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APR. 2, 2018 | USD 20

International Petroleum News and Te Technology chnology |

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EOR REPORT

OFFSHORE OPERATIONS

TURKEY’S BASIN-CENTERED GAS PLAY MEETING NEW BUNKER SULFUR RULES UNDERSTANDING DISTILLATION TRAYS

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CONTENTS Apr. 2, 2018 Volume 116.4

GENERAL INTEREST

Selling US LNG to Europe requires commercial terms, speakers say

KPC lets prefeasibility study for Kuwaiti refining capacity expansions 29

24

Sonatrach updates refining plans

British Columbia offers conditional conditio nal LNG L NG project incentives

30

BPCL lets contract for Kochi refinery

Papua New Guinea white paper addresses domestic gas use

31

Chevron Phillips Chemical commissions USGC ethane cracker

25

26

 Wide WTI-WCS spread spread cuts oil sands s ands output 28

Court rejects N YSDEC’s appeal of FERC’s Valley Lateral ruling

SPECIAL REPORT

OFFSHORE OPERATIONS

EOR REPORT

Study questions stratigraphic traps’ predrill risks

CNOOC studies steam recovery in offshore Bohai heavy oil field

Edwige Zanella

Wankun Xu

Jamie Collard

Fengyi Zhang

36

Dawei Wang Tingting Wu Xiaoha Dong

25

 ADNOC signs deals with Total, CNPC for offshore concessions

SPECIAL REPORT

31

 Argentina moving to develop tight shale oil and gas, speakers say 32

 ADNOC lets contracts contracts for Ruwais refinery 34

28

Continuous pack-off inflow inf low control control device lowers water cut offshore China

Jinze Xu Zhangxin Chen

46

Feng Li

Nanofluids hold EOR potential in Egypt’ Egy pt’s  Western Desert

Xiaoping Li Bailin Pei Songmei Zhang Hailong Wang

Sayed Gomaa

Guojiang Feng

Adel Salem

Jianchang Wu

Mohamed Hassan

Xiaoling Li

52

56 Subsea pipeline projects advance in i n 2018 Christopher E. Smith

72 APRIL

2018

VOL

64;

NO.

5

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UK-based Ophir Energy in 2017 drilled its Ayame-1X exploration well on Block 513 off Ivory Coast using Seadrill’s West Saturn. Ophir has since exited the block, which it operated with a 45% interest. Other part-  ners in Block 513 were African Petroleum 45% and state-owned Petroci 10%. The block covers 1,443 sq km in 3,000 m of water. The predrill risks of stratigraphic traps off West Africa and elsewhere is among the topics addressed in this year’s Offshore Operations special report, starting on p. 36. Photo from Ophir Energy.

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TECHNOLOGY...

EXPLORATION & DEVELOPMENT

DRILLING & PRODUCTION

PROCESSING

TRANSPORTATION

Study questions stratigraphic traps’ predrill risks

CNOOC studies steam recovery in offshore Bohai heavy oil field

Study evaluates refiners’ options to meet 2020 bunker fuel sulfur rules

Subsea pipeline projects advance in 2018

Edwige Zanella

Wankun Xu

Tayseer Abdel-Halim

72

Jamie Collard

Fengyi Zhang

Matthew Yu

36

Dawei Wang

60

Tingting Wu

South Africa oil and gas law could accelerate exploration in 2018-19

Xiaoha Dong

Tayvis Dunnahoe

46

Jinze Xu Zhangxin Chen

40

Basin-centered gas play developed in western Turkey

Nanofluids hold EOR potential in Egypt’s  Western Desert Sayed Gomaa

Tayvis Dunnahoe

Adel Salem

44

Mohamed Hassan

52

Continuous pack-off inflow control device lowers water cut offshore China Feng Li Xiaoping Li Bailin Pei Songmei Zhang Hailong Wang Guojiang Feng Jianchang Wu Xiaoling Li

56

HRM FOR THE

BEYOND BACK-TOBASICS: PROCESS PRINCIPLES AND CONCEPTS—5: Understanding how distillation trays work Norman P. Lieberman

68

Christopher E. Smith

HRM FOR THE OIL & GAS INDUSTRY 

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International News for oil and gas professionals

 GENERAL INTEREST Q U I C K T A K E S Cypriot gas dispute colors Turkey-EU summit  A meeting in Varna, Bulgaria, between Turkish President Recep Tayyip Erdogan and leaders of the European Union ended with repeated EU condemnation of Turkey’s recent interference with oil and gas exploration off Cyprus. “The European Union stands united behind the Republic of Cyprus,” declared Donald Tusk, president of the European Council, in Varna.  Just days before the summit, the EU had said it “strongly condemns Turkey’s continued illegal actions in the Eastern Mediterranean and the Aegean Sea and underlines its full solidarity with Cyprus and Greece.” Omer Celik, EU affairs minister, called that statement “not acceptable for Turkey.” Turkish military vessels in February prevented Eni from moving a drilling rig to Block 3 off Cyprus from Block 6, where it had drilled a gas discovery designated Calypso (OGJ Online, Feb. 9, 2018). Turkey’s government says the exclusive economic zone claimed by Cyprus overlaps Turkish territory and argues that gas development sanctioned by the Greek Cypriot government violates rights of Turkish Cypriots in the divided island. The unresolved dispute over oil and gas exploration off Cyprus simmered in the background as Erdogan, Tusk, and other EU officials debated broader controversies over migration, combatting terrorism, the rule of law in Turkey, and Turkey’s involvement in Syrian conflicts.  After the meeti ng, Erdogan said EU membership remai ns “a strategic goal” of Turkey, which has been in negotiations over EU accession since October 2005.

Statoil’s name to be changed to Equinor Statoil SA will become Equinor. The name will change after a shareholder vote scheduled May 17. The Norwegian government, Statoil’s majority shareholder, supports the proposal by the board of directors. “The name change supports the company’s strategy and development as a broad energy company,” a company statement said.

6

For up-to-the-minute news, visit www.ogjonline.com

Dio named chairman, president of BP Americas Susan Dio has been named chairman and president of BP  Americas Inc. She has worked for BP for 33 years, most recently as chief executive of BP Shipping. A chemical engineer, Dio has worked in the US, UK, and Australia. She succeeds John Minge, who has led BP Americas since February 2013. At the request of the National Petroleum Council, Minge will chair a study of carbon capture, utilization, and storage. He will retire from BP in March 2019.

Watkins to step in as Shell US president Royal Dutch Shell PLC has made changes to its US leadership team. Former Maersk Oil Chief Executive Officer Gretchen Watkins will succeed Executive Vice-Pres. Greg Guidry, who will leave Shell June 31, following 36 years with the company. Watkins will join Shell on May 1 and will be appointed executive vice-president unconventionals, effective July 1. She will report to the upstream director and be based in Houston. Shell Oil Co. Pres. and US Country Chair Bruce Culpepper plans to step down Dec. 31 following 37 years of Shell service. Concurrent with Culpepper stepping down, Watkins will assume the role of Shell Oil president and US country chair.  While serving in her expanded role, Watkins will retain her title as executive vice-president unconventionals.

EXPLORATION & DEVELOPMENT Q U I C K T A K E S Governors extend Tri-State shale deal through 2021 The governors of Ohio, Pennsylvania, and West Virginia agreed to extend a 2015 agreement to cooperate on developing shale oil and gas resources in their states through Dec. 31, 2021. Their Mar. 21 action continues an effort to show the Appalachian basin’s shared goal to assure the gas will attract manufacturers to the region instead of simply being exported, Pennsylvania Gov. Tom Wolf (D) said in Harrisburg. “The shale gas resources in the Appalachian basin represent enormous economic opportunity not just for Pennsylvania, but for the region as a whole,” Wolf said. “We have a unique proposition: abundant and low-cost feedstock for petrochemical and

Oil & Gas Journal 

ICE BRENT / NYMEX LIGHT SWEET CRUDE $/bbl  71.00  70.00  69.00  68.00  67.00  66.00  65.00  64.00 

US INDUSTRY SCOREBOARD — 4/2 4 wk. average

Latest week 3/16

Mar. 21

Mar. 22 

Mar. 23 

Mar. 26 

Mar. 27

Motor gasoline Distillate Jet fuel Residual Other products

 

Crude production NGL production 2 Crude imports Product imports Other supply2 3 TOTAL SUPPLY Net product imports

YTD avg. Change, year ago1 %

9,276 3,899 1,723 322 5,267 20,487

9,102 4,081 1,643 399 4,304 19,529

1.9 (4.5) 4.9 (19.3) 22.4 4.9

9,055 4,051 1,684 299 5,511 20,600

8,672 3,940 1,594 439 4,945 19,590

4.4 2.8 5.6 (31.9) 11.4 5.2

10,360 3,995 7,487 2,065 2,410 26,317 (2,756)

9,090 3,471 7,863 2,187 1,973 24,584 (2,736)

14.0 15.1 (4.8) (5.6) 22.1 7.0 —

10,141 4,003 7,714 2,095 2,324 26,277 (2,739)

9,009 3,531 8,171 2,214 2,257 25,182 (2,666)

12.6 13.4 (5.6) (5.4) 3.0 4.3 —

16,240 16,557 0.9

15,482 16,140 86.7

4.9 2.6 —

16,404 16,751 0.9

16,176 16,503 89.3

1.4 1.5 —

Refining, 1,000 b/d  Mar. 21

Mar. 22 

Mar. 23 

Mar. 26 

Mar. 27

Crude runs to stills Input to crude stills % utilization

 

NYMEX NATURAL GAS / SPOT GAS - HENRY HUB

Latest week 3/16

Latest week

Previous week1

428,306 243,065 131,044 40,976 32,746

430,928 244,758 133,066 41,582 33,416

Same week year ago1 Change

Change

Change, %

Stocks, 1,000 bbl 

Crude oil Motor gasoline Distillate Jet fuel–kerosine Residual Stock cover (days) 4  Mar. 21

Mar. 22 

Mar. 23 

Mar. 26 

Mar. 27

 

ICE GAS OIL / NYMEX HEATING OIL ¢/gal  200.00  198.00  196.00  194.00  192.00  190.00  188.00  186.00 

YTD average1

Supply, 1,000 b/d 

WTI CUSHING / BRENT SPOT

$/MMbtu  2.700  2.680  2.660  2.640  2.620  2.600  2.580  2.560 

Change, %

Product supplied, 1,000 b/d 

TOTAL PRODUCT SUPPLIED

$/bbl  71.00  70.00  69.00  68.00  67.00  66.00  65.00  64.00 

4 wk. avg. year ago 1

(2,622) (1,693) (2,022) (606) (670)

533,110   (104,804) 243,468 (403) 155,393 (24,349) 41,829 (853) 39,573 (6,827)

Change, %

Crude Motor gasoline Distillate Propane

Light sweet crude ($/bbl) Natural gas, $/MMbtu

Change, %

26.4 26.2 33.6 26.9

26.9 26.6 33.5 26.4

(1.9) (1.5) 0.3 1.9 Change

34.2 26.7 38.1 37.3

64.16 2.63

61.31 2.73

2.85 (0.10)

48.50 2.96

Futures prices 5 3/23

(19.7) (0.2) (15.7) (2.0) (17.3)

(22.8) (1.9) (11.8) (27.9) Change Change,% 15.66 (0.33)

32.3 (11.1)

1

Based on revised figures. 2OGJ estimates. 3Includes other liquids, refinery processing gain, and unaccounted for crude oil. divided by average daily product supplied for the prior 4 weeks. 5Weekly average of daily closing futures prices. Source: Energy Information Administration, Wall Street Journal Mar. 21

Mar. 22 

Mar. 23 

Mar. 26 

Mar. 27

4

Stocks

 

BAK ER HUGHES INTERNATIONA L RIG COUNT:TOTAL WORLD / TOTAL ONSHORE / TOTAL OFFSHORE

PROPANE - MT. BELVIEU / BUTANE - MT. BELVIEU ¢/gal  93.00  91.00  89.00  87.00  85.00  83.00  81.00  79.00 

1

2,058 

1,500  1,200  300 

Mar. 21

Mar. 22 

Mar. 23 

Mar. 26 

Mar. 27

 

213 

0  Feb. 17

Mar. 17

Apr. 17

May 17 

Jun. 17 

Jul. 17

Aug. 17 Sept. 17

Oct. 17 

Nov. 17

Dec. 17   Jan. 18

  Feb. 18

Note: Monthly average count

BAK ER HUGHES RIG COUNT: US / CANADA 1,000  900 

995 

809 

800  700  600  500  400  300  200  1

Mar. 21

1

Mar. 22 

1

Mar. 23 

1

Mar. 26 

1

 Mar. 27 

Not available 2Reformulated gasoline blendstock for oxygen blending Nonoxygenated regular unleaded

3

2,271

2,100  1,800 

NYMEX GASOLINE (RBOB) 2 / NY SPOT GASOLINE 3 ¢/gal  203.00  202.50  202.00  201.50  201.00  200.50  200.00  199.50 

2,400 

185 

100  0  1/6/17 1/6/17 

1/20/17 1/20/17 

1/13/17 1/13/17 

2/3/17 

2/17/17 2/17/17 

1/27/17  1/27/17  2/10/17  2/10/17

3/3/1 3/3/17    7 

2/24/17 

3/17/17 

161

1/5/18 

3/10/17 3/10/17    3/24/17   

1/19/18 1/19/18    2/2/18 2/2/18 

1/12/18   

1/26/18 

  2/16/18

2/9/18 

3/2/18

2/23/18 

3/16/18 

3/9/18

3/23/18 

Note: End of week average count

8

Oil & Gas Journal | Apr. 2, 2018

 

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plastics manufacturing, all within the same geographic footprint.” Ohio’s John R. Kasich (R) and West Virginia’s James C.  Justice (R) also signed the ex tension. Under the Tri-State Shale Coalition agreement, the states work together on issues in infrastructure, workforce development, and marketing to harness the potential of Appalachian gas and natural gas liquids, Justice said. The coalition identifies key areas for cooperation to help the gas industry grow, and holds annual summits where government, education, and industry leaders share information and best practices, he noted. Kasich pointed out that since becoming part of the coalition in 2015, horizontal shale wells in Ohio have produced an average 19.2 million bbl of oil and 1.36 tcf of gas—increases of 275.5% and 619.4%, respectively, from the 3-year average preceding the agreement. Production of gas has increased each consecutive year since 2014, he added. “Instead of competing, our three states are working together to promote the region as a center for shale-related manufacturing,” said Justice.

Last year, Philippines President Rodrigo Duterte approved negotiations with the Chinese government over the possibility of joint exploration (OGJ Online, Aug. 17, 2017).  After a meeting this month with Philippine Foreign Sec.  Alan Peter Cayetano, Wang Yi, the Chinese foreign minister, told reporters the countries will “in a prudent and steady way advance cooperation on offshore oil and gas exploration.” Cayetano said the talks yielded “very positive momentum.”

Apache finds oil at Garten prospect in UK North Sea

Mexican state oil company Petroleos Mexicanos (Pemex) signed an exploration and extraction contract with privately held US firm Lewis Energy Group for work in Olmos field in the northern border state of Coahuila, the company said.  With an expected investment of $617 million, the goal is to assess and develop the Eagle Ford field in Mexico with sights set on producing 117 MMcf of natural gas by 2021, Pemex said. Lewis Energy has drilled more than 500 wells in the Eagle Ford, focusing on natural gas production. The company has executed a public works contract in Olmos field for 14 years. Olmos field is estimated to contain 800 bcf of gas.

 Apache Corp., Houston, reported making an oil discovery on Block 9/18a Area-W in the UK North Sea. The Garten discovery well lies 6 km south of the Beryl Alpha platform. The Garten well targeted a downthrown structural closure and encountered more than 700 ft of net oil pay in stacked, high-quality Jurassic-aged sandstone reservoirs. Recoverable resource is expected to exceed 10 million bbl of light oil, which is at the high end of predrill estimates, Apache said. Apache has a 100% working interest in the Garten block. This latest discovery is the company’s fourth commercial find in the Beryl area in the past 3 years, said John J. Christmann IV, Apache’s chief executive officer and president. These discoveries have spanned several play types ranging from the Tertiary to the Triassic. “Apache’s strategy to focus on exploration near operated facilities is set to deliver significant production without the long cycle time of large scale projects,” Christmann said. The Garten discovery well will be suspended as a future producer and tied back to the Beryl Alpha platform. Apache is working closely with the Oil and Gas Authority (OGA) to obtain the regulatory approvals to initiate production, which is anticipated in first-quarter 2019.

India extends open-acreage bid round

Mubadala developing gas field off Malaysia

India’s Directorate General of Hydrocarbons has extended into May 2 the bidding under its open acreage licensing program, which opened Jan. 18 (OGJ Online, Jan. 19, 2018). The Ministry of Petroleum and Natural Gas unit gave no reason for the extension. The round, for which bidding originally was scheduled to close Apr. 3, offers 55 blocks covering 59,282 sq km nominated by oil and gas operators. It’s India’s first use of open-acreage licensing. Of blocks open for bid, 46 are onshore, 8 are in shallow water, and 1 is in deep water.

Mubadala Petroleum, Abu Dhabi, expects production to begin by the first quarter of 2021 from Pegaga natural gas field offshore Malaysia. The company and its partners will develop the field with an integrated central processing platform on an 8-legged jacket designed for 550 MMscfd of gas plus condensate. Produced fluids will move through a new 38-in. subsea pipeline linked to an existing system for transport to the Malaysia LNG plant in Bintulu. The field is in 108 m of water on Block SK 320 in Central Luconia province off Sarawak. Mubadala, operator with a 55% interest, state-owned Petronas Carigali, with 25%, and Sarawak Shell Bhd., with 20%, expect to invest more than $1 billion in the project. Mubadala let a contract for engineering, procurement, construction, installation, and commissioning to Sapura Fabrication Sdn. Bhd. Pegala is one of three discoveries made during 2013-14 on the block. Others are Sirih and Sintok (OGJ Online, June 23, 2014).

