to save natural gas. Petroleum Development Yet, EOR project growth has been slower than expected. Oman (PDO) is working with GlassPoint Solar. After a pilot, IEA analysts found no one reason for this, but possible ex- planations included: Adapted with permission from International Energy Agency’s • Resource scarcity concerns. These traditionally drive “World Energy Outlook 2018” commentary. EOR projects, but ample world oil supplies have discouraged
34 Oil & Gas Journal | Mar. 4, 2019
190304OGJ034-035.indd 34 2/26/19 3:09 PM new EOR projects since 2014. In the WEO’s New Policies Scenario projections, only a • Industry desire for fast returns. An EOR project re- fraction of that 300 billion bbl is produced. By 2025, IEA quires time to plan, test, and implement, meaning that EOR analysts foresee larger production related to EOR projects. adds incremental production only late in a field’s life. US tight oil will near its production plateau and numerous • Limited availability of EOR skills, technologies, and regions and countries also will have become mature produc- expertise. The technology has become a niche business tion provinces by 2025, making them more inclined to pur- among oil and service companies. sue EOR to maintain production or slow declines. • Relative expense. EOR costs have declined since 2014, Numerous measures and initiatives will need to gain mo- but costs of other projects—including shale plays and offshore mentum before EOR production growth forecasts can mate- developments—have declined more quickly. EOR technolo- rialize. Examples of such efforts include: gies struggle to compete with other investment opportunities. • Concerted effort by governments and industry to screen fields and determine EOR potential in resource-rich EOR outlook areas. IEA analysts evaluated EOR prospects in the World Ener- • Timely EOR pilots in countries where EOR has not yet gy Outlook. They estimated that systemic application of all been used. EOR technologies across conventional crude oil resources • Continued fiscal incentives, including emissions cred-
could, in theory, unlock up to 300 billion bbl of crude oil. its for CO2 EOR. • Technological advances such as decreasing the volume of chemicals in- EOR PROJECTS OPERATING WORLDWIDE FIG. 1 jected and using digitalization to grasp a better subsurface understanding. 400 In the WEO Sustainable Develop- Thermal CO2-EOR ment Scenario, total EOR production 300 Chemical grows to around 4 million b/d in 2040. Natural gas injection, nitrogen injection This is smaller than WEO’s New Poli- Other technologies cies Scenario because oil demand and (microbial EOR, 200 combustion EOR) prices are lower. Projects However, CCUS advancements could support much larger CO -EOR 100 2 production. In this scenario, climate imperatives emerge as a key driver be- 0 hind EOR technologies. Given suitable geology, companies can use CO EOR
2017 2
1971-75 1976-80 1981-85 1986-90 1991-95 2001-05 2006-10 2011-15 to reduce their CO2 emissions inten- 1996-2000 sity. If CO is captured and injected in Source: IEA World Energy Outlook 2 enough quantities, negative-emissions carbon credits could be available for oil.
EOR PRODUCTION FIG. 2 Oil produced from a CO2-EOR seques- tration project can be carbon neutral or 5 Thermal carbon negative, depending upon the Chemical EOR source of the CO2 emissions. CO -EOR 4 2 IEA analysts evaluated the possi- Natural gas injection, nitrogen injection bility of negative-emissions oil in the World Energy Outlook and expect to 3 publish a future commentary on it.
Thousand b/d 2 References 1. Han, M., McGlade, C., and Son- dak, G, “Commentary: Whatever hap- 1 pened to enhanced oil recovery,” Nov. 28, 2018, International Energy Agency
0 web site. 2000 2005 2010 2015 2020 2025 2030 2035 2040 2. IEA, “World Energy Outlook Source: IEA World Energy Outlook 2018.”
Oil & Gas Journal | Mar. 4, 2019 35
190304OGJ034-035.indd 35 2/26/19 3:09 PM TECHNOLOGY US olefins industry turns to face global market
Dan Lippe Petral Consulting Co. Houston
Like the characters of L. Frank Baum’s Oz Ethylene production series of novels written during the early PROCESSING Petral Consulting tracks US ethylene production via a 1900s, US ethylene producers have had monthly survey of operating rates and feed slates. Results to find their way to the mythical Emerald of the monthly survey showed a City by surviving a series of disasters. strong rebound in ethylene produc- After the storms of second-half 2017, tion in first-quarter 2018 following US Gulf Coast skies cleared in first-half the hurricane-depressed produc- 2018, with most USGC ethylene produc- tion rates of late 2017. Production ers finding soft landings in second-half in first-quarter 2018 increased 2018. Ethylene producers took the first 14.2 million lb/day (8.4%) from steps on the journey to the Emerald City fourth-quarter 2017 before quarter- in fourth-quarter 2018. ly growth slowed to 4.3 million lb/
USGC ethylene producers had booked US OLEFINS day (2.4%) in second-quarter 2018. their tour to Emerald City via the Yellow Production during third-quarter Brick Road several years ago. But now, in 2018 was 179.3 million lb/day, un- 2019-20, they will have to focus on surviving the journey. changed from the previous quarter. Production, however, in- Trends in polyethylene exports indicate production from creased to 183 million lb/day in fourth-quarter 2018, up 3.7 new polyethylene plants began to ramp up to full capacity in million lb/day (2.0%) from the third quarter. second-half 2018. The transition of focus from North Ameri- Variations in quarterly growth rates for ethylene produc- ca to the global market for ethylene, polyethylene, and other tion paralleled growth in polyethylene exports to destina- ethylene derivatives is well under way. tions other than Canada and Mexico (rest of world, ROW). Exports to ROW destinations in first-quarter 2018 were 4.6 New plant startups million lb/day (49.8%) more than in fourth-quarter 2017. In second-half 2018, ExxonMobil Chemical Co., Shintech Growth in polyethylene exports slowed to 0.99 million lb/ Louisiana LLC, and Indorama Ventures Olefins LLC were day (7.2%) in second-quarter 2018 before rebounding to scheduled to start up new ethylene plants. ExxonMobil 1.79 million lb/day (12.2%) in the third quarter. The trend Chemical was the only producer to meet its target, commis- in polyethylene exports to ROW destinations in second-half sioning its new 1.5-million tonne/year ethane steam cracker at Baytown, Tex., in late July (OGJ Online, July 26, 2018). In first-half 2019, Formosa Petrochemical Corp., Indorama, Feedstock prices, coproduct values, and ethylene plant yields Sasol Ltd., and LACC LLC—a 50-50 joint venture of Lotte determine ethylene production costs. Petral Consulting maintains Chemical Corp. subsidiary Lotte Chemical USA Corp. and direct contact with the olefin industry and tracks historic trends in Westlake Chemical Corp.—are scheduled to commission spot prices for ethylene and propylene. We use a variety of sources new plants with combined nameplate capacity of 9.1 billion to track trends in feedstock prices. lb/year. Petral Consulting Co. also forecasts Shintech’s new Some ethylene plants have the necessary process units to convert plant will start operations second-half 2019. all coproducts to purity streams. Some ethylene plants, however, While some new plants reach full-capacity in 30-60 days, cannot upgrade mixed or crude streams of various coproducts and sell some or all their coproducts at discounted prices. We evaluate others require 3-4 months. Since ethylene supply is already at ethylene production costs in this article based on all coproducts modest surplus levels, production from new plants in Louisi- valued at spot prices. ana will increase surpluses in USGC markets in first-half 2019.