Pemex, Lewis to develop Eagle Ford field

China, Philippines eye joint exploration The governments of China and the Philippines say they’re moving toward cooperative offshore oil and gas exploration. The countries have been locked in a territorial dispute over parts of the South China Sea. The island nation won an arbitration challenge to China’s claim to most of the sea in 2016. Brunei, Malaysia, Taiwan, and  Vietnam also dispute the Chinese claim.

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Oil & Gas Journal | Apr. 2, 2018

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BSEE implements permitting process Q A program The US Bureau of Safety and Environmental Enforcement has implemented a new quality assurance process to review and assess its permitting systems. The process aims to help inform best practices for offshore energy permitting, BSEE Director Scott A. Angelle said. “Taking these actions now will promote BSEE’s effective monitoring of permit processes and provide an avenue to progress toward overall improvements such as decreased processing delays,” he said. The new directive by BSEE’s Office of Offshore Regulatory Programs requires the agency to periodically review and assess permitting processes for consistency, timeliness, and efficiency across the US Department of the Interior agency’s districts and regions. The quality assurance process will be conducted by carefully selected teams of BSEE staff who will develop the assessment plans and conduct the assessments, the agency said. These assessments will review permitting and include in-person site visits to district or regional offices where applicable, it indicated

tion from Khor Mor natural gas field in Kurdish Iraq to increase to 385 MMcfd by yearend from 305 MMcfd at present. The company last year reached an arbitration settlement with the KRG that included $1 billion in cash for past receivables and a commitment to expand investment and operations (OGJ Online, Oct. 23, 2013). The expansion is to include a multiwell drilling program in Khor Mor and Chemchemal fields, operated for Pearl by Crescent Petroleum and Dana Gas, which hold 35% interests each in the consortium. Pearl said debottlenecking will achieve the initial production increase from Khor Mor. It plans to boost output from the fields eventually to 900 MMcfd.  A 58-km, 24-in. pipeline connects the Khor Mor field and gas processing plant with a power station at Chemchemal field to the north. A 116-km, 24-in. pipeline connects Chemchemal with a power station at Erbil. Other partners in Pearl Petroleum are OMV, MOL, and RWEST.

Gas flow starts at B15 field off Malaysia DRILLING & PRODUCTION Q U I C K T A K E S BSEE plan will increase inspection time offshore The US Bureau of Safety and Environmental Enforcement will begin a new program on Apr. 1 that will increase physical inspection time offshore while saving nearly $20 million over 3½ years, the US Department of the Interior agency reported. A team in its Gulf of Mexico regional office in New Orleans developed the approach as it explored ways to make inspections more efficient and reduce helicopter operating expenses, it said. “This new process will allow BSEE inspectors to increase physical inspection time on offshore oil and gas facilities,” noted Michael Saucier, who supervises district field operations in the region. Using technology that provides inspectors access to onshore electronic records, inspectors now will have much more time to inspect operations offshore at more than 2,200 facilities in the gulf, BSEE said. It also will reduce helicopter operating expenses by 15% without affecting safety and environmental protections, it added. The agency pointed out that production from the US Outer Continental Shelf accounts for 1 of every 6 bbl of crude produced in the US. “With 98% of all OCS energy produced from the Gulf of Mexico, it is critical that BSEE continues to maximize efficiency and ensure that oil and gas operations are conducted safely and in an environmentally sustainable manner,” it said.

Pearl to boost gas flow in Kurdish Iraq Pearl Petroleum Co. Ltd., a five-company consortium based in Sharjah, has signed a 10-year gas sales agreement with the Kurdistan Regional Government (KRG) that will allow produc-

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Sapura Exploration & Production (Sarawak) Inc., Kuala Lumpur, has started production from B15 natural gas field off Sarawak, East Malaysia. The field, discovered i n December 2010, is on Block SK310. It produces through a processing platform linked by a 35-km pipeline to an existing system carrying gas to the Malaysia L NG plant at Bintulu. The company expects B15 production to peak at 100 MMcfd. Sapura E&P (Sarawak) operates the Block SK310 production-sharing contract with a 30% participating interest. Other interests are state-owned Petronas Carigali, 40%, and Diamond Energy Sarawak Sdn. Bhd., a subsidiary of Mitsubishi Corp., 30%.

PROCESSING Q U I C K T A K E S RNPK delivers first batch of high-octane gasoline PJSC Rosneft subsidiary JSC Ryazan Oil Refining Co. (RNPK) has produced the first batch of AI-100 high-octane gasoline at its 18.8 million-tonne/year Ryazan refinery about 120 miles southeast of Moscow. Production of the low-sulfur gasoline, which occurred in mid-March, is a result of implementation of Rosneft’s broader program to modernize and upgrade operations of its Russian refineries for production of fuels meeting more stringent global environmental quality specifications, Rosneft said. Designed for high-power engines, the new product also has passed all qualification and benchmark tests for compliance with fuels conforming to the Eurasian Economic Commission’s technical specifications for the K5 emission class (equivalent to Euro 5-quality environmental standards), the operator said.  According to Rosneft’s web site, the following projects are

Oil & Gas Journal | Apr. 2, 2018

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currently under implementation at RNPK’s refinery: • Reconstruction of the diesel fuel hydrotreating unit. • Construction of a two-unit desulfurization plant for dry hydrocarbon gases with a saturated amines regeneration block. • Construction of a production complex for elemental sulf ur applying the Klaus method, with storage, shipping, and operation infrastructure. • Construction of the crude-vacuum distillation Unit 5. • Reconstruction of treatment insta llations. • Construction of the vacuum gas oil hydrocracking complex. The projects come as part of Rosneft’s company-wide refinery modernization plan launched in 2008, which includes the construction of 30 units and reconstruction of more than 20 units at Rosneft’s Russian refineries between 2012 and 2020.

Feasibility study due for Mozambican refinery Empresa Nacional de Hidrocarbonetos EP (ENH), Mozambique’s state-owned oil company, has completed a tender seeking expressions of interest (EOI) from consultants to conduct a study evaluating the feasibility of constructing what would become the country’s first refinery. Closed as of 10:00 a.m. local time in Mozambique on Mar. 16, the tender invited interested parties to submit their EOIs to participate in an upcoming tender process for the provision of consultancy services for “the elaboration of the feasibility study for refinery deployment in Mozambique,” according to ENH tender documents. To be based on proposed crude supplies from the Rovuma basin, Mozambique basin, and imported feedstock from the international market, the EOI was to include the following: • A technical report that analyzes the various alternatives for hydrocarbon processing as well as type and quantity of the products depending on the national and regional market. • An economic evaluation. • A market study at both the local and regional levels.

MEGlobal lets contract for Freeport MEG plant Dubai-based MEGlobal International FZE, a unit of Kuwait’s first international petrochemical joint venture Equate Petrochemical Co., has let a contract to Fluor Corp. to provide mechanical construction of its monoethylene glycol (MEG) plant now under construction at Dow Chemical Co.’s currently expanding Oyster Creek petrochemical complex in Freeport, Tex. Fluor’s mechanical construction scope includes the installation of equipment, steel, and piping for the 700,000-tonne/year MEG process unit, the service provider said. First announced in March, the grassroots MEG plant comes as part of MEGlobal’s program to create greater flexibility to satisfy grown demand for ethylene glycol products in the US and Asia-Pacific markets, as well as strategy to expand the company’s global footprint (OGJ Online, Mar. 28, 2016). The new MEG plant, which will receive ethylene feedstock from Dow’s currently expanding Oyster Creek ethylene pro-

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duction site under a long-term supply agreement, remains on schedule for startup in mid-2019 (OGJ Online, Oct. 26, 2016). Equate Petrochemical is an international JV of Kuwait’s state-owned Petrochemical Industries Co., 42.5%; Dow, 42.5%; Boubyan Petrochemical Co., 9%; and Qurain Petrochemical Industries Co., 6%.

TRANSPORTATION Q U I C K T A K E S Inpex further delays Ichthys LNG start-up  Japanese operator Inpex has announced a further delay in its Ichthys LNG project off Western Australia, pushing back the on-stream date by at least 2 months. The company had set a deadline of Mar. 30 to begin production from the $37-billion development which, in turn, was a 6-month delay of a previous schedule. Inpex now expects to complete commissioning of the central processing facility near the field offshore Kimberley and bring the gas on stream between April and May. This will be followed by production and shipment of condensate via the giant Ichthys Venturer floating production, storage, and offloading vessel at the field and then LNG and LPG in sequence from the Darwin liquefaction plant. Inpex said commissioning of the first LNG production train has been completed, as has the FPSO and subsea production systems. The company hopes to hold to the new timetable but concedes the activity schedule may fluctuate depending on weather conditions at the numerous worksites, along with preparation activities and other factors.

Perenco begins FLNG operations of fshore Cameroon Perenco has begun production at Cameroon LNG via Golar LNG Ltd.’s floating LNG (FLNG) production unit Hilli Episeyo. Hilli Episeyo arrived in Cameroon in late November. A shipto-ship transfer of cool down LNG with the Golar Bear took place in mid-December 2017, followed by the introduction of feed gas from the onshore processing plant. Commissioning of the FLNG’s refrigerant trains continued into February. Gazprom has an 8-year purchase agreement for all of Cameroon LNG’s anticipated 1.2 million tonne/year production from FLNG Hilli. Golar said its experience with conversion and commissioning FLNG Hilli would be applied to the Fortuna project in Block R off Equatorial Guinea. Ophir Energy PLC and OneLNG, a  joint venture of subsidiaries of Golar and Schlumberger, in late 2016 established a joint operating company to develop Fortuna using the Golar Gandria FL NG. Golar Gandria is now at Keppel Shipyard in Singapore. Phase 1 Fortuna development would tie four gas wells back to FLNG Gandria, targeting an eventual plateau output of 2.2 million tpy. First gas is expected in 2019. Fortuna Phase 2 would double production via an additional 5 wells and a second FLNG.

Oil & Gas Journal | Apr. 2, 2018

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 2018-2019 EVENT CALENDAR

 2018-2019 EVENT CALENDAR Denotes new listing or Events_Learn_Listing 9-11. a change in previously published information. Oil & Gas Investment Symposium (OGIS), New York, web site: www.ipaa. org/events/ogis-newAPRIL 2018 york-2018/ 9-11. Pipeline Energy Expo, Global Oil & Gas Atyrau Tulsa, web site: w ww. Exhibition 2018, pipelineenergyexpo. Atyrau, Kazakhstan, com/index.html 3-5. web site: https://oilNational Oil Companies gas.kz/en/ 10-12. Assembly, Abu Dhabi, Mexico Gas Summit, San web site: oilandgasAntonio, web site: https://  council.com/event/  www.mexicogassummit. noc 9. com/mexico-gas-sumOperational Excellence mit-energy-forum 11-12. in Refining & Petrochemicals Summit, Houston, web site: https://opexinrefiningandpetrochem.iqpc. com/?utm_medium_ portal&mac=OGIQ_

sociation Midstream Annual Convention, Austin, web site: https://  gpamidstream.org/ 15-18.

SPE/IADC Managed Pressure Drilling & Underbalanced Operations Conference & Exhibition, Kuwait Oil & Gas SumNew Orleans, web site: mit, Kuwait City, web site: www.iadc.org/event/  www.cwckuwait.com/ speiadc-managed16-17. pressure-drilling-underbalanced-operationsconference-exhibition/ 3rd World Congress 17-18. & Expo on Oil, Gas & Petroleum Engineering 2018, Dubai, web site: North American Coalscientificfederation.com/  bed Methane Forum, petroleum-engineerCanonsburg, Pa., web ing-2018/ 16-17. site: www.nacbmforum.com/conference. SPE International Confer- html 18. ence & Exhibition on SPE Improved Oil Recov- Health, Safety, Security, Oil & Fuel Theft Summit Environment & Social 2018, Geneva, web site: ery Conference, Tulsa, https//oilandfueltheft. web site: w ww.speior.org/ Responsibility, Abu Dhabi, web site: www. iqpc.co.uk/ 18-19. 14-18. spe.org/events/en/2018/  conference/18hse/  International SAP Gas Processors AsConference for Oil & Gas, Lisbon, web site: uk.tacook.com/events/  conferences/details/  international-sap-conference-for-oil-and-gas. html 17-19.

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homepage.html 16-18.

SPE Norway One-Day Seminar, Bergen, web site: www.spe. org/events/en/2018/  conference/18berg/oiland-gas.html 18. The Global Engineering Procurement & Construction Project Management for the Oil & Gas/Energy Industry 2018, Amsterdam, web site: https://www.clocate.com/conference/  The-Global-Engineering-Procurement-andConstruction-ProjectManagement-for-TheOil-and-Gas-EnergyIndustry-2018/71970/  18-20.

angelesbasin/westernregional-meeting-2018 22-26.

Association of International Petroleum Negotiators (AIPN) International Petroleum Summit, London, web site: www.internationalpetroleumsummit.org 23-25. SPE-Kingdom of Saudi Arabia Section (SPEKSA) Annual Technical Symposium & Exhibition, Dammam, web site: www.spe-ksa.org/  atse/ 23-26.

tion, Tehran, website: https://www.expocheck. com/en/expos/27898 30. Offshore Technology Conference, Houston, web site: 2018.otcnet. org/ Apr. 30-May 3. MAY 2018 The East Texas Energy Symposium, Kilgore, Tex. https://www.facebook.com/EastTexasOilMuseum/ 1. Oil & Gas International Licensing Symposium 2018, London, web site: https://www.oilgaslicensing.com/ 1-3.

Alliance Expo & Annual Meeting, Wichita Falls, Tex., web site: texasalliance.org/event/  Petroleum Safety alliance-expo-annual- Conference, Banff, Alta., web site: www. meeting/ 24-25. enform.ca/events/psc/  Oil & Gas Supply Chain about-psc-conference. cfm 1-3. Compliance, Houston, web site: http://  sccompliance-us.com/ Erbil Oil & Gas International E xhibition, 24-26. Erbil, Iraq, web site: LNG International Sum- erbiloilgas.com/index. mit, Hamburg, web site: html# 1-5. lngsummit.org/ 25-26. Mediterranean Oil & Gas Summit, China LNG & Gas International Summit & Rome, web site: Exhibition, Bejing, web https://10times.com/  site: www.chinalngsum- mediterranean-oil-gassummit 2-3. mit.com/ 25-26. Applied Petroleum Geochemistry, Denver, web site: https://www. eventbrite.com/e/  applied-petroleumgeochemistry-tickets-42319290136/ 26. Sub-Saharan Africa Oil & Gas Conference, Houston, web site: https://www.energycorporateafrica.com/ 26-27.

Iran Oil Show, Tehran, web site: https://10times.com/  iran-oil-show 6-9. Eastern Unconventional Oil & Gas Symposium 2018, Lexington, Ky., web site: www.euogs. org/ 7-8. RefComm, Galveston, Tex., web site: refiningcommunity.com/recomm-galveston-2018/  7-11.

SPE Western Regional Meeting, Garden Grove, Iran Oil Show: InternaCalif., web site: http://  tional Oil, Gas, Refining connect.spe.org/los& Petrochemical Exhibi- Four Corners Oil & Gas

Oil & Gas Journal | Apr. 2, 2018

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2018-2019 EVENT CALENDAR

Conference, Farmington, NM, web site: https://www.fourcornersoilandgas.com/ 9-10.

Production & Exploration Association (APPEA) 2018 Conference & E xhibition, Adelaide, web site: https://www. appeaconference.com. Research & Development Petroleum Confer- au/ 14-17. ence & E xhibition, Abu Dhabi, web site: www. Gas-to-Power Africa rdpetro.org/ 13-15. Congress 2018, Cape Town, web site: ww w. energycouncil.com/  FLNG Global 2018, event-events/gasAmsterdam, web site: power-africa-congress/ https://www.clocate. com/conference/FLNG- 15-16. Global-2018/49265/ International School of 14-15. Hydrocarbon Measurement, Oklahoma City, Canada Gas & LNG Conference & Exhibition web site: ww w.ishm. info/ 15-17. 2018, Vancouver, BC, web site: ww w.canadagaslng.com/ 14-16. Global Oil & Gas Uzbekistan 2018 (OGU 2018), Tashkent, web Australian Petroleum

Oil & Gas Journal | Apr. 2, 2018

2018-2019 EVENT CALENDAR

site: oilgas.uz/ 16-18.

tion & Exhibition, Salt web site: https://  Lake City, web site: ace. europetro.com/week/  International Conference aapg.org/2018 20-23. idw2018  22-25. on Petroleum Engineering, Rome, web site: AAPG 2018 Annual East Africa 2018 Oil & petroleumengineering. Convention & Exhibition, Gas International Trade conferenceseries.com Salt Lake City, web site: Exhibition, Nairobi, web 17-18. www.aapg.org/events/  site: expogr.com/Keconferences/ace/ 20-23. nyaoil/ 29-31. World Fuel Oil Summit XI, Limassol, Cyprus, PNEC: International Pe- International Caspian web site: www.axeltroleum Data Integration, Oil & Gas Exhibition rodenergyprojects.com Information & Man2018, Baku, web site: 17-19. agement Conference, https://www.clocate. Houston, web site: www. com/conference/25thpnecconferences.com/  International-CaspianWorld Congress on Petroleum Refineries & index.html 22-24. Oil-and-Gas-ExhibiNatural Gas Recovery, tion-2018/27231/ May Singapore, web site: LNG Fuels Summit, 29-June 1. petroleum.conferencAmsterdam, web site: eseries.com 18-19. www.lngfuelssummit. Projects & Technology com/ 22-24. Forum, Syzran, Russia, American Association web site: https://euroof Petroleum Geologists International Downpetro.com/event/73/0 (AAPG) Annual Conven- stream Week, Prague, 30-31.