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190304OGJ036-043.indd 36 2/26/19 3:09 PM 2018 was a positive leading indicator of the trend in USGC upgrade all coproduct streams to meet purity specifications. ethylene production rates for 2019 and 2020. A few ethylene plants can upgrade all coproducts to pu- Petral Consulting estimates industry nameplate capacity rity streams and sell all coproducts at market prices. Some in operation was 189.1 million lb/day in first-quarter 2018. ethylene plants produce purity coproduct propylene but Production capacity increased to 198 million lb/day in sec- produce all other coproducts as mixtures (mixed butylene- ond-quarter 2018 and was 206.5 million lb/day in the fourth butadiene and mixed aromatics) and sell mixtures at dis- quarter. counted prices. Variations in realized revenue for coprod- On a regional basis, plants in Texas accounted for all pro- ucts result in large differences in coproduct credits from one duction growth in second-half 2018. Texas plants produced plant to another. Cash production costs are determined by 131.8 million lb/day in the third quarter and 135.8 million simple addition of raw material costs and coproduct credits lb/day in the fourth quarter. Production from Texas plants in (see accompanying box). third-quarter 2018 increased 1.4 million lb/day from the sec- Crude oil price trends are always a strong influence on ond quarter, and fourth-quarter production increased 4 mil- prices for propane, naphtha, gas oil, and most coproducts. lion lb/day (3.1%) more than in the previous quarter. Plants in Domestic crude oil prices reached their peak in May 2018 Louisiana produced 41.3 million lb/day in third-quarter 2018 and began to decline in June primarily because of con- and 40.7 million lb/day in the fourth quarter (Table 1). straints in crude pipelines from West Texas to the Texas Gulf Operating rates dipped to 85.6% in second-quarter 2018 Coast. Prices for international benchmark crudes continued and were 86-90% in second-half 2018. Texas plants oper- to increase in second-quarter 2018 but settled into a pla- ated at 86.3% in third-quarter 2018 and 89.0% in the fourth teau during the third quarter. International benchmark pric- quarter, while plants in Louisiana operated at 87.5% in the es began to decline in second-half October and continued third quarter and 86.2% during the following quarter. to fall in November and December. Initially, the decline in Results of the monthly survey showed some USGC eth- second-half October appeared to be a short-lived correction ylene producers curtailed operating rates in several existing following 15 months of steadily rising prices, but correction plants during second-half 2018 to limit ethylene oversupply became a collapse in November. in the Texas Gulf Coast spot market. Petral Consulting esti- The collapse in crude, motor gasoline, and naphtha pric- mates ethylene production from Texas and Louisiana plants was reduced by 9-10 million lb/day due to these curtail- ments, offsetting production from ExxonMobil Chemical’s ETHYLENE PRODUCTION Table 1 Heavy feed Light feed Total new 3.3-billion lb/year Baytown plant. 2017-18 –––––––––––––––– million lb/day–––––––––––––––– Average operating rates for all ethylene plants mask im- Q3 10.0 141.4 151.4 portant variations. In second-half 2018, 17 units (combined Q4 13.8 146.9 160.7 Q1 13.5 161.4 174.9 nameplate capacity of 34.7 billion lb/year) operated at less Q2 14.0 165.0 179.0 Q3 11.3 168.0 179.3 than 90% of nameplate capacity, while 20 units (combined Q4 11.0 172.0 183.0
nameplate capacity of 40.5 billion lb/year) operated at 90- Source: Petral Consulting monthly survey 100%. Of these 20 units, 6 units (combined nameplate ca- pacity of 10.1 billion lb/year) operated at 100% or more of nameplate capacity.
Fig. 1 shows trends in ethylene pro- US ETHYLENE PRODUCTION* FIG. 1 duction. 250 Light feeds Heavy feeds Capacity Ethylene production costs Ethylene production costs are deter- 200 mined by raw material costs and co- product credits. Based on variations in yield patterns for the various feeds, co- 150 product volumes vary widely between the three categories of plants (ethane- Million lb/d only, LPG-only, and multifeed plants). 100 Raw material costs are determined by each feedstock’s price and its conver- sion to ethylene. Similarly, coproduct 50 Q1 Q2 Q3 Q4 Q1 Q2 Q3 credits are determined by spot prices 2017 2018 and production volumes for each co- *Cracker production from fresh feed. product but only for those plants that Source: Petral Consulting Co.
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es around the world resulted in a sizeable compression in ter spot ethylene prices dipped to a low of 13¢/lb in May, a mod- spot prices for heavy feeds vs. light feeds. The crash in crude est rally began in July and extended through September. Spot prices also squeezed ethylene production cost differentials ethylene’s rising cash cost of production from purity ethane was between ethane and all other primary feeds as well as be- the key factor that sparked the modest rally. Spot ethylene pric- tween propane and heavy feeds. es averaged 16.7¢/lb in third-quarter 2018 but varied between USGC ethylene producers continued to increase ethane’s 13-20¢/lb, according to PetroChem Wire. Prices were 19.7¢/lb share of fresh feed in third-quarter 2018, but some ethylene in September, up from 13-14¢/lb in May and June. producers responded to the compression in production costs A series of short-covering episodes in the Mont Belvieu by reducing ethane consumption in fourth-quarter 2018 ethane market pushed purity ethane prices to 60-61¢/gal in while continuing to increase ethylene production. mid-September. The bullish impact was enough to support In third-quarter 2018, ethylene produced from ethane spot prices for purity ethane above 40¢/gal through early was 78% of total production, but ethylene production from October before prices fell to 33-36¢/gal in late October and ethane fell to 75% in fourth-quarter 2018. At the same time, even weaker in November and December. ethylene produced from propane averaged 11.3% of total Gross margins (spot ethylene prices minus cash produc- production in the third quarter but jumped to 15-16% in the tion costs) in third-quarter 2018 were -2¢/lb for purity eth- fourth quarter. ane, -7.3¢/lb for propane, and -11¢/lb for natural gasoline. Cash production costs in third-quarter 2018 were 18.7¢/ Margins improved in the fourth quarter to 3.5¢/lb for eth- lb for purity ethane, 24.0¢/lb for propane, and 28.6¢/lb for ane, breakeven for propane, and -2.7¢/lb for natural gaso- natural gasoline. line. As new plants start up, ethylene supply in the spot mar- Following a series of short-covering episodes in the eth- ket will remain plentiful. Spot prices and gross margins will ane spot market in Mont Belvieu, Tex., in the third quarter, remain weak for another 4-6 quarters. monthly spot prices for purity ethane declined 10¢/gal both Consistent with three full quarters of weak spot prices, in October and November and by an additional 2.75¢/gal PetroChem Wire monthly reports showed the volume of in December. Prices for propane and natural gasoline also fixed-price trades in Texas and Louisiana fell sharply in sec- declined sharply in fourth-quarter 2018, with cash produc- ond-quarter 2018 and remained weak through yearend. The tion costs at 16.2¢/lb for purity ethane, 19.4¢/lb for propane, combined volumes of all fixed-price trades (current month and 22.4¢/lb for natural gasoline. Propane’s cost advantage only) for all trading locations were 4.4-4.7 million lb/day in to natural gasoline was 3.0¢/lb in the fourth quarter vs. 4.6¢/ second-half 2018, 35-40% less than the 2015-17 average. lb in the third quarter. Fixed-price trades at Choctaw Dome, La., accounted for Table 2 shows production costs for major ethylene feedstock. 34% of all fixed-price trades in second-half 2018, according to PetroChem Wire. Trade volumes at Choctaw Dome his- Ethylene pricing, profit margins torically account for 3-6% of fixed-price trades. Leveraging Spot prices for ethylene generally fluctuate within a range their ownership of ethylene pipelines and weak pricing in defined by cash costs for the higher-cost feedstock. The low the Mont Belvieu spot ethylene market, a few ethylene sellers end of the range is determined by the cash cost for high-cost in Texas took advantage of premium prices for spot trades at feedstock with margins in a range of -5¢/lb to +5¢/lb. The Choctaw Dome. high end of the range is determined by cash costs plus mar- The modest rally in spot ethylene prices in second-half gins of 10-15¢lb. Occasionally, a buying void in one or more 2018 contributed to an increase in net transaction price USGC trading hubs triggers a collapse in spot prices. Sec- (NTP) contract settlements of 7.3¢/lb during third-quarter ond-quarter 2018 was just such a situation, and spot prices 2018. NTP settlements averaged 30.1¢/lb in the third quar- continued to be too weak to support positive margins for ter, reaching a peak of 33.75¢/lb in September. As purity production from high-cost feeds. ethane prices fell from a third-quarter peak of 53¢/gal in Spot ethylene prices fell sharply in second-quarter 2018. Af- September to 29-32¢/gal in November-December, NTP con-
ETHYLENE PRODUCTION COSTS Table 2 ETHYLENE FEED SLATE DEMAND Table 3 Ethane Propane n-Butane Pentane + Naphtha, 2017-18 ––––––––––––––––––––– ¢/lb –––––––––––––––––––––– Ethane LPG Natural gasoline gas oil 2017-18 –––––––––––––––––––––1,000 b/d –––––––––––––––––––– Q3 13.0 23.3 16.2 20.8 Q4 12.3 29.2 18.9 26.3 Q3 1,115.1 379.7 41.3 102.5 Q1 12.4 20.5 7.2 28.5 Q4 1,232.4 303.4 54.7 127.7 Q2 13.3 20.5 8.6 32.0 Q1 1,342.2 367.6 48.7 114.9 Q3 18.7 24.0 13.0 28.6 Q2 1,394.6 343.7 37.7 104.7 Q4 16.2 19.4 10.8 22.4 Q3 1,424.7 345.6 27.1 101.0 Q4 1,454.6 358.1 32.6 99.0 Source: Petral Consulting estimates Source: Petral Consulting monthly survey