JUNE 2018 Operational Excellence in Energy, Chemicals & Resources, Calgary, web site: https://opexsummit. iqpc.com/?utm_medium_portal&mac=OGIQ_ Events_Learn_Listing 4-6. Caspian International Oil & Gas E xhibition, Baku, web site: caspianoilgas. az/ 5-8. International Liquid Terminals Association (ILTA) International Operating Conference & Trade Show, Houston, web site: https://www. ilta.org/AOCTS 11-13. SPE Europec featured

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2018-2019 EVENT CALENDAR

at EAGE Conference & Exhibition, Copenhagen, web site: www.spe.org/  events/en/2018/  conference/18euro/  homepage.html 11-14. Future Oil & Gas 2018 Conference, Aberdeen, web site: www.futureoilgas. com/ 12-13. Global Petroleum Show (GPS 2018), Calgary, web site: https://  globalpetroleumshow. com/ 12-14. Africa Oil & Gas Local Content Conference & Exhibition, Luanda, Angola, web site: ametrade.org/alc/?utm_ source=Worldoils&

utm_medium=Banner& cow, web site: www. utm_campaign= mioge.ru /en-GB/about /  ALC%202017 14-16. exhibitions/MIOGE.aspx 18-21. Russian Petroleum & Gas Congress FSRU Asia Summit, (RPGC2018), MosSingapore, web site: cow, web site: https://  https://f srusumwww.clocate.com/  mit.iqpc.sg/?utm= conference/14thmedium=portal&mac Russian-Petroleum=OGIQ_Events_Learn_ and-Gas-CongressListing 20-21. RPGC-2018/27847/ 18-19. SPE International Oilfield Scale Conference SPE International Oil& Exhibition, Aberdeen field Corrosion Confer- web site: www.spe. ence & Exhibition, Ab- org/events/en/2018/  erdeen, web site: www. conference/18oss/  spe.org/ events/en/2018/  homepage.html 20-21. conference/18ofcs/  home.html 18-19. International Refining & Petrochemical ConvenMoscow International tion China 2018, ShangOil & Gas Exhibition hai, web site: https://  (MIOGE 2018), Moswww.bmiresearch.com/ 

events/4th-international- coreconf erences.com/  refining-petrochemical- petrochemistry2018/ convention-china-2018 28-30. 21. JULY 2018 SPE Trinidad & Tobago Section 2018 Energy 3rd World Congress on Resources Conference, Petroleum & Refinery, Port of Spain, web site: Melbourne, web site: http://spettconf.org/ petroleum.conferenc25-26. eseries.com/ 2-3.

Neuquen, web site: www.spe.org.ar/events/  aneu2018/ 14-16. Summer NAPE, Houston, web site: napeexpo. com/ 15-16.

IADC/SPE Asia Pacific Drilling Technology Conference & Exhibition, Bangkok, World Gas Conference, Oil Spill India 2018 (OSI) web site: www.spe. Washington, DC, web International Conference org/events/en/2018/  site: wgc2018.org/  & Exhibition, New Delhi, conference/18apdt/  contact-us/ 25-29. web site: w ww.oilspillin- homepage.html 27-29. dia.org/ 5-6. Libyan-European Oil Offshore Northern Seas & Gas Summit, Vienna, World Congress on (ONS 2018), Stavanger, web site: libyaogs.com Petroleum Refinery & web site: www.ons. Natural Gas Recovery, no/2018 / 27-30. 28-29. Melbourne, web site: World Congress on Pet- https://petroleum.confer- SPE Artificial Lift rochemistry & Chemical enceseries.com/ 19-20. Conference & ExhibiEngineering, Dubai, tion—Americas, The web site: https://bioInternational ConferWoodlands, Tex., ence on Petrochemical web site: www.spe. Engineering 2018, org/events/en/2018/  Kuala Lumpur, web site: conference/18alce/  https://www.clocate. home-page.html 28-30. com/conference/2nd-International-conference- SEPTEMBER 2018 on-Petrochemical-Engineering-2018/73368/ FPSO World Congress, 23-25. Marina Bay Sands, Singapore, web site: SPE/AAPG/SEG https://www.fpsoworldUnconventional congress.com/?utm_ Resources Technology medium=portal& mac= Conference, Houston, OGIQ_Events_Learn_ web site: http://urtec. Listing 4-5. org/2018/ 23-25. Engenious SympoInternational Symposium & Exhibition for sium on Combustion Upstream Innovation, 2018, Dublin, web site: Aberdeen, web site: www.combustionsymwww.engeniousglobal. posia.org/2018/home com/ 4-6. July 29-Aug. 3. SPE Liquids-Rich AUGUST 2018 Basins Conference—North America, International ConferMidland, Tex., web ence & Expo on Oil site: www.spe.org/  & Gas, Madrid, web events/en/2018/  site: oil-gas.conferenc- conference/18lrbc/  eseries.com/ 9-10. liquids-rich-basinsconference/  5-6. SPE Argentina Exploration & Production Oil & Gas Thailand of Unconventional (OGET) 2018 & PetroResources Symposium, chemical Asia 2018,

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Oil & Gas Journal | Apr. 2, 2018

2018-2019 EVENT CALENDAR

2018-2019 EVENT CALENDAR

Bangkok, web site: oilgasthai.com/ 6-8. EUROCORR 2018— The European Corrosion Congress, Cracow, web site: eurocorr.org/  9-13.

Asia Pacific Congress on Oil & Gas 2 018, Shanghai, web site: https://www.clocate. com/conference/10thAsia-Pacific-Congress-On-Oil-andGas-2018/70722/ 10-11.

Gas/LNG Contracts: Structures, Pricing & Negotiation, Port of Spain, web site: www. infocusinternational. com/gascontracts/ 10-14.

Oil Sands Trade Show & Conference, Fort McMurray, Alta., w eb site: https://oilsandstradeshow.com/ 11-12. Pipeline Week, Houston, web site: www. pipelineweek.com/  index.html 11-13. International Conference on Petrochemical, Energy Conservation & Emissions Reduction (PECER 2018), Chongqing, China, web site: engii.org/conference/  PECER2018 15-17. IoT in Oil & Gas 2018, Houston, web site: https://www.iotinoilandgas.com/ 18-19. Asia Pacific Congress on Oil & Gas, Beijing, web site: oil-gas.chemicalengineeringconference.com/ 17-19. Middle East Heavy Oil Congress, Muscat, web site: meheavyoil.com 17-19.

Gastech Exhibition & Conference, Barcelona, web site: ww w.gastechevent.com/ 17-20.

Oil & Gas Tanzania 2018, Dar es Salaam, Tanzania, web site: https://www.clocate. com/conference/4thOil-and-Gas-TanTurbomachinery & Pump Symposia, Hous- zania-2018/48067/ 11-13. ton, web site: https://  tps.tamu.edu 18-20. 2018 LNG Summit, Chicago, web site: Petrochemistry & www.lngsummit.com/ Chemical Sciences, 14-16. Montreal, web site: https://petrochemicalsciences.conferenc- SPE Russian Petroeseries.com/ 24-25. leum Technology Conference, Moscow, SPE Annual Technical web site: ww w.spe. org/events/en/2018/  Conference & Exhibiconference/18rptc/  tion (ATCE), Dallas, web site: www.atce.org/  spe-russian-petroleumtechnology-conferencewelcome 24-26. moscow.html 15-17. International Refining & Petrochemical Confer- SPE International Hydraulic Fracturing ence (IRPC), HousTechnology Conference ton, web site: www. & Exhibition, Muscat, hpirpc.com/events/  web site: ww w.spe. irpc-americas-2018/  event-summary-681ae- org/events/en/2018/  conference/18ihft/  b2992784599a1873 hydraulic-fracturingaaa7492994a.aspx technology-confer25-26. ence-and-exhibition. html 16-18. World Congress on Oil, Gas & Petroleum Gas/LNG Contracts: Refinery, Abu Dhabi, web site: https://petro- Structures, Pricing & leumrefinery.conferenc- Negotiation, Johannesburg, web site: www. eseries.com/ 27-28. infocusinternational. com/gascontracts/inOCTOBER 2018 dex.html 22-26. RefComm Valencia, Gulf Downstream Valencia, web site: Association (GDA) http://refiningcommunity.com/refcomm- International Downstream Conference & valencia-2018/ 1-5. Exhibition, Manama, Kazakhstan Internation- web site: https://www. al Oil & Gas Exhibition gdaconference.org/ & Conference, Almaty, 23-25. web site: https://www. kioge.kz/en/home/30- SPE Asia Pacific Oil & Gas Conference & conference/19-conf Exhibition, Brisbane, 3-5. web site: ww w.spe. Middle East PetroTech org/events/en/2018/  conference/18apog/  2018, Manama, web asia-pacific-oil-andsite: https://www. facebook.com/pg/ME- gas-conference-andPetrotech/photos/ 7-10. exhibition.html 23-25.

Oil & Gas Journal | Apr. 2, 2018

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JOURNALLY SPEAKING

IOR and geosciences

PAULA DITTRICK  Upstream Technology Editor

Industry has expanded the definition of improved oil recovery (IOR) and advanced its application to economically produce more of the world’s oil that already has been discovered. The Midcontinent Section of the Society of Petroleum Engineers has hosted a biennial IOR conference in Tulsa since 1978. E. Lance Cole, general chairman of the SPE IOR 2018 Conference, hopes to emphasize geosciences during the conference set for Apr. 14-18. In the spirit of cooperation across disciplines, this year’s agenda includes for the first time a short course on development geology. “IOR without due respect for the geosciences can handicap any project,” Cole told OGJ. He also advocates that operators “look at IOR projects across the world to glean what applies” to their own particular projects. Cole is intersociety collaboration manager at the Society of Exploration Geophysicists. He leads SEG’s efforts to collaborate with other professional societies to organize major technical conferences and workshops. He works with geoscientists worldwide. “Geoscience is part of everything…geoscientists themselves are getting more sophisticated in how they describe a reservoir and forecast how it will perform,” Cole said. “In IOR, as well as all areas of oil and gas, incremental im- Cole provements come when people work hard and make step advances.” Before joining SEG, Cole was president of Petroleum Technology Solutions Inc., which provided engineering consulting for the Petroleum Technology Transfer Council. “I facilitated brainstorming between very small independent producers and leading researchers in US National Laboratories,” Cole said. “As producers described their problems, researchers could readily see where their research—which often was not directly related to oil and gas—could with minor adaptation provide disruptive solutions.”

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SAVE T HE D ATE 

Disruptive technology This year’s conference theme is “Acceptance, Perseverance, and Disruption Enhance Future IOR.” Cole said acceptance “means coming to terms with a realistic future oil-price scenario.” He said operators of both deepwater and unconventional plays have learned they must earn profits in current economic circumstances rather than waiting for higher crude prices. Industry leaders need perseverance to achieve incremental advances in IOR techniques. Cole considers disruption a positive force, noting the offshore industry has developed many deepwater successes through a series of disruptive technological advancements. He also believes disruption has redefined “the playing field” for IOR and enhanced oil recovery. “Looking at unconventional resources, the combo of horizontal drilling and hydraulic fracturing could be considered the disruptive technology.”

Geoscience Development geology is key to managing IOR projects, said organizers who decided to include such a course. The  American Association of Petroleum Geologists developed the course. Terngu Utim will teach the course on Apr. 14, providing information about reservoir Utim characterization, reservoir behavior, and reservoir connectivity analysis. He plans to discuss how to design wells to fulfi ll their designated roles in IOR projects. Utim is managing consultant at XPSG LLC, a geoscience and field development consulting company based in Houston. Formerly with Nexen and Shell, he has participated in IOR projects involving carbonates (Permian basin) and siliciclastic formations (Gulf of Mexico and West Africa deepwater as well a s US and West Africa onshore).

Oil & Gas Journal | Apr. 2, 2018

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Regulatory repair They’ll call it an assault on environmental protection. Pressure groups and their friends in politics and the media will complain that the Environmental Protection Agency has advanced its unholy campaign against regulation yet again.  What EPA in fact will do when it and the National Highway Traffic Safety Administration (NHTSA) ease vehicle fuel-efficiency standards is to accommodate excesses of the Obama administration to economic reality. This has occur red frequently in the yearling adm inistration of President Donald Trump. EPA Administrator Scott Pruitt, to his credit, seems unfazed by the by the condemnation his repairs have provoked.

Change coming  At this writing, details had not been disclosed about changes to Obama-era standards for vehicle greenhouse gas emissions and corporate average fuel economy (CAFE). An EPA spokeswoman had confirmed that revisions were sent to the White House Office of Management and Budget, the last step before publication. And an official of NHTSA, which administers the program with EPA, had told the Senate Committee on Commerce, Space, and Technology that a proposal would be made about  Apr. 1. For the oil and gas industry, this is mildly welcome news. For American motorists, it represents strong economic relief. And for the environment, it’s hardly the catastrophe many will call it. Characteristically, the Obama administration opted for maximum regulation when a review of its vehicle-mileage targets indicated problems with practicability. In 2012, the EPA and NHTSA had toughened requirements for new light-duty vehicles through 2025 under a complex system regulating emissions and mileage together through a standard expressed as miles per gallon. Because requirements can cover no more than 5 years, standards for later years were estimates, subject to a midterm evaluation. That evaluation, conducted in 2016, revealed problems. Motorists favored heavier vehicles. While automakers had hoped to balance fleet emissions with sales of electric vehicles and hybrids, market patterns in mid-2016 made clear that aggressive targets wouldn’t be met. Vehicle manufacturers

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sought relaxation of the 2022-25 standards. In its final weeks, the Obama administration declined. In early weeks of the Trump administration, automakers requested that the scheduled toughening of standards not be made. Trump’s EPA and NHTSA now seem ready to oblige. Before howling begins from the environmentalist left, a few observations are in order. Congress authorized CAFE standards to address fuel supply, not environmental protection. Emissions of greenhouse gases and their effect on globally averaged temperature were not matters of concern in 1975, when lawmakers passed the Energy Policy and Conservation Act in response to the  Arab oil embargo of 1973-74. Embracing conventional wisdom of the day, lawmakers thought US production of crude oil would irreversibly decline, consumption of gasoline would strongly increase, prices of oil prices would relentlessly climb, and dependency on imported oil would perpetually grow. Conventional wisdom of the mid-1970s was thoroughly wrong. More by political fusion than by law, oil supply gave way to air emissions, especially greenhouse gases, as the dominant reason to regulate vehicle fuel mileage. This is nothing to regret. Limiting emissions is desirable, and improving vehicle fuel mileage is one way to go about it. But the value of limiting emissions should be weighed against costs of the effort and related to the diminished value of improving vehicle fuel mileage to address vanishing challenges of oil supply.

Energy mistakes In 2012, of course, the EPA and NHTSA would have none of that. The regulatory approach then was to cut the use of fossil energy however possible, wherever possible, regardless of cost, no matter how little the effort might influence global temperature. Climate myopia seduced the Obama administration into a series of appalling energy mistakes, from which Pruitt and others in the Trump administration are now rescuing consumers and the economy. The Obama team blissfully regulated to raise the costs of energy forms it disliked and of vehicles  Americans want but that regulators wished them not to buy. Popular reaction against imperiousness of this type helps explain why Trump is president.

Oil & Gas Journal | Apr. 2, 2018

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Selling US LNG to Europe requires commercial terms, speakers say Nick Snow

Washington Editor

Europe’s natural gas market is evolving from politically driven projects to commercial agreements, and US suppliers will need to move more aggressively on those terms if they expect to be a substantive part of it, speakers suggested at a Mar. 22 conference. “US suppliers have an opportunity to step in now and line up customers when prices are low. The biggest question is who will take the strategic r isk,” said Mindaugus Jusius, chief executive at AB Klaipedos Nafta, Lithuania’s state oil products and gas terminal company. “The US government did its part to start reforming policies, but US gas is owned by companies which need to star t moving the conversation about liquefied natural gas in Europe from political to commercial terms,” added Amos J. Hochstein, senior vice-president for marketing at Tellurian Inc. in Houston, during the discussion on expanding global gas infrastructure hosted by LNG Allies and Our Energy Moment. Hochstein added, however, that it will be necessary for the US, as well as Europe, to increase its gas pipeline capacity because Permian basi n production associated with cr ude oil has risen so dramatically. “It’s at a critical point; $150 billion of new infrastructure wi ll be needed domestically. With all the growth in the Permian, there’s not capacity to ship gas to Louisiana,” Hochstein said. “If governments in both the US and Europe aren’t willing to put infrastructure in place, real progress won’t be made.” Magnolia LNG LLC Chief Executive Greg M. Vesey noted that it is important for more US suppliers to understand the changing customer base in Asia as well as Europe. “More traders are becoming interested. They’re in a new tier which has regasification c apacity. We met several of them yesterday at a [US Trade and Development Agency] briefing in Houston,” he said.  Vasey predicted US companies w ill be able to compete in Europe because their prices will reflect those at the Henry Hub, which move more often with markets than gas based on contracts. “The right set of terms will make deals happen,” he said. Goran Francic, managing director at LNG Hrvatska in Croatia, which is developing an offshore LNG import ter-

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minal that will use a floating storage unit, said that an open season to determine i nterest and investment will follow soon once the government makes a final investment decision in  June and issues location and construction permits soon after.

‘They shouldn’t wait’  “We’re thinking of using the FSU not just for regasification, but also to bunker other projects,” Francic said. “A lot of US companies have been around in the past. They shouldn’t wait for small European national companies which would be their customers to lock capacity in during the open season. They should be there too.” Poland Sec. of State Piotr Naimski said the first US LNG cargoes have begun to arrive at the country’s LNG terminal, but suggested that US suppliers will need to start offering more medium-term contracts to keep competitive with gas, which is arriving by pipeline from Norway’s continental shelf and North Africa. “Contracts will need to be constructed to make risk attractive to customers,” he said. “European terminals receive almost 100 billion cu m (bcm)/year of LNG already,” said Naimski, who also is the country’s plenipotentiary for strategic energy infra structure. “We also know that Europe is [Russian state supplier Gazprom’s] most important market, with 175 bcm/year of sales. There’s an opportunity for Eastern and Central Europe to take back what the Soviets took 25 years ago, but the Russians are very deeply rooted in the region. We are trying to create a civili zed, free gas market.” Lithuanian Energy Minister Zygimantas Valciunas said, “One dream came true when we received the first gas shipment from Poland in 2017. The Klaipedos terminal ended a 6-year Russian monopoly in the Baltic states. Gas prices immediately dropped in half. We have another dream now— steady supplies from US companies—which we hope won’t take as long.”  Valciunas said, “We now have a good mix of pipeline and LNG supplies in the Baltic states. But there is a 330-bcm import gap developing in Europe. The question is who will be there to fill it: Russia or the US?”

Oil & Gas Journal | Apr. 2, 2018

 Valciunas said the US, which already has sanctions on Russia in place, should be prepared to use provisions in the Countering America’s Adversaries Through Sanctions Act to block the Gazprom-backed Nord Stream 2 pipeline project. Thirty-nine US senators urged the Trump administration to use that and other tools at its di sposal in a letter to US President Donald Trump several days earlier (OGJ Online, Mar 15, 2018).

British Columbia offers conditional LNG project incentives The government of British Columbia has proposed conditional incentives for LNG projects in a move that tests a governing coalition of the New Democratic and Green parties. It said new conditions and incentives provide a framework for “other industries in British Columbia in similar circumstances” but targeted details to the delayed LNG Canada proposal for a liquefaction plant near Kitimat. The plant would have two trains able to yield at least 6.5 million tonnes/year. LNG Canada, a joint venture led by Shell, postponed a final investment decision on the project in 2016 (OGJ Online,  July 12, 2016).

The incentives  The BC government said these incentives will apply to LNG Canada if the venture decides by Nov. 30, 2018, to proceed with the project: • Performance payments in lieu of the provincial sales tax. LNG projects do not now receive the exemption applicable to input costs, which other manufacturing facilities do. To receive the exemption during construction of the initial ly proposed facility, LNG Canada would need to agree to pay the province annual operating performance payments for 20 years equivalent to what it would have paid in the sales tax during the initial construction period. • Tailored application of climate-mitigation regulations. The government said it recognizes that “energy-intensive, trade-exposed industries, including the natural gas sector, face unfair competition when competing globally with jurisdictions that do not impose carbon taxes.” LNG Canada would be subject to a new “clean growth incentive program” instead of requirements under the Greenhouse Gas Industrial Reporting and Control Act. • Industrial electricity rates. The LNG project would pay the general industrial electricity rate charged by BC Hydro for other industrial customers in the province. • Removal of the LNG income tax. The government said

Oil & Gas Journal | Apr. 2, 2018

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it will introduce legislation to repeal a ta x, imposed by a former Liberal government, that it called cumbersome and wil l use instead “a number of other tax and royalty measures under its new fiscal framework to ensure that British Columbia gets a fair return for its natural gas resource.” The government also sa id it would introduce legislation to repeal the Project Development Agreement Act, which contains measures it said “effectively indemnified proponents against changes” and will make other changes to “improve the transparency and consistency with which it assesses industrial development opportunities.”

‘Competitive issue’  Three LNG export proposals have been canceled in BC . The government said it and LNG Canada conducted a  joint financial analysis of the project. “This analysis corroborated evidence and information from internationally recognized LNG analysts that BC has a competitiveness issue and formed the basis of a mutual understanding upon which the province is prepared to commit measures that will increase the competitiveness of British Columbia’s LNG industry,” the government said in a statement. Premier John Horgan said the province will assess LNG projects against four conditions: a “fair return” for BC’s natural resources, jobs and training, respect for and partnership with First Nations, and environmental protection.  Andrew Weaver, Green Party leader, in January threatened to break from the coalition with the New Democrats over what he called the “LNG folly,” which he said would make achievement of provincial climate goals i mpossible. The government seeks to reduce greenhouse gas emissions against 2007 levels by 40% by 2030 and 80% by 2050. He now says the Greens will wait until autumn and as sess progress toward the climate targets. LNG Canada partners are Shell Canada Energy, 50%; PetroChina, 20%; and Korea Gas Corp. and Mitsubishi Corp., 15% each. Last month the joint venture notified two of its four potential engineering, procurement, and construction contractors that they had been short-listed for selection. The finalists are a partnership of TechnipFMC PLC and KBR Inc. and a partnership of JGC Corp. and Fluor Corp.

Papua New Guinea white paper addresses domestic gas use Rick Wilkinson

OGJ Correspondent

Papua New Guinea has formulated a new white paper on the oil and gas industry, stressing the importance of increasing domestic gas usage in the country.

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Petroleum Minister Fabian Pok used his keynote address to the Papua New Guinea Petroleum & Energy Summit in Port Moresby last week to say that the new policy is aimed at introducing best practices in the industry throughout the country and urging more citizens to become directly involved to drive the electrification of Papua New Guinea through the use of domestic gas. Pok added that a new ministry would be established to administer this when the white paper’s provisions were written into law. He said the huge success of the PNG-LNG project has reduced the perception of political risk in the country and pointed out the importance of harmony and mutual respect between government and the companies involved in the industry. The white paper, he said, was formulated out of the lessons learned from the ExxonMobil Corp.-operated PNGLNG project. Recommendations in the document include setting up an investment framework and robust third-party access regime for strategic gas pipelines and related i nfrastructure; putting in place a domestic market obligation over domestically produced gas up to a certai n percentage of national gas production, pro-rata across all producers; and providing a f lexible and responsible national content requirement so that gas e xplorers and producers maximi ze the local labor and content in their operations. Changes in policy will not be retrospective, but they will apply to three proposed projects that have yet to be issued with development licenses: the offshore Pasca A gas facility in the Gulf of Papua, the P’ynang gas development in Western Province, and the Elk-Antelope project in Gulf province. No new petroleum development licenses or gas agreements will be entered into until the new policies have been implemented. The white paper is currently with the National Executive Council awaiting approval before it is tabled in parliament. Further consultations on the white paper will take place before the September/October parliamentar y sitting.

ADNOC signs deals with Total, CNPC for offshore concessions  Abu Dhabi National Oil Co. (ADNOC) has signed agreements with Total SA and China National Petroleum Corp. (CNPC) in which the French and Chinese companies will be awarded stakes in Abu Dhabi’s new offshore concessions. Under the terms of the agreements, Total has been awarded a 20% interest in the Umm Shaif and Nasr conce ssion and a 5% interest in the L ower Zakum concession. Total contributed a participation fee of $1.15 billion to enter the Umm Shaif and Nasr concession and a fee of $300 million to enter the Lower Zakum concession.

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Meanwhile, CNPC, through its majority owned listed subsidiary PetroChina, has been awarded a 10% interest in the Umm Shaif and Nasr concession and a 10% interest in the Lower Zakum concession. The concession entry fees are valued at about $1.175 billion, with PetroChina paying $575 million to enter the Umm Shaif and Nasr concession and $600 million to enter the Lower Zakum concession. Both concessions will be operated by ADNOC Offshore on behalf of all concession partners. Details of the deals   ADNOC Group Chief Executive Officer Ahmed Al Jaber said, “Total brings deep knowledge and understanding of  Abu Dhabi’s offshore oil and gas fields, as well as specialist expertise and technology that will help accelerate the development of the giant Umm Shai f gas cap. ADNOC has recently seen encouraging results from the first gas cap production pilot well at Umm Shaif, which will play an important role in delivering our 2030 smart growth strategy and a sustainable and economic gas supply.” The Umm Shaif and Nasr concession and the Lower Zakum concession have been created from the former ADMA offshore concession, which Total has been a partner in since 1953. It has been divided into three separate concession areas. In the Umm Shaif and Nasr concession, Total joins Italy’s Eni, which was recently awarded a 10% stake. Umm Shaif field’s Arab reservoir is characterized by a huge condensatesrich gas cap—one of the largest in the region. “Based on ADNOC’s development and initial piloting activities in the gas cap, the concession partners will further pursue the technical and economic evaluation of the development,” the company said. The gas cap overlays an oil rim which, in combination with Nasr, has a crude production capacity of 460,000 b/d.  ADNOC plans to process 500 MMscfd of gas from Umm Shaif’s gas cap to help meet Abu Dhabi’s growing demand for energy and reduce reliance on imported gas. The condensates, from the gas cap, will be refined to extract higher value products. In the Lower Zakum concession, Total joins an Indian consortium, led by ONGC Videsh, Japan’s INPEX, as well as Eni as stakeholders. ADNOC is finalizing opportunities, with potential partners, for the remaining 10% of the available 40% stake in the Lower Zakum concession, and for the remaining 10% stake in the Umm Shaif and Nasr concession. ADNOC retains a 60% majority share in both concessions. In February 2017, CNPC was awarded an 8% interest in Abu Dhabi’s onshore concession, operated by ADNOC Onshore. It also has a 40% stake in the Al Yasat concession with ADNOC. CNPC joins Eni SPA (10%) and Total (20%) as participants in the Umm Shaif and Nasr concession; and an ONGC  Videsh-led consortium (10%), Inpex Corp. (10%), Eni (5%) and Total (5%) as participants in the Lower Zakum concession. ADNOC retains 60% majority shares in both concessions.

Oil & Gas Journal | Apr. 2, 2018

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 Wide WTI-WCS spread cuts oil sands output Cenovus Energy Inc. is li miting production from its oil sands projects in Alberta, citing the suppression of bitumen values by transportation bottlenecks (OGJ Online, Feb. 21, 2018). “When Canadian heav y oil is selling at a wide discount to  West Texas Intermediate (WTI) due to transportation bottlenecks, we have significant capacity to store barrels in our oil sands reservoirs to be produced and sold at a later date when pipeline capacity improves and differentials narrow,” Cenovus Pres. and Chief Executive Officer Alex Pourbaix said in a press statement. Since February, he said, the company has reduced production from its Christina Lake and Foster Creek thermal projects while injecting steam at normal rates. Production capacities are 210,000 b/d at Christina Lake and 180,000 b/d at Foster Creek. The Cenovus statement projected first-quarter oil sands

production of 350,000-360,000 b/d. The statement said the strategy will affect monthly production rates but did not change the company’s projection for average oil sands output in 2018 of 364,000-382,000 b/d. Last month, the Alberta government said transportation problems have prevented the province from benefiting from the recent rise in global oil prices. The normal discount of Western Can adian Select (WCS) crude to WTI widened after a 2-week shutdown last November of TransCanada’s Keystone pipeline, which has operated below capacity rates since restar ting. The other major pipeline for export of oil sands production, the Enbridge Mainline system, is at capacity. Rail transport has responded slowly. Since November, the provincial government said, the  WCS-WTI different has doubled to $28/bbl. “Alberta heavy oil producers are currently forgoing an estimated $30-40 million/day in revenue as a result,” it said.

Court rejects NYSDEC’s appeal of FERC’s Valley Lateral ruling Nick Snow

Washington Editor

 A US federal appeals court denied the New York Department of Environmental Conservation’s (NYSDEC) appeal of the Federal Energy Regulatory Commis sion’s decision that NYSDEC waived authority to issue or deny a water-quality certification for the Mil lennium natural gas pipeline’s 7.8-mile  Valley Lateral when the state agency did not act w ithin the federal Clean Water Act’s Section 401 1-year timeframe (OGJ Online, Sept. 18, 2017). “We conclude that the department waived its authority to review Millennium’s request for a water-quality certification under the Clean Water Act by failing to act on that request within 1 year,” Circuit Judge Jose A. Carbanes said in a Mar. 12 decision in US Appeals Court for the Second Circuit in New York. “We also conclude that FERC does have jurisdiction over the pipeline. Accordingly, we deny the petition for review.” The decision effectively will allow construction of the project in Orange County, NY, to resume. Three organizations welcomed it. “This decision is great news for New York workers and consumers who have been harmed by attempts to stifle energy infrastructure modernization in the state,” API New York Executive Director Karen Moreau said in Albany. “Further, ad-

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ditional pipeline infrastructure will help New Yorkers guard against potential gas shortages.” Business Council of New York State Pres. Heather C. Briccetti said, “The decision shows that [NYSDEC] cannot impede the transport of interstate natural gas by refusing to act on a request for a certification.” In Houston, Consumer Energy Alliance Pres. David Holt said the ruling sent a clear message not only to New York regulators, but also state agencies across the country where officials often try to add unnecessary and redundant delays during permit application reviews. “Critical pipeline projects have been held up with permitting processes that are increasingly being abused in an effort to delay development. Unfortunately, low-income families, seniors, and households across the Northeast and New Engl and are left with the bill,” Holt said. “Those who rely on affordable energy have already endured their third major Nor’easter this year—and because of regulatory overreach and a lack of pipeline capacity—paid the highest price for natural gas in the industrialized world in January,” Holt said. “The region’s supply situation was so bad this winter that they imported Russian LNG when ample supplies of domestic energy were available and waiting for delivery.”

Oil & Gas Journal | Apr. 2, 2018

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KPC lets prefeasibility study for Kuwaiti refining capacity expansions Robert Brelsford Downstream Technology Editor

Kuwait Petroleum Corp. and its subsidiaries have let a contract to  Jacobs Engineering Group Inc., Dallas, to deliver a prefeasibility study to support downstream capacity expansions in Kuwait in support of KPC’s long-term strategic plans and directions up to 2040.  As part of the contract, which includes the option of proceeding to a detailed feasibility study, Jacobs will evaluate how domestic Kuwaiti refining capacity can be expanded in a cost-effective way that will enable the refineries to provide advantaged feedstocks for integrated petrochemical production, the service provider said. The studies will cover evaluation

KPC, through subsidiary KNPC, operates refineries that are undergoing modernization and expansion works as part of KNPC’s Clean Fuels Project. Photo from KNPC.

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and optimization of alternative process configurations using an integrated linear program model, various technical studies, licensor evaluation, cost estimation, financial modeling, and risk assessment and management, with a focus on increasing refining capacity and optimum petrochemical integration, Jacobs said.  Jacobs did not disclose further details regarding the contract or the specific projects to be included as part of the study. KPC, through its subsidiary Kuwait National Petroleum Co. (KNPC), operates the 466,000-b/d Mina Al-Ahmadi refinery about 28 miles south of Kuwait City on the Persian Gulf, and the 270,000-b/d Mina Abdullah refinery, both of which are undergoing modernization and expansion works to transform into an integrated 800,000-b/d merchant refining complex as part of KNPC’s Clean Fuels Project (CFP) under

Kuwait’s 2030 strategy, which aims to enhance growth in its refining manufacturing sectors as well as upgrade the refineries to produce clean-burning fuels conforming to Euro 5 st andards (OGJ Online, Feb. 14, 2018; Nov. 28, 2017). Through recently formed subsidiary Kuwait Integrated Petroleum Industries Co. (KIPIC), KPC also owns the grassroots 615,000-b/d Al-Zour integrated refining complex under construction as part of the CFP in southern Kuwait, the first unit of which is scheduled to be completed by May 2019, with pipelines for delivery of feedstock to the refinery to be ready by October 2019, according to a recent presentation from KPC (OGJ Online, Jan. 22, 2018). KPC most recently said it expects to start up the remainder of the CFP in May.

Sonatrach updates refining plans Robert Brelsford

consider buying a refinery outside of Algeria, negotiations for Downstream Technology Editor which are still under way. The proposed purchase comes as part of Sonatrach’s new State-owned Sonatrach is weighing the purchase of a refinstrategy of resource development, under which the company ery abroad to process Algerian-produced crude oil to furplans to process its own oil and gas production instead of sellther help reduce Algeria’s high costs for and reliance on iming it into the market, according to APS. ported petroleum products, Abdelmoumen Ould Kaddour,  Alongside the potential refinery purchase, Ould Kaddour Sonatrach’s chief executive officer, told Algeria Press Service also disclosed that Sonatrach expects to complete the refur(APS). bishment and revamping of the operator’s 2.7 million-tonne/   Without disclosing specific details of the potential transacyear refinery in Algiers before yearend in a project that prevition, Ould Kaddour said Sonatrach has launched a project to ously intended to increase crude processing capacity at the site to 3.6 million tpy (OGJ Online,  June 5, 2017; Dec. 22, 2010; Sept. 24, 2010).  A contract launching Sontrach’s previously announced construction of a grassroots 5 million-tpy refinery at Hassi Messaoud is scheduled to be signed within the next 2-3 months, while relevant provisions for an earlier announced 5 milliontpy refinery at Tiaret—which will cost between $2-5 billion—has yet to be launched (OGJ Online, Mar. 8, 2016). Ould Kaddour did not address plans for a third previously announced 5 million-tpy refinery the company previously said it would build in Biskra. In addition to the three proposed Sonatrach is weighing the purchase of a refinery abroad to process Algerian-produced grassroots refineries at Hassi Messcrude oil. Photo from S onatrach. aoud, Tiaret, and Biskra, Sonatrach’s program to help meet energy de-

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Oil & Gas Journal | Apr. 2, 2018

mand of Algeria’s domestic market by 2040 also includes construction of a 4.6-million tpy gas oil hydrocracker and a 4-million tpy catalytic reformer to enable production of Euro 5-quality diesel and gasoline at its existing 16.5 million-tpy refinery in Skikda, both of which most recently were scheduled for completion in 2019 (OGJ Online, Dec. 20, 2016).