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tract settlements fell to 29.25¢/lb for ETHYLENE CE FIG. 2 November-December. 40 Cash production costs based on purity ethane were 15-23¢/lb in sec- 35 ond-half 2018, averaging 18.7¢/lb in 30 the third quarter and 16.2¢/lb in the fourth quarter. Cash production costs 25 for propane were 24¢/lb in the third 20 quarter and 19.4¢/lb in the following 15
quarter. Production costs for natural Price, ¢/lb gasoline were 28.6¢/lb in the third 10 quarter before falling to 22.4¢/lb in the 5 fourth quarter. Spot Contract Ethane cash cost 0 Gross margins in third-quarter Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2018 were 11.4¢/lb for ethane, 6.1¢/ 2017 2018 lb for propane, and 1.5¢/lb for natural Source: PetroChem Wire, Petral Consulting market research gasoline. Gross margins in the fourth quarter were 13.7¢/lb for ethane, 10.5¢/lb for propane, and 7.5¢/lb for natural gasoline. 150,000 b/d, averaging 130,000 b/d in second-half 2018. Fig. 2 shows historical trends in ethylene spot prices and NTPs. Monomer exports Ethylene and propylene are used as raw material feeds for pro- Olefin-plant feed slate trends duction of derivative products, with polyethylene and poly- Petral Consulting’s monthly survey of plant operating rates propylene as the most important derivatives. US chemical and feed slates showed industry demand for NGL feedstocks companies focus primarily on selling surplus supplies of poly- jumped to 1.73 million b/d in first-quarter 2018 and 1.74 ethylene, ethylene glycol, PVC, polypropylene, and acryloni- million b/d in the second quarter. Demand for NGL feeds in trile into international markets. With one ethylene export ter- first-half 2018 was 209,000 b/d (13.7%) more than in sec- minal in operation, however, US suppliers export only small ond-half 2017. Full recovery from hurricane-related down- volumes of ethylene monomer. time was the primary factor for the increase in demand in US International Trade Commission (ITC) data showed first-quarter 2018. In second-quarter 2018, voluntary plant ethylene monomer exports averaged 1 million lb/day in shutdowns in response to the collapse in spot ethylene pric- third-quarter 2018, down 0.45 million lb/day (30.8%) from es and production curtailments offset increased production second-quarter exports. During 2015-18, monomer exports from new capacity (Table 3). on a quarterly average basis were within a range of zero to Ethane demand was 1.37 million b/d in first-half 2018, 1.6 million lb/day. up 195,000 b/d from second-half 2017. Ethane demand increased by 71,000
b/d in second-half 2018 to 1.44 mil- OLYETHYLENE E O T FIG. 3 lion b/d. Ethane’s share of total fresh 30 feed was 72.9% in first-half 2018 before increasing to 75% second-half 2018. 25 In Texas, ethane’s share of fresh feed was 71.6% in first-half 2018 vs. 67.0% 20 in second-half 2017. In Louisiana, eth- ane’s share of fresh feed was 70.0% in 15 first-half 2018 vs. 70.5% in second-half 2017. Million lb/d 10 Propane demand was 267,000 b/d in first-half 2018 and 264,000 b/d in the 5 HDPE LDPE LLDPE second half. Propane’s share of fresh 0 feed averaged 14.2% in first-half 2018 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 and 13.7% in the year’s second half. Af- 2015 2016 2017 2018 ter first-quarter 2018, demand for heavy feeds varied within a range of 120,000- Source: US ITC
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Until a new USGC ethylene export terminal becomes op- COPRODUCT PROPYLENE FROM ETHYLENE PLANTS Table 4 erational, ethylene export volumes will remain just 1-2% of From From light feeds heavy feeds Production US production and of no practical importance. 2017-18 ––––––––––––––––– Million lb/day ––––––––––––––– Q3 15.2 5.4 20.6 Polyethylene exports Q4 12.8 7.1 19.9 Q1 14.9 6.1 21.0 According to US ITC statistics, US exports of polyethylene— Q2 14.4 5.3 19.7 including high-density polyethylene (HDPE), low-density Q3 14.6 4.8 19.4 Q4 17.0 4.9 21.9 polyethylene (LDPE), and linear low-density polyethylene (LLDPE)—rebounded in January-May 2018, continuing to in- Source: Petral Consulting estimates. crease during June-October 2018. Exports to all destinations in January-May were 22.9 million lb/day, increasing by 4.9 ily on the use of propane, normal butane, naphtha, and other million lb/day (21.5%) to 27.8 million lb/day in June-October. heavy feeds. In first-half 2018, the monthly survey showed Exports to Canada and Mexico in June-October were 10.3 demand for LPG feeds (propane and normal butane) was million lb/day, up 0.73 million lb/day (7.7%) from January- 356,000 b/d, while demand for heavy feeds was 153,000 b/d. May. More importantly, however, exports to all other destina- In the third quarter, demand for LPG feeds fell to 346,000 tions (ROW) in June-October were 17.8 million lb/day, or 4.4 b/d, with demand for heavy feeds slipping to 128,000 b/d. million lb/day (33.1%) more than in January-May (Fig. 3). If Demand for ethane increased in the third quarter but not polyethylene exports to ROW destinations increase at a sus- enough to offset the drop in heavy feed demand. Demand tained rate of 20% per quarter, Petral Consulting estimates for LPG and