Chevron Phillips Chemical commissions USGC ethane cracker Robert Brelsford

BPCL lets contract for Kochi refinery Robert Brelsford

Downstream Technology Editor

India’s state-owned Bharat Petroleum Corp. Ltd. (BPCL) has let a contract to Petrofac Ltd. to provide engineering, procurement, and construction services for a project to increase production of Bharat Stage 6-qual ity fuels (equivalent to Euro 6) at its refinery near Kochi, at Ambalamugal, Ernakulam district, in the Indian state of Kerala. Petrofac’s scope of work under the 27-month, lump-sum contract includes EPC as well as precommissioning and assistance-with-commissioning services for a new block of motor spirit (MS, gasoline) refining units at Kochi, the service provider said.  While it did not reveal the number or capacities of MS units proposed under the contract, Petrofac did confirm a contract value of about $135 million.  Announcement of the BS 6-quality fuels project follows BPCL’s earlier completion and commissioning of all units under the Kochi refinery’s integrated expansion project (IREP), which intended to expand crude processing capacity at the refinery to 15.5 million tpy from 9.5 million tpy with the addition of a crude distillation unit, FCCUs, and a delayed coker to enable the production of fuels that meet Europe’s latest emissions standards (OGJ Online, July 25, 2017; July 11, 2016).  While BPCL confirmed startup of all units under Kochi’s IREP in its latest sustainable development report to interested parties, the operator has yet to verify the refinery has fully reached its new processing capacity of 15.5 million tpy.  According to the latest data available from BPCL, the Kochi refinery reached its highest-ever throughput of 11.787 million tpy in fiscal year 2016-17, while data from India’s Ministry of Petroleum and Natural Gas for January showed the refinery’s prorated installed processing capacity for fiscal year 2017-18 at 12.995 million tpy. BPCL also has undertaken its propylene derivates petrochemical project at Kochi to diversify the refinery’s output of niche petrochemicals, which will be produced from polymergrade propylene supplies resulting from increased crude processing at the site (OGJ Online, Dec. 9, 2014). The 45.88 billion-rupee PDPP currently is scheduled to be completed in May.

Oil & Gas Journal | Apr. 2, 2018

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Downstream Technology Editor

Chevron Phillips Chemical Co. LP (CPCC), a joint venture of Chevron Corp. and Phillips 66, has completed startup of a 1.5 million-tonne/year ethane cracker at the combine’s Cedar Bayou facility at Baytown, Tex., finalizing the second phase of its previously announced $6-billion US Gulf Coast petrochemical project (OGJ Online, Apr. 8. 2014). CPCC has successfully introduced feedstock into and started operation of the ethane cracker, the operator said. Official commissioning of the cracker follows CPCC’s earlier announcement in late 2017 that it had reached mechanical completion of the cracker and started a series of rigorous commissioning activities, system checks, and final certifications to ensure the unit’s safe and reliable start-

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CPCC has completed startup of a 1.5 million-tpy ethane cracker at its Cedar Bayou facility at Baytown, Tex. Photo from CPCC.

up (OGJ Online, Dec. 20, 2017). CPCC previously told OGJ that it expects the cracker to achieve full-production rates sometime during 2018. The unit will produce at least 1.5 million tpy of ethylene to support CPCC’s ethylene business and as feedstock for the operator’s two nearby 500,000-tpy polyethylene units at Old Ocean, Tex., which began commercial operation in November 2017 (OGJ Online, Sept. 20, 2017). First announced in March 2011, the USGC petrochemical project comes as part of CPCC’s strategy to help meet robust global demand for ethylene and ethylene derivatives by taking advantage of abundant shale gas feedstock produced from ongoing development of US shale resources.

Completion of both phases of the USGC petrochemical project marks a new era of growth for CPCC, according to Mark Lashier, CPCC’s president and chief executive officer. “With global demand for ethylene and polyethylene poised for sustained long-term growth, the [USGC] petrochemicals project will allow [CPCC] to deliver high-quality products to our customers across the country and around the globe,” Lashier said, referring to project as the most transformational undertaking in the company’s history. “Our company and our growing employee base, the communities we call home, and the entire [USGC] region’s economy will benefit for decades to come as our project comes to life,” Lashier added.

Argentina moving to develop tight shale oil and gas, speakers say Nick Snow Washington Editor

 With the largest shale gas resources and tight oil deposits second only to those of the US in the Western Hemisphere,

32

 Argentina is try ing to attract more foreign investments by continuing to improve government policies, speakers said during a Mar. 27 discussion at the Inter-American Dialogue. But the South American nation faces substantive cha llenges as it tries to make operating conditions there more transpar-

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ent and predictable, they added. “Our general economy has grown for seven consecutive quarters, and poverty is going down,” said Fernando Oris de Rosa, Argentina’s ambassador to the US. “Foreign direct investment grew to $10.7 billion in 2017, and we’d like more. Fiscal and tax reforms have been passed, and discussions with organized labor are planned. Ultimately, we want to move from populism to transparent, realistic policies which become permanent.” More reforms need to move from transitions to permanence, said Omar Gutierrez, governor of Neuquen province where most of the tight oil and gas supplies are in the Vaca Muerta formation. “We eliminated gas and oil retentions and installed a pricing regime that has encouraged development. We also have done away with consumption subsidies and allowed prices to rise. With drilli ng costs half of what they were, unconventional oil and gas now has a greater share of our province’s total production, and 20-22% of Argentina’s,” he said.  Argentina has become the only Latin American country on a par with the US due to the alignment of its government at several levels with all the stakeholders, said Paolo Carvajal, a consulting member at international management services firm Arthur D. Little’s Houston office. “Today, we can talk about a 50% gain in efficiency per square foot there. Multinationals like ExxonMobil, Chevron, and Shell are there along with YPF, the national oil company,” she said. “We expect that in 2025, Argentina’s oil and gas production will have tripled. But it will need to overcome challenges, including infrastructure, investment climate stability, unions, developing qualified human resources a nd an oil services sector, and smoothly adopting natural gas market prices,” Carvajal said.

From pilots to development  Gutierrez noted that of Argentina’s 26 tight shale oil and gas concessions, three are being developed now and three to four more are expected to get under way soon. “We have a plan all the actors are monitoring and are involved in. Tonight, I will be in Houston for an event where I expect to discuss this in more detail. We’ve seen capital from many sources and expect to see more projects move from the pilot to the development phase,” he noted. “We want to make our energy prices competitive so the rest of the country’s economy can follow,” said Gutierrez. “We also have begun to export gas to Chile, with generally good results. Vaca Muerta will give us an efficient energy hub which will drive our national economy.” Carvajal said, “Argentina has been fortunate because it has been able to develop unconventional resources without as much local and labor opposition as in other Latin American countries. But local issues will need to be addressed. This alignment has let Argentina lead the unconventional resources charge in Latin America. But investments will be

34

needed in other sectors as well.” Full stakeholder participation is essential, Gutierrez said. “We have a comprehensive plan with dynamic properties. Companies also have shared what they have learned. This has led to a constructive dialogue where all the actors are contributing,” he said. Carvajal said Argentina President Mauricio Marci’s government has enacted several good reforms, but oil and gas multinationals have long memories and face equally long waits before prospects being producing. “We’re talking about production that would begin 35 years in the future, so the situation could change,” she suggested. Gutierrez thinks that this looks increasingly less likely. “The government is one of four main actors. It is putting many ideas forward, but everyone else is participating too,” he said. “We’ve done a lot in 3 years. Vaca Muerta has shown what can be done. There is not a single negative result in the pilot programs so the companies will continue to invest. We also are about to announce plans for a huge new gas pipeline so companies w ill be able to move what t hey produce to their customers.”

ADNOC lets contracts for Ruwais refinery Robert Brelsford

Downstream Technology Editor

 Abu Dhabi National Oil Co. (ADNOC) subsidiary ADNOC Refining (formerly Takreer) has let two contracts to Samsung Engineering Co. Ltd. of South Korea to provide engineering, procurement, and construction services for separate projects on its 80,000-b/d Ruwais refining complex in the UAE. The combined value of the contracts—both signed on Mar. 26—exceeds $3.5 billion, ADNOC said in a release. Under the first contract, Samsung Engineering will deliver EPC services for ADNOC’s previously announced $3.1-billion project to increase crude processing flexibility and improve margins at the Ruwais refinery’s 417,000-b/d  West plant to enable the site to process up to 420,000 b/d of Upper Zakum crude or similar medium-sour crude types from the market in lieu of fellow UAE-produced, light, sweet Murban crude (OGJ Online, Feb. 8, 2018). Increased crude-processing flexibility at the refinery, in turn, will free higher-priced Murban crude for export sales to global oil markets to help UAE garner greater returns from its domestically produced oil resources, A DNOC said.  As part of the second contract, Sam sung Engineering will provide EPC services for a $473-million waste-heat recovery project (WHRP) at the refinery, which—via an upgrade to four giant gas turbines with closed-cycle power generation technology—will generate an additional 230 Mw of electr ic-

Oil & Gas Journal | Apr. 2, 2018

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ADNOC Refining let contracts for EPC services for projects on its 80,000-b/d Ruwais complex in the UAE. Photo from ADNOC.

ity for sale and 62,400 cu m/day of water by capturing refinery waste heat cur rently vented into the atmosphere. The WHRP also will play a large role in reducing the environmental impact of the Ruwais complex’s refining and power operations, as well as help improve overall energy efficiency at the site, ADNOC said.  ADNOC earlier announced the award of a contract to a  joint venture of CB&I, Houston, and Samsung Engineering for the crude flexibility project (CFP), under which CB&I said it would provide engineering and procurement serv ices for two atmospheric residue desulfurization units equipped with technology licensed by CB&I-Chevron Corp. joint venture Chevron Lummus Global, as well as engineering, procurement, fabrication, and construction of 14 flat-bottom tanks and 10 process heaters for the project (OGJ Online, Feb. 9, 2018).  ADNOC’s multibillion-dollar investment in crude-quality arbitrage and waste-heat recovery at Ruwais follows the operator’s late-2017 announcement that it will boost production capacity of supergiant Upper Zakum offshore field by 350,000 b/d to 1 million b/d and it broader plans to grow its refining capability and e xpand petrochemical production three-fold to 14.4 million tpy by 2025 (OGJ Online, Nov. 15, 2017). Other planned projects under the downstream investment program include construction of a new mixed-feed naphtha cracker and investments in new refinery capacity,  ADNOC said without disclosing further details.  ADNOC said it expects to complete the CFP by yearend 2022, while the WHRP is scheduled for completion by yearend 2023.

Oil & Gas Journal | Apr. 2, 2018

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35

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Study questions stratigraphic traps’ predrill risks Edwige Zanella Jamie Collard Westwood Global Energy Group London

tic reservoirs from 2008 to 2017 to investigate the higher risk perception and examine industry performance in its search for stratigraphic traps.

Stratigraphic trap formation  Stratigraphic traps made headlines in 2017 with the discovery of an estimated 1 billion boe of recoverable resources in the Stabroek block offshore Guyana within the Payara, Snoek, and Turbot discoveries. The Turbot-1 discovery well was an EXPLORATION & ExxonMobil-operated joint venture’s ( JV) DEVELOPMENT fifth exploration test of the Liza play following the giant 2015 frontier Liza-1 discovery. Liza-1 encountered more than 90 m of net pay in Late Cretaceous deepwater turbidite sandstones in a stratigraphic trap. The JV had already discovered almost 2 billion boe of recoverable reSPECIAL sources at Liza where a final investment REPORT decision (FID) has been taken on the first phase of field development. On the other side of the Atlantic, however, recent stratigraphic trap exploration has been less fruitful, with unsuccessful wells in Senegal, Cote D’Ivoire, and Guinea chasing the same play concept of Late Cretaceous turbidite sandstones. Despite their large resource potential (Fig. 1) and a low average finding cost (drilling cost only) of $0.90/boe, only 22% of global exploration wells targeted stratigraphic traps in conventional plays during 2017. This figure is 19% for the entire period from 2008-17, with little variation year-on-year.

Predrill risks  Stratigraphic traps are perceived to have h igher predrill geological risk than other structural trap types like anticlinal structures and tilted fault blocks. Some companies even add an extra geological risk factor to stratigraphic traps by default.  Westwood Global Energy Group has looked at 270 completed exploration wells targeting stratigraphic traps in cla sThis article is extracted from Westwood Energy’s “Are stratigraphic traps more risky,” published in October 2017.

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The stratigraphic traps considered in the study are formed by reservoir sand pinch-outs encased in sealing claystones or mudstones. Traps are often created around the time the sands are deposited. Combination traps in clastic reservoirs involve a combination of sand pinch-out with folding, faulting, or both. This usually requires structural deformation post-deposition of the reservoir sands. There is a wide spectrum between the rarer pure stratigraphic trap and a combination trap, and sometimes little difference between the two. For this study, a trap is designated stratigraphic when the stratigraphic component of the trap is the most important for the accumulation of hydrocarbons. Carbonate reef build-ups can also form significant stratigraphic traps but are not included in this analysis. Only six basins in the world have had more than 10 stratigraphic traps drilled since 2008. Almost 25% of the exploration wells targeting stratigraphic traps have been drilled in the North Sea basin, followed by the Africa Equatorial Margin including Sierra Leone-Liberia, Ivorian and Tano basins, the Ruvuma basin off Mozambique and Tanzania, the Carnarvon basin in Australia, and the Sergipe-Alagoas basin offshore Brazil. Fewer than 10 stratigraphic traps have been tested in the Suriname-Guyana Basin to date, but the play is emerging rapidly. Stratigraphic traps in clastic sediments can be formed in all depositional environments where processes result in lateral lithology changes from sands to nonreservoir facies. They can also occur in different tectonic settings. The major focus of stratigraphic trap exploration in the 2008-17 period has been the Cretaceous and Tertiary deepwater turbidite complexes in passive margin settings.

Discoveries  Most hydrocarbons discovered in stratigraphic traps have been in Late Cretaceous and Oligocene reservoirs (Fig. 2). The Late Cretaceous plays are dominated by oil, with a large proportion of estimated discovered resources (>3 billion boe) in the Suriname-Guyana basin. An estimated 1.5 billion boe of recoverable oil and gas have been discovered in Late Cretaceous stratigraphic traps in the Sergipe-Alagoas

Oil & Gas Journal | Apr. 2, 2018

TRAP TYPE DISCOVERY DISTRIBUTION, 2008-17 Resource range

P100

FIG. 1a

Stratigraphic Combination Four-way dip Faulted

P90    %  ,   y    t    i    l    i    b   a    b   o   r   p   e   c   n   e    d   e   e   c   x    E

basin. An estimated 37 tcf of gas have been discovered in Oligocene stratigraphic traps, dominated by the gas discoveries of the Ruvuma basin. More than 15 billion boe of oil and gas resources have been found in stratigraphic traps since 2008. The range of discovery size is wide, with a mean of almost 440 MMboe (Fig. 1). This range is comparable to combination traps, which have a mean resource of 500 MMboe and finding cost of $0.60/boe.

FIG. 1a

P80 P70 P60 P50 P40 P30 P20

Faulted traps

P10

0 0

0.1

1

10 100 Resources, MMboe

1,000

10,000

Source: WGE Wildcat Database

Resource distribution, MMboe Trap type

FIG. 1b

P90

P50

Mean

P10

P1

Discoveries

Stratigraphic

3

46

438

700

6,430

77

Combination

3

44

500

740

7,380

88

Four-way dip

1

13

210

270

3,100

108

Faulted

2

13

44

100

500

321

Faulted traps represent 50% of all exploration prospects drilled during the study period and have a narrow resource range with a mean resource of 44 MMboe, 10 times smaller than stratigraphic traps. The faulted traps finding cost of $2.20/  boe is more than double the finding cost of stratigraphic traps. Resource distributions reflect that most large fault blocks have already been drilled and that the larger remaining accumulations are stratigraphic or have a stratigraphic component in their trapping mechanism.

STRATIGRAPHIC EXPLORATION RESULTS

FIG. 2

Wells, commercial discoveries

Resources, MMboe

FIG. 2a

Pleistocene

Pleistocene

Pliocene

Pliocene

Miocene

Miocene

Oligocene

Oligocene

Eocene

Eocene

Paleocene

Paleocene

Upper Cretaceous

Upper Cretaceous

Lower Cretaceous

Lower Cretaceous

Upper Jurassic

Upper Jurassic

Middle Jurassic

Middle Jurassic

Low Jurassic

Low Jurassic

Triassic

Triassic

Permian

Permian 0

20 Total

40

60 Commercial

80

0

2,000

FIG. 2b

4,000 Oil

6,000

8,000

Gas

Source: Westwood Energy Wildcat Database.

Oil & Gas Journal | Apr. 2, 2018

TECHNOLOGY

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TECHNOLOGY

AFRICA DEEPWATER EXPLORATION, 2008-17 Fatala

SIERRA LEONE

Sabu  Z  e a F  G u i n

Savannah

Djembe

Mercury

 F Z  o n e  r a L e  S i e r

Venus

FIG. 3

S  i   e 

r  a  Jupiter r   L e  o n   Montserrado e -  L i   b e  Mesurado Goshtern

Atlantic Ocean 

Iroko Bee Eater 0

Miles

186

0

Km

300

TOGO BENIN

NIGERIA

LIBERIA Carmine Deep

Timbo

r  i  a  Narina M   a r   i  n   Apalis  Z  l  ’s F  P a u  S t.