heavy feeds, however, increased in the fourth they will reach 40-42 million lb/day by first-half 2020. The quarter, with LPG feed demand rising to 460,000 b/d (about ability of US chemical companies to ramp up polyethylene 105,000 up from the third quarter) and heavy feed demand exports at 20%/year every quarter for 6 quarters depends on averaging 132,000 b/d. Demand for ethane was down by how many companies decide to play hardball while taking about 30,000 b/d. the various turns along the Yellow Brick Road. Increasing ex- Coproduct supply was 19.3 million lb/day in third-quar- ports at 20%/year for 18 months seems like a big hurdle but ter 2018, down 0.4 million lb/day (2.1%) from second-quar- the ramp up in US exports is about 5%/year based on global ter 2018 and 1.3 million lb/day (6.1%) from third-quarter polyethylene demand; also, growth rates in global demand 2017. Coproduct supply jumped to 22.6 million lb/day in are allegedly 4-5%/year. Prices for polyethylene exports will fourth-quarter 2018, up 16.8% from the previous quarter. remain under downward pressure for 18-24 months. Coproduct supply from light feeds (ethane, propane, and According to PetroChem Wire, spot prices for HDPE (free normal butane) was 14.6 million lb/day in third-quarter 2018 on board, FOB Houston) were steady at 55¢/lb in first-half and 17.7 million lb/day in the fourth quarter. Supply from 2018. Prices, however, began to decline in the third quarter, light feeds in the third quarter was 0.6 million lb/day less than falling to 45¢/lb in fourth-quarter 2018. Pricing differentials third-quarter 2017 but 4.9 million lb/day more than the previ- between HDPE and spot ethylene were 34.5¢/lb in third- ous year’s fourth quarter. Coproduct supply from heavy feeds quarter 2018 before dipping to 24.9¢/lb in the fourth quarter. in second-half 2018 was 4.9 million lb/day, down 1.4 million Differentials between HDPE and NTP ethylene prices were 21.1¢/lb in the
third quarter before slipping to 14.7¢/lb HDPE SPOT PRICING, GROSS MARGINS FIG. 4 in the fourth quarter. Trends in HDPE- 60 45 polyethylene differentials show prices 40 for monomer and polymer also were 50 weaker in fourth-quarter 2018. 35 The strong increase in exports is a 40 30 harbinger of continued and sustained 25 growth in the polyethylene export mar- 30 ket. The increase in exports to ROW 20 Price, ¢/lb destinations, and the increase in poly- 20 15 Margin, ¢/lb ethylene spot prices are indicators that 10 second-half 2018 and 2019 may be “the 10 best of times” after all (Fig. 4). HDPE HDPE vs. spot ethylene HDPE vs. NTP 5 0 0 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Propylene supply 2016 2017 2018 Olefin-plant coproduct supply. Coprod- uct propylene supply depends primar- Source: PetroChem Wire, Petral Consulting market research
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lb/day (22.1%) from second-half 2017 (Table 4). continent refineries was 49.7 mm lb/day in third-quarter PDH plant supply. Based on PetroChem Wire’s daily re- 2018 and 49.2 mm lb/day in the fourth quarter. USGC mer- ports and other industry sources, Petral Consulting esti- chant sales—which include all supply from USGC and Mid- mates propylene production from propane dehydrogenation continent refineries—in second-half 2018 was up 1 million (PDH) plants at the USGC. Three plants with a combined lb/day (2%) from first-half 2018 (Table 5). capacity of 13 million lb/day were operational in second-half US supply. EIA statistics for refinery-grade propylene and 2018, with production averaging 11 million lb/day (85% of Petral Consulting estimates for coproduct supply and PDH nameplate capacity). plant production show total USGC propylene supply was As of first-quarter 2019, no additional USGC PDH capac- 79 million lb/day in third-quarter 2018 and 84 million lb/ ity is slated to come on stream for the next 2-3 years. In day in the fourth quarter. Supply from all sources in second- December 2018, Enterprise Products Partners LP (EPP) an- half 2018 was 81 million lb/day, up 4.4 million lb/day (5.7%) nounced it has revived plans for a second PDH plant in Mont from first-half 2018. Belvieu. LyondellBasell Industries NV is also near a final in- Fig. 5 shows trends in coproduct supply, PDH plant pro- vestment decision for a PDH-polypropylene complex. Glob- duction, and refinery merchant sales of propylene. ally, however, chemical companies continue to expand PDH capacity. Ineos AG, for example, recently announced plans Propylene economics, pricing for a major olefins complex at Antwerp, Belgium, that will Before any USGC PDH capacity came on stream, Petral Con- include a PDH plant (OGJ Online, Jan. 15, 2018). sulting periodically received questions regarding the impact Refinery supply. Refinery propylene sales into the mer- of propylene supply from PDH plants on propylene prices. chant market are a function of: Based on the operational issues that were generally known • Fluid catalytic cracking unit (FCCU) feed rates (most in 2010, Petral Consulting’s answer to these questions was important variable). consistent: more supply from PDH plants translates into • FCCU operating severity (important but not directly greater pricing volatility for polymer-grade propylene. The measurable). same holds true for refinery-grade propylene pricing. • Economic incentive to sell propylene rather than use it In distinct contrast with persistently weak spot ethylene as alkylate feed. prices, spot prices for refinery-grade propylene were stron- Variations in FCCU feed rates generally are the most im- ger for most of second-half 2018 based on premiums to un- portant parameter determining refinery-grade propylene leaded regular gasoline. supply. Economic factors that may result in changes in oper- At 85% of nameplate capacity, USGC propylene supply ating severity are generally of secondary importance. from PDH plants will average 11 million lb/day. In the absence Statistics from the US Energy Information Administra- of any offsetting reduction in refinery-grade propylene supply, tion (EIA) show US refineries operated FCCUs at 5.1 million USGC polymer-grade propylene markets should trend toward b/d in third-quarter 2018, up 42,000 b/d (0.8%) from the chronic surplus. The previously anticipated chronic propyl- second quarter. Based on EIA monthly statistics for Octo- ene surplus did not occur because US suppliers were able to ber 2018 and weekly statistics for November-December, Pe- offset supply growth with increasing monomer exports. tral Consulting estimates FCCU feed rates in fourth-quarter Before 2016, propylene exports were just enough to offset 2018 declined by 61,000 b/d to average 5 million b/d. imports from Canada. Exports averaged 0.85 million lb/day Regionally, EIA statistics showed feed rates for FCCUs in in 2010 through first-quarter 2015. During the past 13 quar- the USGC and Midcontinent were 3.78 million b/d in third- ters (second-half 2015 through third-quarter 2018), how- quarter 2018. Petral Consulting estimates feed rates were ever, propylene exports averaged 2.8 million lb/day (about 3.74 million b/d in the fourth quarter, with overall second- three times more than in 2010 through first-quarter 2015) half 2018 feed rates 69,000 b/d higher vs. first-half 2018. and were never less than 1.9 million lb/day in the last 9 Refinery-grade propylene supply from USGC and Mid- quarters. In the past 6 quarters, propylene exports were 3.5 million lb/day. Exports are now equal to typical propylene production from one world-scale PDH plant. REFINERY PROPYLENE PRODUCTION Table 5 Discounts for refinery-grade propylene vs. polymer-grade Texas South Other 2017-18 Gulf Coast Louisiana areas Total propylene exceeded 10¢/lb for the first time in second-quar- ––––––––––––––––– Million lb/day ––––––––––––––– ter 2010, but discounts were consistently less than 10¢/lb in Q3 17.5 18.5 13.8 49.8 fourth-quarter 2010 through third-quarter 2011. During the Q4 21.2 18.8 14.8 54.8 Q1 21.5 17.5 12.9 51.9 next 4 years (2012-15), discounts varied within a range of Q2 20.4 17.4 13.6 51.4 7-12¢/lb, averaging 10.1¢/lb. Since 2015, discounts for refin- Q3 21.5 17.3 13.8 52.6 Q4* 20.0 19.0 15.4 54.4 ery-grade propylene were never less than 10¢/lb in any quar- *Petral Consulting estimates. ter and averaged 15.7¢/lb in first-half 2018. Discounts were Source: EIA Petroleum Supply Monthly, Petral Consulting estimates 13.4¢/lb in second-half 2018 and varied within a range of
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11-16¢/lb. Discounts for refinery-grade O YLENE O CT ON LE FIG. 5 propylene are now routinely 10-12¢/lb 100 and are three to four times more than in 2005-09. While trends in refinery-grade pro- 80 pylene pricing discounts vs. polymer- grade propylene support a bearish 60 view, trends in refinery-grade propyl- ene prices vs. unleaded regular gaso- 40 line prices are bullish. Price premiums Million lb/d for refinery-grade propylene vs. USGC 20 unleaded regular gasoline prices were Re nery merchant sales Coproduct supply PDH plants 5.4¢/lb in second-quarter 2018 before 0 surging to 9-13¢/lb in July-Septem- Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 ber to average 10.9¢/lb during third- 2016 2017 2018 quarter 2018. As the global collapse in Source: EIA, Petral Consulting estimates motor gasoline prices extended into November-December, however, pre- miums fell to 6.8¢/lb in November and only 1.7¢/lb in De- will continue to influence spot prices for polymer-grade and cember. refinery-grade propylene. In the current market, unpredictable variations in sup- Pricing volatility (measured as the standard deviation of ply-demand balances result in large swings in polymer- day-to-day variation in spot prices for each month) increased grade propylene pricing and differentials. The unpredictable as propylene supply from PDH plants and the number of variability in operating rates of the USGC’s three PDH plants PDH plants in operations increased. In 2017, the standard deviation for day-to-day variation in spot prices averaged 0.62¢/lb and was 1.0¢/lb or more in only 1 month. In first- half 2018, the standard deviation averaged 1.09¢/lb and was 1.0¢/lb or more in 3 months. All PDH plants settled into a period of sustained and steady operations in fourth-quarter 2018. As anticipated, when PDH plants ran consistently at high operating rates, pricing volatil- ity declined. In third-quarter 2018, standard deviations for daily variations in polymer-grade propylene prices were 0.23- 0.73¢/lb, averaging 0.5¢/lb. In the fourth quarter, standard deviations measured 0.5-1.1¢/lb and averaged 0.71¢/lb.