Houmelan

S.G. Lahou

Nighthawk

Kosrou Saumon

Azobe TEN Jubilee Buffalo Sankofa

Saphir Aigle Ayame

 n  r  i a   I  v o   i n   b a s

Success rates   Westwood’s study looked at both the technical success rate (TSR), which is the number of hydrocarbon discoveries divided by the number of exploration wells, and the commercial success rate (CSR), which considers the number of commercial discoveries only. Globally, stratigraphic traps have an average TSR of 49% over the 2008-17 period, comparable to other trap types. The average CSR of stratigraphic traps is only 26%, 10 percentage points lower than the CSR of faulted traps. To understand this difference, the performance of stratigraphic traps needs to be reviewed on a basin and play analogue basis to remove other play element risks that could have a greater impact than the trap type its elf. The Cretaceous turbidite play along the Africa Transform Margin covers basins from Sierra Leone to Benin (Fig. 3).  While stratig raphic traps along the margin have had a high TSR of 61%, their CSR is only 11%. Only the Tano basin has delivered commercial volumes so far, with a TSR of 69% and a CSR of 31%.  After the discovery of the Jubilee field in 2007, offshore Ghana, the search for Jubilee look-alikes started, spreading westwards along the Africa Transform Margin. Exploration along this margin focused on Late Cretaceous turbidite slope channel complexes and basin floor fans detached from the up-dip canyon feeder systems. Sixty-eight post-Jubilee exploration wells have been drilled on the margin, yielding only two development projects, the TEN (Tweneboa, Enyenra, and Ntomme discoveries) cluster development, which ca me on stream in 2016, and the Sankofa (Sankofa and Gye Nyame discoveries) project that achieved first oil in 2017.

Failure analysis  Failure analyses of dry wells that have sufficient published information indicate that the main causes of failure were

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GHANA

COTE D’IVOIRE

Morue

 

Rossignol Colibri Pelican

Tana basin

  Z   F   h e  c  n  m a   R o

Starfish Dry hole Noncommercial discovery Commercial discovery Oil Gas 2016-17 completed wells FZ Fishery zone

lack of sufficient hydrocarbon charge or lack of effective trap and seal. Failure causes for noncommercial discoveries are different than for dry holes because in these cases hydrocarbons are present. The primary causes of commercial failure are reservoir quality, which is either too thin or displays low porosity and permeability, and trap areal extent, meaning the trap is sma ller than predicted. Both result in the gross rock volume of the accumulation being on the low side of predrill expect ation.  Another cause of commercial failure in some cases is charge limitation and timing of hydrocarbons migration. These cases a re probably the hardest to diagnose w ith a single exploration well but can result in underfilled traps and, when recognized, impact t he understanding of the play.

Understanding failure, success  The high CSR of the Tano basin lies in its structural configuration, defined by the Romanche fracture zone to the South and the St. Paul fracture zone to the North. The Jubilee field  JV recognized that the ramp-like geometry of the eastern Tano basin allowed connected turbidite sand systems to pond and that local structure of the South Tano High creates a hydrocarbon migration focal point.1 The Ivorian and Sierra Leone-Liberia margin has a more abrupt morphology, which creates isolated turbidite systems and a lack of well-defined hydrocarbon migration focal points. Sediment provenance also contributes to differences in CSRs. Tano basin sediments are derived from a more granitic hinterland, delivering cleaner sands, whereas the sediment sources in the Sierra Leone and Liberia areas are dominated by metamorphic rocks, resulting in a lower quality reservoir. In many cases, the stratigraphic nature of the traps has taken the blame, when other causes are actually responsible for low CSRs and the reduced exploration potential of the whole margin. In areas where turbidite systems can be connected and hydrocarbon migration focal points exist, there

Oil & Gas Journal | Apr. 2, 2018

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is a greater chance of commercial success. The study also investigated the low commercial success rates of stratigraphic traps in the mature North Sea (22% CSR) and Carnarvon basin (8% CSR) since 2008. Post-well failure analysis conducted by the UK regulator in 2015 concluded that frequent failure of stratigraphic trap tests was due to an over-dependence on geophysical attributes, such as amplitude anomalies or AVO.2  This dependence led to wells being dr illed on poorly defined prospects and to overestimated predrill chances of success. In the Carnarvon basin, only 14 of 115 recorded exploration wells have targeted stratigraphic traps. Although a limited number, all but one of these prospects was reported by companies to be well-defined by s eismic attributes, yielding a single commercial discovery. In both basins, t he failure of stratigraphic traps is more related to an over-reliance on geophysical tools than the nature of the trapping mechanism. Stratigraphic traps are not inherently more risky than other trap types. The key is for explorers to recognize whether they have the r ight tools and processes to ex plore effectively for commercial discoveries. Making th is determination calls for a sound geological model integrating the trap element into the entire petroleum system analysis, reliable geophysical calibration, and the effective use of an alogue data.

References  1. Tullow Oil, “Capital Markets Day Present ation,” Oct. 1, 2008. 2. Mathieu, C., “Moray Firth – Central Nor th Sea Post Well analysis,” UK Oil and Gas Authority, Dec. 8, 2015, pp. 208. The Authors

Edwige Zanella (ezanella@westwoo denergy.com) is a senior associate at Westwood Global Energy Group, London. She has also served as geologist and exploration manager at Lasmo Plc and Nexen Petroleum UK Ltd. She holds an engineering degree in petroleum geoscience from IFP School, Rueil-Malmaison, France. She is a member of the American Association of Petroleum Geologists (AAPG) and the Petroleum Exploration Society of Great Britain (PESGB). Jamie Collard (jcollard@westwoo denergy.com) is an analyst at Westwood Global Energy Group. He holds a BS in geology from the University of Bristol and an MS in petroleum geo science from the University of Manchester. He is a member o f AAPG and PESGB.

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South Africa oil and gas law could accelerate exploration in 2018-19 Tayvis Dunnahoe Exploration Editor

 With active exploration offshore South es began drilling in 2004.  Africa later in 2018, the administration Offshore activity has remained limited of newly elected President Cyril Ramasince mid-2014 in the wake of lower oil phosa’s commitment to finalizing its oil prices and political uncertainty in South and gas law could encourage more foreign  Africa’s resource development ministry. SPECIAL EXPLORATION & investment. South Africa’s newly-elected Lower operating costs and rising oil pricDEVELOPMENT REPORT President Cyril Ramaphosa has moved es in the last year, however, have drawn swiftly to reshuffle his cabinet following some companies into the region. his Feb. 15 inauguration. His appoint With the potential for more certain ment of Gwede Mantashe to Mineral Resource Minister is oil and gas rules slated for late 2018 and several drill-ready expected to accelerate passage of South Africa’s Minerals and prospects, South Africa’s offshore region may reveal several Petroleum Resources Development Act (MPRDA) Amendworld class discoveries. ment bill. The bill has been before parliament for 5 years, and President RaSOUTH AFRICA BLOCKS maphosa has called for its finalization. FIG. 1 South Africa’s mining industry has ANGOLA languished. Heavy, often contentious, regulations govern exploration permits, mining authorizations, tax, royMowe Bay alties, and other industry related functions. Many of the country’s laws have BOTSWANA Windhoek been mired in disputes and legal challenges that tend to deter, rather than Walvis Bay Block Gaborone attract, foreign investment. PEL 37 NAMIBIA Once the MPRDA Amendment bill is passed, the increased certainty South  Johannesburg in exploration and development proLuderitz Atlantic  grams should encourage more foreign Ocean  Bloemfontein investment. SOUTH AFRICA

Historical operations  The oil and gas industry drilled about 300 wells offshore South Africa from the late 1980s to the early 1990s. During apartheid and after transitioning to South Africa’s current form of government, offshore oil and gas exploration had fewer incentives. Little activity occurred through the late 1990s until Pioneer Natural Resourc-

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Indian  Ocean 

South  Atlantic  Ocean 

NAMIBIA

0 0

Miles Km

Block 2B

Cape Town

Mossel Bay

LESOTHO Port Elizabeth

SOUTH AFRICA

200 322

Block 11B/12B

Oil & Gas Journal | Apr. 2, 2018

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Brulpadda prospect 

BLOCK 11B/12B

FIG. 2

Total SA recently sold 25% interest in exploration Block 11B/12B offshore Total block SOUTH AFRICA Oil field South Africa to Qatar Petroleum (OGJ Gas field Online, Feb. 5, 2018). The transacGTL plant, 36,000 b/d Prospect Plettenberg Bay tion remains subject to regulatory apPipeline proval, but the partnership on Block Refinery Mossel Bay 11B/12B (Fig. 1) is preparing for the high-potential Brulpadda-1AX well Block 11B/12B, 18,734 sq km scheduled to be drilled on t he block at Petro SA the end of 2018. Block 11B/12B covers EM gas field 19,000 sq km in 200-1,800 m of water FA gas field FO gas in the Outeniqua basin about 175 km Total SA discovery Oil mature kitchen offshore southern South Africa (Fig. 2). Sable oil field Total attempted to drill Brulpadda1AX in Winter 2014, but the well was suspended after harsh conditions exPetro SA Paddavissie fairway ceeded rig specifications. Low riser angle restrictions, poor sea-state compensation systems, and insufficient Oryx, Oribi oil fields power to dynamically position the rig SOUTH AFRICA forced the company to plug and abandon the well. 2D seismic, Five giant Cape Town 1 km × 2 km grid prospects 62 The Brulpadda-1AX re-entry is ex0 Miles pected to commence in December and Km 100 0 follows Total’s extensive metocean study to monitor current, wind, and waves in the area to better understand conditions. The operator has contracted Odfjell Drilling “The team is also very fa miliar with the Jubilee field in GhaCo.’s Deepsea Stavanger, a sixth-generation semisubmersible na and the La Ceiba and Okume fields in Equatorial Guinea, rig capable of drilling the Brulpadda well during the Cape all of which have some common elements to Block 11B/12B summer. in South Africa and to Petroleum Exploration License (PEL)  Africa Energy Corp. CEO Garrett Soden described Block 37 Namibian geology [submarine fans],” Soden said. 11B/12B as a “unique exploration situation” where five am The Brulpadda-1AX well is highly ranked in Total’s globplitude supported closures all conform to structural closure. al portfolio. Infrastructure is not a concern as there is exThe Brulpadda well will test the first of these. isting oil and gas production next to Block 11B/12B. The Predicted volumes are more than 500 MMbbl and the Mossel Bay gas-to-liquids facility operates at a third of its complex could exceed 2 billion bbl of prospective resources. capacity with a connecting pipeline about 70 km away. The  Africa Energy owns 49% of Main Street, which holds a 10% Cape Town oil refinery is also nearby. Drilling techniques stake in Block 11B/12B (subject to Government approval). and procedures are tested and proven and South Africa’s Total maintains 45% operating interest with CNR Internageological environments are well known. Brulpadda could tional holding the remaining 20%. be the start of a world class development offshore South AfThe Brulpadda prospect is part of the Paddavissie turbirica, much like Jubilee was for Ghana. dite play that covers more than 2,000 sq km and is a similar play to the much smaller Oryx and Sable complexes to Block 2B  the northwest in the adjacent Bredasdorp basin (Fig. 3). On South Africa’s western coast, Africa Energy is advancThese complexes contain stratigraphically and structurally ing a farmout with plans to drill an exploration well in 2019 trapped oil and gas in reservoir quality channel sandstones on offshore Block 2B (Fig. 1). The company was granted a that form feeders to the outboard Paddavissie fan systems. 2-year renewal of its exploration license by South Africa’s Source rocks in the fetch area comprise both mid-Aptian Petroleum Agency in February (OGJ Online, Feb. 27, 2018). and Hauterivian shales that entered maturity in early TertiaBlock 2B covers 3,604 sq km in 50-200 m of water. The ry and are presently within t he main stage of oil generation. block contains the A-J1 oil discovery drilled by the former Africa Energy’s current team has, with various employSouth Africa state-owned Soekor in 1988. The A-J1 well ers, been exploring Africa continuously for the last 30 years. tested light oil from a Lower Cretaceous sandstone section.

Oil & Gas Journal | Apr. 2, 2018

TECHNOLOGY

41

TECHNOLOGY

BRULPADDA PROSPECT

FIG. 3

0 0

Miles Km

12.4 20

11B/12B

A Brulpadda Luiperd

A’

Prospects Deep prospects Leads

trend in the region is like the Ea st African Rift where major oil accumulations have recently been discovered in Kenya’s South Lokichar basin and Uganda’s Albert rift. Soden told OGJ that six prospects have been identified on Block 2B, containing an estimated 400 million bbl of prospective resources. The southern and northern graben combined contain a total of more than 800 million bbl, most of which is in 150 m of water only 25 km offshore. The company plans to farm out 50% or more of the block on an estimated well cost of less than $20 million. “The 2019 drilling opportunity will occur 9-12 months after the farmout is complete,” Soden said.  Africa Energy currently holds 90% participating and operating interests in Block 2B. Crown Energy AB holds the remaining 10% through a subsidiary company. Namibia 

The A-J graben is a rift basin related to the Atlantic opening during the Early Cretaceous. In addition to the A-J southern graben, Block 2B also includes prospective acreage in the northern graben. According to Africa Energy, the greater rift

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Tullow Oil will drill on the Cormorant prospect in the Walvis basin offshore Namibia in September 2018. PEL 37 covers 17,295 sq km of the northern Namibian offshore region about 420 km south of the Angolan-Namibian border (Fig. 1). PEL37 water depths range from 400-1,500 m. The Cormorant and other prospects including Albatross, Seagull, and Gannet, lie in 400-600 m of water. HRT Participacoes em Petroleo SA, Rio de Janeiro, recovered noncommercial amounts of oil in its Wingat-1 well on Block 2212 in the Walvis basin in 2013 (OGJ Online, May 22, 2013). Block 2212 is directly south of PEL 37. The Murombe-1 well, drilled in the same license as Wingat-1, intersected a mature oil-prone source in the Aptian sequence. Tullow has acquired 3,440 sq km of 3D seismic in PEL 37 and has delineated several prospects consisting of Lower Cretaceous submarine fans that are stratigraphically trapped. During the 2013 seismic campaign, an additional 1,000 km of 2D seismic data were acquired in the southern part of PEL 37, indicating that the Lower Cretaceous fan play extends southwards and could be further explored if warranted. Recent drilling in the Namibian offshore has proven the presence of an Aptian Type II source rock with >3% total organic carbon as intersected in the Murombe-1 and Wingat-1 wells in the Walvis basin. The company and its partners plan to test this play in September. Further de-risking could have follow on potential of up to 1.5 billion bbl of oil.

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Basin-centered gas play developed in western Turkey limkoy and Kesan formations. In December, the company completed four production tests from eight frac Tayvis Dunnahoe stages in the Kesan formation, yielding a 24-hr aggreExploration Editor gate test rate of 2.9 MMcfd. Canadian Valeura Energy Inc. and partner Statoil  Valeura Energy has participated in numerous  ASA are planning a three-well delineation drilling drilling programs throughout the southern Thrace EXPLORATION & and testing program commencing third-quarter basin since 2013 and play types have ranged from DEVELOPMENT 2018 on the Banarli and West Thrace licenses in conventional shallow gas exploration prospects in northwest Turkey’s Thrace basin, west of Istanbul the overlying Danismen and Osmancik formations and extending to the borders of Greece and Bulto the tighter gas prospects in the Mezardere and garia (Fig. 1). underlying Teslimkoy and Kesan formations (OGJ Online, In the meantime, Valeura is tying the Yamalik-1 discovMar. 22, 2016). The company’s basin-centered gas concept ery on the Barnarli license in to its gas production network is targeting the pervasive overpressured unconventional gas for further testing and long-term production and sales. Deresources in the synclinal parts of the Thrace basin. sign work is under way for the production facilities and gathering pipeline at an anticipated cost of $3 million. First sales Basin-centered gas play  from Yamalik-1 are targeted for second-quarter 2018.  Valeura identified potential for a basin-centered gas accumu Yamalik-1 was drilled to 4,196 m and hydraulically fraclation (BCGA) play in Thrace basin through drilling results tured and production tested in fourth-quarter 2017. The well and regional geological modelling from 2011 to 2013. The discovered a 1,300-m natural gas and condensate column in company then captured rights to a majority of the Thrace overpressured reservoirs below 2,900 m in the Tertiary TesBCGA fairway through 2016.  Yamalik-1 was the first deep exploration well in the project, and was drilled under a farm-in agreement THRACE BASIN PROSPECT FIG. 1 giving Statoil 50% interest in formaBlack Sea  BULGARIA tions deeper than 2,500 m within Statoil partnered blocks Other licenses the Banarli and West Thrace licens  Area Discovery RUSSIA shown es. Statoil invested $69 million in the project, according to Valeura’s most Yamalik-1 recent investor presentation. Valeura TURKEY holds 50% in the deep formations in the Banarli license and 31.5% in the deep formations in the West Thrace. GREECE Istanbul Pinnacle Turkey Inc. holds the remainBanarli ing 18.5% interest in West Thrace. West Thrace Sea of Marmara  BCGA plays are among the more economically important unconvenMediterranean Sea  0 Miles 31 tional gas systems in the world. They 0 Km 50 are made made up of pervasive, basinTURKEY wide gas accumulations trapped in low

44

Oil & Gas Journal | Apr. 2, 2018

TECHNOLOGY

TECHNOLOGY

THRACE BASIN CROSS SECTION Tekirdag fields

S

FIG. 2

Guney Osmanli-1

Yayli-1

Yamalik-1

Ergene-1

Misinili-1 N

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000

0

Pressure, psi

500

Normal pressure

Hydrostatic gas fields

1,000

1,500

  m  ,    h    t   p   e    D

Transition pressure

2,000

0.8 psi/ft

2,500

Over pressure

3,000

3,500

4,000

Osmancik Mezardere Teslimkoy

Water = 0.433 psi/ft

Overpressured zone of interest

2,500 m 3,000 m

Kesan

4,000 m Yamalik-1 5,000 m

permeability rock. In the US alone, basin-centered gas accumulations provide 15% of the country’s annual production, equal to 4 tcf/year.  Valeura’s Thrace basin play fairway is defined by the onset of overpressures and a hydrocarbon generation window. To date, eight deep wells on the fringe of Thrace basin have displayed high overpressures below 2,500 m at 0.68-0.77 psi/ft. The Yamalik-1 measured 0.80-0.84 psi/ft at 4,100 m depth. These wells also contain increased mud gas and interpreted gas saturation in the reservoir. All tested wells have recovered gas to surface. The play area’s pressure seal covers 400,000 acres. The depth contour through Yamalik-1 at 3,100 m extends across 175,000 gross acres. The Yamalik-1 encountered almost 500 m of net sand in Teslimkoy and Kesan reservoirs. The shallower Mezardere and Osmancik reservoirs have not been tested in the basin’s center (Fig. 2).