“I can think of no one better to translate the complexities of Propylene, polypropylene exports natural gas liquids into a more easily understandable subject.” For the first 3 quarters in 2018, monomer exports varied — Frank H. Richardson, President and CEO, Shell Oil Company, Retired within a range of 3.0-5.5 million lb/day. Monomer exports in Natural Gas Liquids: A Nontechnical Guide second and third-quarters 2018 were 4.23 million lb/day, up is a comprehensive overview of NGLs from 0.56 mm lb/day (15.1%) from second and third-quarters 2017. production in the oil patch to consumption in The primary destinations for monomer exports remain the fuels and petrochemicals industries. Columbia and Mexico. Exports to Mexico were 1.99 mil- Learn what is behind natural gas liquids: lion lb/day in first-half 2018, up 0.61 million lb/day (43.9%) • How they are produced from second-half 2017. Exports to Columbia also increased • How they are transported in first-half 2018 vs. second-half 2017, with first-half 2018 • How they are consumed in the fuels exports averaging 1.44 million lb/day, or 0.26 million lb/day and petrochemicals industry (22.1%) more than in second-half 2017. Exports to Mexico • Prof les of successful NGL companies slipped to 1.84 million lb/day in July-October 2018. Exports to Columbia were also weaker in July-October, averaging 1.33 million lb/day. ORDER YOUR COPY TODAY AT US ITC statistics also show US polypropylene exports WWW.PENNWELLBOOKS.COM 226 Pages/Hardcover/2014 OR CALL 800-752-9764 were weak in first-half 2018 relative to 2015 through first- half 2017. Polypropylene exports remained weak in second-
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half 2018 based on July-October statistics. Exports in first- the early phase of commissioning, while Sasol is likely to half 2018 were 5.97 million lb/day before falling below 5 begin an extended startup for new ethylene and derivative million lb/day in September-October. July-October exports units at its Lake Charles, La., complex. averaged 5.11 million lb/day, down 0.87 million lb/day After 2019, ethylene producers will have access to addi- (14.5%) from first-half 2018. tional ethylene export capacity. As one or two export termi- nals dedicated to ethylene service begin operations in 2020 2019 outlook or 2021, ethylene producers will be able to adjust exports Domestic chemical companies have taken the first major to maintain balanced markets, and a collapse in spot prices steps from a period when all important variables within similar to first-half 2018 will become less likely. North America were known and developments in markets outside North America were of interest but not generally rea- The author son for concern. The future is all about integrating North Daniel L. Lippe ([email protected]) is presi- America into the global marketplace. In 2019, however, pro- dent of Petral Consulting Co., which he founded ducers’ primary focus will be on the new plants in Louisiana in 1988. He has expertise in economic analysis of and Texas that will start up in 2019. a broad spectrum of petroleum products includ- Petral Consulting forecasts US ethylene production will ing crude oil and refined products, natural gas, average 190-210 million lb/day in first-half 2019 and 200- natural gas liquids, other ethylene feedstocks, 220 million lb/day in second-half 2019. During first-half and primary petrochemicals. 2019, production will average 20-25 million lb/day more Lippe began his professional career in 1974 with Diamond Sham- than in 2018. Year-over-year growth in second-half 2019 rock Chemical Co., moved into professional consulting in 1979, will increase 25-30 million lb/day. and has served petroleum, midstream, and petrochemical indus- The outlook for first-half 2019 has characteristics similar try clients since. He holds a BS (1974) in chemical engineering to first-half 2018. Three new plants in Louisiana are sched- from Texas A&M University and an MBA (1981) from Houston uled to come on stream in 2019. Indorama’s restart of the Baptist University. He is an active member of the Gas Processors 950-million lb/year plant acquired from LyondellBasell is in Suppliers Association.
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In-depth phase characterization improves naphtha cracker emulsion breaking
Fabrice Cuoq Jérôme Vachon Saudi Arabian Basic Industries Corp. Geleen, the Netherlands
Research by Saudi Arabian Basic Industries Corp. of the PWS can be rerouted to the QWT as quench- PROCESSING (SABIC) shows that colloid chemistry analytical ing water or sent to the water treatment plant. The tools combined with advanced analytics enable bottom of the PWS is finally routed to the DSG, clearer understanding of the emulsion properties. where process steam is produced for use as diluent Dynamic surface tension as well as zeta and streaming po- in the furnaces. The system from the QWS to DSG is called tential titrations yield valuable information on the molecu- the dilution steam system (DSS) (Fig. 1). lar size, electrostatic charge, and isoelectric point (IEP) of Either OW or water-in-oil (WO) emulsions can form in the emulsifier. These combined, measured parameters can the first compartment of the QWT and may lead to carry- be used to determine the emulsion-stabilization mechanism, over of process water or pygas to sections not adapted to which in turn allows a proper and tailored optimization of treat such effluents, which can lead to severe issues impact- plant conditions. ing plant economics, including corrosion, formation of poly- meric deposits, or in extreme cases, an unplanned shutdown Background of the petrochemical plant. OW emulsions are generally the Naphtha-cracking processes often suffer from oil-in-water largest cause for concern. Solid fouling deposits—which (OW) emulsions in quench water towers (QWT). Organics result from the high reactivity of pygas—can be formed in within the water phase can deposit in the dilution steam gen- the DSS, which subsequently leads to severe energy capacity erators (DSG) and cause severe fouling that can lead to critical losses in PWS, preheaters, and the DSG. energy losses and threaten production. In practice, emulsion- In practice, emulsion-breaker dosage or pH reduction are breaker dosage or pH reduction are commonly used to break used to break these emulsions. Physical separation methods these emulsions. The mechanism of emulsion stabilization via such as coalescers can also be applied. If missing, however, emulsifiers, however, is often unknown due to the complex this solution requires a high-cost hardware change to the composition of both aqueous and gasoline phases. cracker. An ethylene plant’s cracked gas needs to be cooled before proceeding
to the cracked-gas compressor section. ETHYLENE PLANT QWT, DILUTION STEAM SYSTEM FIG. 1 This is generally achieved by quench- ing the cracked gas with a water stream Condensation in a QWT. The QWT is generally fol- vessel lowed by a quench-water settler tank QWT, 80° C. that allows water and pyrolysis gasoline Water Quench water settler Furnace Process process (pygas) separation. The pygas usually water steam contains a mixture of light hydrocar- bons such as benzene, toluene, styrene, Cracked Process gas water ethylbenzene, cyclic hydrocarbons, and Pygas stripper, Dilution steam C -C unsaturated components. This 5 10 Stripping steam 120° C. generator, stream is commonly recovered after 180° C., 8 bars the QWT for further treatment, and the water phase is sent to a process-water stripper (PWS) column to remove dis- Purge solved hydrocarbons. Depending on Preheaters plant design, condensates from the top
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Despite the different existing solutions, the mechanism of Methods emulsion stabilization and the structure of the emulsifier(s) A SITA science line t-60 maximum bubble-pressure tensiom- are often unknown due to the complex composition of both eter measured dynamic surface tension. Streaming potential phases and the high variability of feedstocks cracked in an titration determined the charge density of the emulsion. Mea- ethylene plant. Empirical solutions are often developed for surements were performed on a Mütek PCD03PH streaming these systems by using simple shake-bottle tests without in- potential detector. A total of 19.81 g of process water was ti- vestigating an emulsion’s true nature and properties. trated with a polydiallyldimethylammonium chloride (Poly- To our knowledge, this is the first time that colloid chem- DADMAC) (1 milliequivalent (meq)/l.) organic coagulant. istry analytical tools have been applied to resolving OW While 0.282 ml of the PolyDADMAC solution was needed to emulsion issues in a naphtha cracker. The results presented neutralize all charges in the process water, the titration of the in this article have all been obtained using real plant sam- cell itself required 0.220 ml of the blank solution. ples from one of SABIC’s European naphtha crackers. The pendant-drop method determined interfacial ten- sions. In this method, the shape of a droplet suspended from Materials a needle in a nonmiscible bulk-liquid phase is determined. Four OW emulsion samples (pH = 8.8, σ = 135 microsie- The interfacial tension can be derived from the drop shape mens (μS)/cm) were taken at different times from a QWS at and the density difference between the two phases. Analysis one of SABIC’s naphtha crackers. The milky-colored water was performed with an Attension CAM-200. samples—which indicate dispersed organics in the water— Average gasoline-droplet size was measured using a Mal- were obtained from the bottom of the gasoline-water separa- vern Mastersizer 2000, with the mean diameter (volume- tor vessel (Fig. 2). weighed mean) of the droplets found to be about 11.08 μm. Salting out the process water (NaCl 100g/l.) measured the amount of gasoline dispersed in the water. Once the emul- sion was broken, the amount of phase-separated gasoline was measured volumetrically, revealing that the process wa- ter contained about 0.1% of dispersed gasoline. Zeta potential values were obtained with a Malvern Zeta- sizer NanoZS at 70º C., and the emulsion’s pH was lowered using a 0.1 volume-to-volume (v/v) % HCl solution. DSM R&D Solutions BV, Geleen, the Netherlands, mea- sured liquid chromatography-mass spectrometry (LC-MS) on a Bruker Daltonics maXis Quadrupole Time-of-Flight (Q-TOF) mass spectrometer with electrospray ionization (ESI), atmospheric-pressure chemical ionization (APCI), and sometimes atmospheric-pressure photoionization (APPI) in the positive and negative-ion mode. The elemental composi- tions of the visual peaks were manually determined based on the accurate mass. Direct insertion probe-mass spectrometry (DIP-MS) was performed by DSM Resolve on a Waters Autospec sector- field mass spectrometer.
Discussion Zeta potentials (ζ) of -80 ± 6 mv (pH = 8.8, σ = 135 μS/cm) were obtained for the emulsion at both 25º C. and 70º C. (aver- age values of the four samples), indicating that the electrostatic component is relatively strong since ζ < -30 mv are generally representative of stable emulsions. Using titration, the charge density of the emulsion was found to be about 2.7 μeq/l. at pH 8.8. By considering an 0.1 v/v % OW emulsion (volumetric value determined by salting out the emulsion) and an average spherical-droplet size of 11.08 μm, the charge density of the Samples of OW emulsion taken from the naphtha cracker’s QWS emulsion was calculated at 0.62 μeq/sq m. were milky colored, indicating the presence of dispersed organ- This calculated value seems low compared to the charge ics in the water (Fig. 2). density generally considered for a stable emulsion. While
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the low charge density and the highly negative zeta potential ing potential = 0 mv) is obtained at pH 5.45, which corre- seem contradictory, they can be partially explained by the sponds to the IEP. At pH values above the IEP, the droplets low conductivity of the continuous phase (i.e., 135 µS/cm), are negatively charged, while below the IEP, the droplets are which could be indicative of the presence of low amounts positively charged. In this case, cationic charges are gener- of adsorbed counter ions. It can finally be concluded that ally caused by amines, whereas anionic charges are generally the electrostatic component of the emulsion is not negligi- due to carboxylic acids. Around the IEP, the emulsion is not ble in the specific conditions of the naphtha cracker’s QWT charged and becomes very unstable. Determination of the studied. Furthermore, zeta potential measurements can be IEP will therefore indicate the system’s optimum pH. used to optimize the emulsion-breaker dosing rate in pro- Fig. 4 shows the process water at different pH values after cess water. For this, dynamic zeta potential measurements 24 hours. upon emulsion breaker addition can be recorded offline or At pH < 3.86, the streaming potential decreases again monitored online. slightly because of either the compression of the double lay- • Determination of IEP and its relation to emulsion destabi- er or a systematic decrease in streaming potential, both in- lization. Recording the titration curve (streaming potential duced by the high concentration of ions. vs. pH) while titrating the emulsion with HCl (Fig. 3) deter- Recording dynamic surface tension measurements al- mined its IEP. lowed estimates of the time needed for the emulsifiers to dif- From the process water’s original pH of 8.88 to pH 3.45, fuse to a newly created hydrophobic surface (Fig. 5). the streaming potential shows a continuous increase from Surface tensions of both emulsion bottles (measured in about -400 mv to +200 mv. The charge inversion (at stream- duplicate) lie well above the ones for pure water, indicating that no free-surface active species are present in the process water. Also, the H T E NG OTENT L NCT ON FIG. 3 stable high surface tension indicates 600 that the emulsion is not stabilized by Isoelectric point = 5.45 small molecules but rather by amphi- 400 philic polymers because these do not have time to migrate from the emul- 200 sion droplet onto the bubble surface for a bubble life of even 10 sec. The 0 fact that the values are slightly above the pure-water value is because the –200 samples were colder (18° C.) than the water reference (25° C.), giving them a Streaming potential, mv –400 slightly higher ionic strength. Surface HCl titration tension generally increases with low- –600 er temperatures and increased ionic 2 4 6 8 10 pH strength. Fig. 6 shows the evolution of the *For OLE4-unit process water. zeta potential as a function of time
Process water at higher pH values after 24 hours increased in murkiness (Fig. 4).
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