Prospect development  Dallas-based DeGolyer & MacNaughton (D&M) reported on Feb. 6 that Valeura Energy’s estimated working interest unrisked mean resources were 10.1 tcf, which includes 236 million bbl of condensate. Working interest risked mean prospective resources are an estimated 5.2 tcf of gas, 165 million bbl of which is condensate. Valeura’s Chief Executive Officer Sean Guest said the independent evaluation support-

Oil & Gas Journal | Apr. 2, 2018

TECHNOLOGY

0

Miles

6.2

0

Km

10

ed the company’s thesis of a “large unconventional, basincentered gas-condensate resource,” but also acknowledged that exploration is in an e arly phase. D&M’s broad range of recoverable gas from 3.2 tcf to more than 20 tcf is a function of uncertainty related to limited stimulation and production testing from the overpressured Teslimkoy and Kesan formations in the Thrace basin. The firm has assigned a 74% chance of development for the gas prospect based on economic field size and t he application of existing fracing technology. Follow-up well depths are estimated to be about 5,000 m and therefore not excessive in cost. The Yamalik-1 well, drilled to 4,196 m, was limited by rig capability but the base of the well was still in gas-bearing sands that were successfully f low tested, Valeura said. The company’s existing infrastr ucture and customer base is capable of handling more tha n 35 MMcfd compared with current sales through the system of less than 10 MMcfd. Turkey also meets 99% of its current gas demand by imports, providing an opportunity for domestic producers.

45

TECHNOLOGY

CNOOC studies steam recovery in offshore Bohai heavy oil field Wankun Xu Fengyi Zhang Dawei Wang Tingting Wu CNOOC Ltd. Tianjin Bohai Oilfield Institute Tianjin, China

DRILLING & PRODUCTION

Xiaoha Dong China University of Petroleum Beijing

Jinze Xu Zhangxin Chen University of Calgary Calgary

 A combination of cyclic steam stimulation (CSS), steam drive (SD), and steam-assisted gravity drainage (SAGD) can improve thermal recovery in heavy oil reservoirs in Bohai offshore oil field in the central Bohai Gulf. Bohai’s heavy oil reservoirs present severe heterogeneity and complex water zones, properties that complicate devel-

BOHAI FIELD HEAVY OIL RESERVOIR Reservoir type

Thin water zone

Thicker water zone

Reservoir names Reservoir depth, m Oil viscosity, cp Reservoir thickness, m Water-oil net ratio

MB35-2, QHD, LD-1 1,100 600-3,000 5-15 0-3

LD-2, LD-3 900 >30,000 30-55 1-20

BOHAI FIELD RESERVOIR, FLUID PROPERTIES Properties Reservoir depth, m Porosity, % Absolute permeability, 10-3 sq μm Kv/Kh ratio Thickness, m Net-to-gross ratio Initial oil saturation, % Oil viscosity, cp at 50 ºC. Formation pressure, MPa Formation temperature, ºC. Formation compressibility, kPa-1  Water-oil net ratio

46

Thin water zone

Thicker water zone

1,100 0.378

900 0.323

3,000 0.3 8 0.8 67 667 10.8 56 1.6×10-5  0.5

2,992 0.5 30.9 0.8 73 35,079 9.2 47 7.7×10-6  10

opment. The reservoirs, usually deposited at more than 1,000 m, are classified into three types: • Thin water-zone. • Thicker water-zone. SPECIAL • Lean zone. REPORT Researchers studied thermal recovery processes for each type of reservoir to determine which process worked best given reservoir thickness, oil viscosity, reservoir permeability, vertical and horizontal permeability ratio, and water-oil thickness ratio. Reservoir simulation studies and field experiences demonstrated CSS-SD works best in heavy-oil reservoirs with thin-bottom water. SAGD was most appropriate in thick bottom-water reservoirs with horizontal wells. CSS-SD yielded a higher cumulative oil-steam ratio (COSR) and recovery factor in the lean-zone reservoirs. Table 1 provides the classification of Bohai offshore field’s heavy oil reservoirs: NanBao 35-2 (NB 35-2), QinHuangDao 35-2 (QHD), LvDa-1 (LD-1), LvDa-2, LvDa-3 and LvDa-4. The representative wells are B04M in NB 35-2 reservoir, LD2-4N in LD-2 reservoir, and LD-4-1 in LD-4 reservoir. Other researchers had found CSSSD and SD outperformed SAGD for Table 1 developing thin water-zone heavy oil Lean water zone reservoirs in onshore fields.1-5 The authors of this article focused on CSS-SD LD-4 950 and SD for developing an offshore thin 10,000 < 20 water-zone heavy oil reservoir, com— paring and analyzing the recovery performances of all three processes on the different types of reservoirs. Table 2 The existence of lean zones efLean water zone fects the formation and expansion of a steam chamber, limiting the useful950 0.310 ness of SAGD.6 Bohai field’s lean zone 3,200 led this article’s authors to study CSS 0.3 and SD for that area. 20 0.8 70 10,000 9.5 47 4.6×10-6 —

Numerical simulation models  Figs. 1-3 show the three reservoir models and numerical simulation models developed for each. The thin water-

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zone heavy oil reser voir model has a 5 × 51 × 21 grid system (400 m × 102 m × 48 m). The thicker water-zone heavy oil reservoir model has a 5 × 51 × 49 grid system (400 m × 102 m × 330 m). The lean-zone heavy oil reservoir model has a 5 × 51 × 20 grid system (400 m × 102 m × 20 m). Refined grids produced similar simulation results. A simulator automatically selected the time steps to ensure stability of the numerical schemes (finite volumes in space and adaptive time integration). Both the steam injection well and the oil well have a 300-m horizontal section. Table 2 shows the parameters used in simulation runs. Oil viscosity is highest in the thicker water-zone heavy oil reservoir. The models figured the same production constraints into the CSS a nd SD processes. The steam quality is 80%. The steam injection rate is 240 tonne/d. For SAGD, the temperature difference is controlled within 15 ºC. The operation pressure is 3 MPa. The three models simulated a 20-year production life based on the anticipated life of the offshore platform. Switching CSS to SD in the simulations after seven cycles allowed strategic consideration of the CSS-SD combination.

THIN-WATER ZONE

8 m reservoir thickness

Results and Discussions  Figs. 4-6 show the recovery performance results from a series of simulations on the d ifferent heavy oil reservoirs. Models forecast effective thermal recovery methods by recovery rate, recovery factor, and COSR for each reservoir type. Fig. 4 shows the CSS-SD process yielded the highest reBottom covery results for the t hin-water zone. water zone The COSR of CSS-SD process increased by 11% compared with CSS performance. Fig. 5 shows results for the thicker water-zone where the SAGD process had the best recovery factor, recovery rate, and COSR. The oil recovery factor of CSS was only 5% due to higher formation thickness, existence of a bottom aquifer, and CSS’s limited thermal sweep efficiency. In addition, THICKER-WATER ZONE its recovery rate and COSR were the lowest. Fig. 6 shows the simulated recovery 30 m rate, recovery factor, and COSR results reservoir of the three processes of t he lean-zone thickness heavy oil reservoir. The CSS-SD recovery process model shows the h ighest recovery factor, recovery rate, and COSR for the lean zone. The CSS model shows the lowest Bottom oil recovery rate and COSR, resulting water zone from its limited thermal sweep efficiency. For the recommended CSS-SD combination, CSS established a heat connection between the steam injec-

48

FIG. 1

FIG. 2

Oil & Gas Journal | Apr. 2, 2018

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TECHNOLOGY

LEAN-WATER ZONE

tion well and the production well before the SD process starts.

FIG. 3

Sensitivity studies  Sensitivity studies for the three processes and their corresponding reservoir models examined the effects of reservoir parameters on performance. For offshore oil reservoirs, the recovery rate is a more important indicator than the oil recovery factor. The recovery rate and COSR measure recovery performance. Researchers numerically studied the thermal recovery processes’ adaptability in Bohai field’s reservoir types. Table 3 shows the results and final recommendations. For the heavy oil reservoir with a thin water zone, a CSS-SD process is suitable. The studied formation is relatively thin (8-15 m), permeability is greater than 1,000 × 10-3 μm 2, Kv/  Kh ratio is higher than 0.3, and the water zone is low with a water-oil net ratio of < 1. SAGD is suitable to a reservoir more than 25 m thick, with a thicker water zone, horizontal permeability greater than 2,000 × 10-3 μm 2, and a Kv/Kh ratio higher than 0.3. For a heavy oil reservoir with lean water zones, CSS and SD processes are suitable. Other reservoir parameters applicable to this choice are thickness greater than 15 m, oil viscosity less than 30,000 cp at 50° C., horizontal permeability greater than 1,000 × 10 -3 μm 2, and Kv/Kh ratio higher than 0.3.

20 m

reservoir thickness

Acknowledgments  The authors acknowledge the financial support of National Science and Technology Major Project (20162X05058001-008), CNOOC Ltd. Tianjin Bohai Oilfield Institute, the NSERC/AIEES/Foundation CMG Chair, and the AITF (iCORE) Chair.

References  THIN-WATER ZONE 45

FIG. 4

3.0

0.18 Oil recovery factor

40 2.5    %  ,   r   o    t   c   a    f   y   r   e   v   o   c   e   r    l    i    O

35 30 25 20 15

0.15

Recovery rate    %2.0  ,   e    t   a   r   y   r 1.5   e   v   o   c   e    R1.0

COSR

0.12    R

0.09    S    O    C

0.06

10 0.5

0.03

5 0

0

CSS-SD

SD Recovery method

Oil & Gas Journal | Apr. 2, 2018

TECHNOLOGY

CSS

0

1. Butler, R., “Thermal Recovery of Oil and Bitumen,” Prentice Hall, Englewood Cliffs, NJ, 1991. 2. Farouq Ali, S., Jones, J., and Meldau, R., “Practical Heavy Oil Recovery,” University of Alberta, Edmonton, 1979. 3. Kendall, G., “Importance of Reservoir Des cription in Evaluating In-situ Recovery Methods for Cold Lake Heavy Oil,” Petroleum Societ y of Canada Journal of Canadian Petroleum Technology, Vol. 16, No. 1, January 1997, pp. 41-47. 4. Kasraie, M., and Farouq Ali, S., “Heavy Oil Recovery in the Presence of Bottom Water,” Petroleum Society of Canada A nnual Technical Meeting, Calgary, June 10-13, 1984.

49

TECHNOLOGY

RECOMMENDED RECOVERY METHOD, BOHAI FIELD Heavy oil reservoir type

Recovery method

Thickness, m

CSS-SD SAGD CSS-SD

>8 > 25 > 15

Thin water zone Thick water zone Lean zone

Table 3

Oil viscosity, cp at 50° C.

3.0

20 15 10

The authors

0.15

Recovery rate    %2.0  ,   e    t   a   r   y   r 1.5   e   v   o   c   e    R 1.0

0.12

COSR

   R

0.09    S    O    C

0.06

0.5

0.03

5 0

0

SAGD

CSS-SD

SD

CSS

0

Recovery method

LEAN-WATER ZONE 45

FIG. 6

3.0

0.12 Oil recovery factor

40 2.5    %  ,   r   o    t   c   a    f   y   r   e   v   o   c   e   r    l    i    O

35 30 25 20 15

Recovery rate

   %2.0  ,   e    t   a   r   y   r 1.5   e   v   o   c   e    R 1.0

   R

0.08    S    O    C

Wankun Xu (xuwk@ cnooc.com.cn) is a reservoir engineer at Binhai New Area of Tianjin, Bohai oil field since July 2010. He researched multiple-thermal fluid mechanisms and offshore thermal recovery programs, such as CS S and SAGD, during 2010-16. He obtained his BS and MS in oil and gas field development engineering, from China University of Petroleum, East China. Zhang Fengyi ([email protected]) is a CNOOC Ltd. Tianjin Bohai Oilfield Institute reservoir engineer with more than 10 years’ experience in the oil and gas industry. He holds a BS (2004) and MS (2007) in reservoir engineering from China University of Petroleum. His research interests are development and production of offshore heavy oil.

Dawei Wang ([email protected]) is a reservoir engineer at Binhai New Area of Tian jin, Bohai oil field since 0.04 July 2012. He researched CSS the development programs of offshore heavy oil field from 2012-17. He holds a BS (2004) in chemical engineering and an MS (200 9) and PhD (2012) in oil and gas field development engineering from Southwest Petroleum University, China. 0.06

0.5 5 0

CSS-SD

SD Recovery method

5. Delamaide, E., and Moreno, W., “Enhanced Oil Recovery of Heav y Oil in Reservoirs with Bot tom Aquifer,” Society of Petroleum Engineers (SPE) Western Regional Meeting, Garden Grove, Calif., Apr. 27-30, 2015. 6. Samuels en, E., Langlais, V., Svanes, T., Dalen, V., and Tyler, K. “Evaluation of Flooding S trategies for a Nor th Sea Reservoir Using Stochastic Techniques to Model Heterogeneities,” SPE-Department of Energy Ninth Symposium on

50

0.1

COSR

10

0

<1 0-20 —

0.18 Oil recovery factor

2.5

25

> 0.3 > 0.3 > 0.3

FIG. 5

35 30

> 1,000 > 2,000 > 1,000

Water-oil net ratio

Improved Oil Recovery, Tulsa, Apr. 17-20, 2013.

40    %  ,   r   o    t   c   a    f   y   r   e   v   o   c   e   r    l    i    O

Kv/Kh

600-3,000 5,000-200,000 < 30,000

THICKER-WATER ZONE 45

Permeability, 10-3 sq μm

Tingting Wu ([email protected]) is a reservoir engineer at Binhai New Area of Tianjin, Bohai oil field since July 2011. She researched numerical simulation technology in thermal recovery for offshore oilfields and thermal recovery technologies for heavy oil reservoirs, such as thin interbed common heavy oil reservoir and

Oil & Gas Journal | Apr. 2, 2018

TECHNOLOGY

TECHNOLOGY

massive block extra-heavy oil reservoir during 2011-16. She obtained her BS and MS in oil and gas field development engineering from Northeast Petroleum University. Xiaohu Dong (dongxh0 [email protected]) is an assistant professor at the Department of Petroleum Engineering, China University of Petroleum, Beijing, since 2016. Previously, he worked as a postdoctoral fellow at the University of Calgary, 2014-16. He holds a BS (2009) and PhD (2016) in petroleum engineering from the China University of Petroleum, Beijing. Dong’s research includes phase behavior modeling in unconventional resources and thermal and non-thermal recovery methods for heavy oil. Jinze Xu ([email protected]) is a PhD student at the University of Calgary Department of Chemical and Petroleum Engineering. He obtained an MS (2015) in petroleum engineering from the University of Calgar y and a BS (2011) in petroleum engineering from China University

of Geosciences, Beijing. He researches heavy oil, oil sands, and shale gas. Zhangxin Chen ([email protected]) is a University of Calgary petroleum engineering professor. He currently holds the Natural Science and Engineering Research Council Chair, and Computer Modelling Group Chair and is the Industrial Research Chair in Reser voir Simulation, and the Alberta Innovates Technology Future (iCORE) Industrial Chair in Reservoir Modeling. He is director of the University of Calgary’s iCentre for Simulation & Visualization. He earned a PhD (1991) from Purdue University, West Lafayette, Ind.,an MS (1985) from Xi’an Jiaotong University, China, and a BS (1983) from Jiangxi University, China. He was a professor and reservoir engineer at Xi’an Jiaotong University, Peking University, University of Minnesota, Texas A&M University, and Southern Methodist University. His research interests are reservoir engineering and numerical reser voir simulation for conventional and unconventional reservoirs.

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Nanofluids hold EOR potential in Egypt’s Western Desert Sayed Gomaa Al-Azhar University Cairo

Adel Salem Suez University Suez

DRILLING & PRODUCTION

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Reservoir engineers seek ways to alter the wettability from oil wet to water wet or from water wet to highly water wet in efforts to change total recovery factor. Wettability affects fluid distribution, relative permeability, and flow behavior through porous media. Nanoparticles have great potential for altering rock wettability.

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Experimental work 

Belayim Petroleum Co. Cairo

 Alumina nanoparticles in a displacing brine alter rock wettability and increase the ultimate recovery factor in Egypt’s  Western Desert, providing a new method of enhanced oil recovery (EOR). Nanoparticles are believed to have great potential in wettability alternation of cores, i mproving recovery factors. Researchers ran a series of core flooding experiments to determine the effect of different concentrations of aluminum oxide (alumina, Al2O3) nanoparticles.  An ultimate recovery factor of 81.13% at 10 g /l. alumina nanofluid led to a 20.75% oil recovery over what was achieved by water flooding.  Al 2O3 changes the wettability of the sandstone rock. After nanofluids are injected into the core sample, it became more water wet. Researchers measured contact angles to determine rock wettability and recovery factors. FLOODING APPARATUS Pressure transducer

Core holder Oil accumulator

Nano accumulator

Pump

52

 

Brine accumulator

Confining pressure pump

Researchers used a 70,000-ppm brine prepared with NaCl salt. This concentration represents average Egyptian oil field reservoir water salinity. The core samples came from an Egyptian oil field in the Western Desert.  A pycnometer measured the brine and oil density, and a rolling ball viscometer measured viscosity. The bulk volume, pore volume, and porosity were measured using a helium porosimeter and the liquid saturation method. Researchers used a gas permeameter and a liquid permeameter to measure the core permeability. Researchers fully immersed the core in a beaker containing the prepared brine. The core was placed in a vacuum saturator for 2 hr to ensure full saturation. Laboratory workers prepared nanofluids, which went into a probe sonicator or a bath sonicator. Sonication takes 2 hr to guarantee full suspension of nanoparticles in the f luid. During sonication, specific sound waves are forced through a solution, agitating its particles. The resulting disruptions can better mix the solution or accelerate dissoluFIG. 1 tion of solids inside the liquid. Sound waves cross alternating high-pressure and low-pressure regions. Frequency of the sound waves measures how often the particles vibrate. Sonication of nanoparticles is most effective at ultrasonic frequencies above 20 kHz.  An increased frequency leads to better agitation and suspension of the nanoparticles. Researchers used Graduated a probe sonicator with a frequency of cylinder 50 kHz. It worked with an amplitude range of 30-90%. Fig. 1 shows a schematic of the flooding apparatus. The core is placed

Oil & Gas Journal | Apr. 2, 2018

TECHNOLOGY

TECHNOLOGY

in the core flooding device. Oil is in jected into the core under high-pressure differential, enabling oil to replace brine. This process stops when no more brine exits the core. At this point, the production water cut is zero.  A low pumping rate during flooding adheres to Darcy’s law. Volumes of produced oil and brine are measured, and their flow rates calculated. The pressure difference and process time are also monitored at each step. Researchers use these parameters to calculate and plot the recovery factor and relative permeability curves. The core represents an oil reservoir.  Any remaining brine inside the core is considered connate water. The volume of brine produced is calculated through graded tubes and considered to be the volume of oil in place. Researchers calculate the amount of pore volume (PV) remaining, considered to be the interstitial water volume, using the data to determine critical water saturation and oil saturation.

Nanoparticles identification 

RECOVERY FACTOR*

FIG. 2

100

80    %  ,   r   o    t   c   a    f   y   r   e   v   o   c   e    R

60

40

20

0 0

1

2

3 4 Pore-volume injected, cc

5

6

*Nano alumina 10 g/l.

PERMEABILITY FACTOR*

FIG. 3

1.2 1.0

  r    K  ,   y    t    i 0.8    l    i    b   a   e   m 0.6   r   e   p   e   v    i 0.4    t   a    l   e    R

The Egyptian Petroleum Research Institute (EPRI) prepared the alumina 0.2 particles. The prepared alumina is a Oil nano-sized highly crystalline alphaWater 0 type alumina powder synthesized by 0.65 0.70 0.75 0.80 microwave combustion at 900 w for Water saturation, fraction 5 min with a metal-fuel molar ratio of *Nano alumina 15 g/l. 1:3.  A high-resolution transmission electron microscopy (HRTEM) test before the next experiment. Contact angle, different sized the alumina nanoparticles. An XThe experimental procedure folconcentrations ray diffraction test on very fine partilows: Nano alumina, g/l. Contact angle, ° cles with a spherical shape showed the • Place the saturated core plug in0 32.443 3 82.442 presence of a highly crystal line phase. side the core-flooding device. 5 97.781 Injection of an Al2O3 nanofluid in• Apply confining pressure until 7 127.727 10 129.226 side an oil reservoir leads to decreased all injected fluid passes through the residual oil saturation, increased oil core to ensure there are no leaks in the production, and increased overall uldevice. A hydraulic pump fixed at 500 timate recovery from the field. psi creates the confini ng pressure. The nanofluid injection occurs in the tertiary recovery • Place the oil inside the core-flooding device and inject phase after the water flood. Researchers injected multiple pressure on the oil inside the rock sample. concentrations of nanofluid into the core plug: 3 g/l., 5 g/l., • Transfer the brine solution from the core sample to a 7 g/l., and 10 g/l. graduated tube. Lab workers cleaned the core between tests by removing • Calculate the brine solution volume using the graduit from the flooding device and soaking it overnight in a solated tube. The brine represents the oil in place. vent. The core was heated in an oven to evaporate all fluids • Calculate the connate water saturation.

Oil & Gas Journal | Apr. 2, 2018

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53

TECHNOLOGY

ALUMINA NANOFLUID CONCENTRATION 90 80    %  ,   r   o    t   c   a    f   y   r   e   v   o   c   e   r    l    i    O

70 60 50 40 30 20 10 0

1

2

3 4 Pore volume injected, cc

*Water flood

• Continue the experiment for 2 hr to ensure no additional brine solution can be removed from the core.

Results  Researchers determined initial volume of oil in place was 10.6 cc, oil saturation was 67.67%, and the connate water saturation was 32.33%. In the base run, the core sample was water flooded (WF) with no nanofluid. Researchers started by injecting 0.2 PV and periodically monitored the recovery with increased in jections going up to 5 PV. The oil recovery factor increased as the injected pore volume increased. The water injection continued until no more oil was produced and all output fluid was water or up to the economic limit. The recovery factor was 60.38% of original oil in place. In the nano alumina flooding, the concentration of the  Al 2O3 nanofluid is 3 g/l. of brine solution. This represents about 3,000 ppm or 0.3 wt %, one of the most commonly used concentrations in nanoparticle research. Researchers prepared the alumina nanofluid using 0.15 g of alumina nanoparticles, which were added to 50 ml brine inside a beaker. They set a sonicator inside the beaker to an amplitude of 50% with one pulse on and one pulse off. The sonication process lasted until no nanoparticles precipitated at the beaker bottom. The nanofluids went inside the vessel while the vessel was placed on a magnetic stirrer and a magnet placed inside the vessel. The vessel was closed properly to ensure all the pressure was used to push the fluid inside the rock core sample. Researchers put 0.2 PV inside the vessel under constant pressure to inject the alumina nanofluid inside the rock sample. The amount of water produced, oil produced, time of production, and pressure were determined and recorded

54

for additional calculations. This same procedure was repeated with PV of 0.4, 0.6, 0.8, and 1.0. Results were collected to calculate water cut, the amount of residual oil, the incremental oil recovery, and the ultimate oil recovery. Maximum recovery factor with 3 Nano alumina, g/l. g/l. of alumina nanofluid was 74.38%, 0* 3 a 14% higher recovery factor than the 5 water flooding base run. 7 The relative permeability curve in10 dicates increased wettability of the 15 rock. The point of intersection for the nanofluids test shifted toward water 5 6 wet. This meant a better mobility ratio and increased estimated ultimate recovery (EUR). The point of intersection was 72.5% water saturation vs 67.5% with water flooding. In a 5g/l. concentration alumina nanofluid experiment, the recovery factor was 74.58%, up 0.71% from the 3 g/l. test. The 5 g/l. test increased the recovery factor by 14.71% over the water-flooding base run. Relative permeability’s intersection point moved to about 73.5% water saturation, meaning the core become more water wet with 5 g/l. than with 3 g/l, indicating a better mobility ratio and EUR. The 7 g/l.-concentration alumina nanofluid experiment showed a 76.13% recovery factor, marking a 1.04% incremental recovery from the 5 g/l. run and running about 15.75% higher than the water-flooding base run. Relative permeability showed an increasing wettability of the rock sample. The point of intersection for the 7 g/l. concentration was 75.5% water saturation. Fig. 2 shows results from testing a 10 g/l. concentration, finding a maximum recovery factor of 81.13%, 5% higher than the previous case and about 20.75% higher than the water-flooding base run. The relative permeability curve shows rock wettability moved toward the water-wet region. The point of intersection was 79% water saturation. Fig. 3 shows the 15 g/l. concentration experiment yielding the lowest recovery factor. The intersection point of the relative permeability curve also was lower than the experiment with a 10 g/l. concentration. The 15 g/l. intersection point decreased to 66.64% water saturation, less than the water flooding base run. Researchers concluded that fluid containing high concentrations of nanoparticles can cause blockage of the pores, decreasing oil production. Fig. 4 compares the recovery factors achieved by using different alumina nanofluid concentrations. FIG. 4

Wettability changes  Ultimate recovery and relative permeabilities of a reservoir

Oil & Gas Journal | Apr. 2, 2018

TECHNOLOGY

TECHNOLOGY

hinge upon the wetting behavior of the PERMEABILITY INTERSECTION, POINT MOVEMENT rock, which can be water wet or oil 100 wet. An adjustment to the wettability of a reservoir can achieve higher pro90 duction.    % Researchers used a high-resolution  ,    t   n    i camera to measure the contact angle at 80   o   p   n different concentrations from 0 g/l. to   o    i    t   c 10 g/l. The table shows that as the con  e   s 70   r   e centration increases, the contact angle    t   n    I increases, a change in wettability to60 ward water wet. The contact angle is the angle, conventionally measured through the liq50 0* 3 5 7 10 uid, at which a liquid-vapor interface Nano alumina concentration, g/l. meets a solid surface. It quantifies the *Water flood wettability of a solid surface by a liquid. Results confirm the relative permeability curves findings and the intersection point findings. The wettability increase explains the improved incremental The authors recovery factor by alumina nanofluid over conventional waSayed Gomaa ([email protected] ) is an ter flooding. associate professor of petroleum reservoir engiThe intersection point on the relative permeability curve neering at Al-Azhar University and The British indicates the degree of rock wettability. Fig. 5 shows the inUniversity in Egypt. He holds a BSc (1999) and tersection point corresponding to a water saturation higher MSc in petroleum engineering (2005) from Althan 50%, a water-wet water-wet rock. The nanofluid concentrations, Azhar University and PhD (2010) in petroleum except for 15 g/l., made the rock more water wet, increasing engineering from Azerbaijan State Oil Academy. the recovery factor above that of conventional water flooding. Adel Moh. Salem Ragab (adel.salem@suezuni.

Acknowledgments  The authors thank the British University in Egypt, Future University in Egypt, and the Egyptian Petroleum Research Institute for providing research equipment and core plugs.

Bibiliography  Li, S., Genys, M., Wang, K., and Torseter Torseter,, O., “Experimental “Exp erimental Study of Wettability Alteration during Nanofluid Enhanced Oil Recovery Process and Its Effect on Oil Recovery,” Society of Petroleum Enginers (SPE) Reservoir Characterization and Simulation Conference and Exhibition, Abu Dhabi, Sept. 1414-16, 16, 2015. Ragab, A., and Salem, M., “Unlocking Reservoir Potential using Robust Hybrid Nanoparticles Designe d for Future Enhanced Oil Recovery,” Mediterranean Mediterranean Offshore Of fshore Conference & Exhibition, Alexandia, Eg ypt, Apr. 19-21, 2016. Sheshdeh, M., “A Review Study of Wet tability Alteration Methods with Regard to Nano -Materials Application,” Application,” SPE One Day Co nference, Bergen, Norway, Apr. 22, 2015. 2015. Torsater, O., Li, S., and Hendraningrat, L., “A Coreflood Investigation of Nanofluid Enhanced Oil Recovery in Low-Medium Permeability Berea Sandstone,” SPE International Symposium on Oilfield Chemistry, The Woodlands, Tex., Apr. 8, 2013.

Oil & Gas Journal | Apr. 2, 2018

TECHNOLOGY

FIG. 5

15

edu.eg ) is an associate professor and head of the petroleum engineering department at Suez University. He obtained a PhD (2008) in petroleum engineering from Leoben University, Austria. He also earned a BS and MS from Suez Canal University, Egypt. Previously Previously,, Adel was assistant professor at American University in Cairo for 4 years, Future University in Egypt for 2 years, and Suez Canal University for 3 years. He has published more than 45 papers on EOR, characterization characterization of formation formation damage, nanotechnology of o f EOR, and smart drilling fluids, oil shale, well testing, and radial drilling. Mohamed Hassan (Mohamed.hassan813@ p etroleum engineer for Belayim gmail.com) is a petroleum Petroleum Co. He holds a B S (2016) in petroleum engineering from British University in Egypt.

55

TECHNOLOGY

Continuous pack-off inflow control device lowers water cut offshore China Feng Li Xiaoping Li Southwest Petroleum University Chengdu, China

Bailin Pei Songmei Zhang Hailong Wang Guojiang Feng Jianchang Wu Xiaoling Li

SPECIAL

REPORT

Anton Bailin Oilfield Technology Technology Co. C o. Ltd. Beijing

The water-coning water-coning interval might m ight be a small percentage of the entire wellbore, yet the overall water cut still can be high. Darcy’s law establishes a strong correlation with t he mobility ratio of in-situ water and oil. Equations 1-2 show the mobility ratio of water and oil in Liuhua reservoir res ervoir.. The water rate of the high-permeability zone is more than three times higher than t he oil rate in lowpermeability zones, assuming oil viscosity of 130 cp. Fluid moves through the reservoir’s fractures and faults to EQUATIONS

m 0 = K 0 /n 0 and mW = K W /n W M = m W /m 0 = K W n W

(1) (2)

)

Researchers lowered the water cut and increased oil producproduction during a trial of a continuous pack-off inflow control device (CP+ICD) in an offshore horizontal well in 300 m of water in Liuhua oil field, eastern South China Sea. CP + ICD technology was developed to resolve high water-production issues for horizontal wells. Previously, CP + ICD proved successful in the sandstone reservoirs of onshore northwestern China oil fields (OGJ, Oct. 3, 2016, p. 48 and OGJ, May 1, 2017, p. 52). This article discusses t he technology’s first trial on a carbonate reservoir. reservoir. It also marks the first offsho offshore re trial for CP + ICD. Effective water control is a well-known problem in Liuhua field where industry reports cumulative oil production at 10% estimated OOIP. Operators often shut in Liuhua wells due to 99.5% basic sediment and water production. The Cenozoic carbonate reservoir involves a one-porosity, two-permeability flow system characterized by fractures and minor faults. CP + ICD minimizes water production along a well’s horizontal section because injected particles buffer water flow through the annulus. CP + ICD differs from a swellable packer inflow control device (SP + ICD), which compartmentalizes a horizontal section into units. CP + ICD works in old wells unsuitable for mechanical packers and in poor poor-sealing -sealing wells having irregular wellbores or twisted casi ng. Operators can restart shut-in wells because CP + ICD maximizes oil production while limiting water-production volumes after a water breakthrough. Heterogeneity of formations combined with reservoir fluid properties can cause an uneven flow or water coning toward the horizontal section.

56

NOMENCLATURE mobili ility ty,md/ mPa mPa s m 0 = oil mob :

K 0 = oi oill pe perm rmea eabi bili lity ty,md viscosi osity ty,mPa mPa s n 0 = oil visc watermobil termobility ity, md/ mPa s m W = wa :

:

K W = wa wate terr me meam amea eabi bili lity ty,md water ter vis viscos cosity ity,mPa s n W = wa :

M = mobility ratio ,dim ensionless

the wellbore. The ICD screen chokes water flow after water breakthrough. Industry has used SP + ICD to remedy high-water production for more than 20 years, but it can be hard to isolate horizontal sections using mechanical packer installations. Some wellbores develop irregularities while drilling into unconsolidated reef limestone reservoirs. Consequently, a mechanical packer’s seal malfunctions. Upon water breakthrough, oil production production declines so drastically that operators shut in the wells. The CP + ICD is self-adaptable to various wellbore conditions. Light, stable particles are injected into the annular space between the ICD screen and wellbore wall. The particles, which take the place of mecha nical packers in a conventional ICD, also help control sand production. Fig. 1 shows how CP + ICD minimizes the axial flow

Oil & Gas Journal | Apr. 2, 2018

TECHNOLOGY

TECHNOLOGY

relative to the radial flow. A 7-in. casing houses the 3.5-in. ICD screen. The Well A4H4 ICD pipe is 10 m long with wit h a 1-m juncDate Oil rate, Water rate, Liquid rate, BS&W, % Drawdown, cu m/d cu m/d cu m/d MPa tion. Pre-operation October 2015 8 1,782 1,790 99.5 0.66 Fig. 2 shows minor faults and min i Post-operation February 2017 39 2,038 2,077 98.1 5.55 fractures that provide direct communication with oil-bearing zones in Liuhua field. All wells ex perienced water breakthrough within weeks of coming on stream. Produczontal section into six units. A 99% water cut was recorded tion stabilized after the water cut reached 90%. after 9 days of operation. Reservoir characteristics indicated fractures and faults. Researchers detected wellbore irregularities. They also unField trials  Earlier SP + ICD trials proved incapable of controlling water successfully tested chemical-based water-control technology. in Liuhua field’s fracture-fault system. The SP + ICD and au A CP + ICD tria triall on Well A4H4 filled fil led the 575-m lateral la teral tonomous inflow control device (AICD) trials involved two with CP particles. The trial was successful without engiwells with five swellable packers installed to divide a horineers having havi ng to locate water water-breakthrough -breakthrough points, fractures, and faults.  Well A4H4 was w as shut in i n dur ing December 2015 after producing 99.5% FLOW RESISTANCE FIG. 1 basic sediment and water (BS&W). Wellbore Inflow control screen Fig. 3 shows the CP + ICD well comAxial direction pletion with an 8 ½-in. open hole. Permeability was wide ranging, averaging 300 md. The oil had 130 cp viscosity.  Well A4H4 demonstrat demonstrated ed water coning. The water cut reached over 90% within weeks of water breakthrough. Production dropped dramatically with water accounting for most of the produced produced fluid, making maki ng the well economically unfeasible. The table shows a direct comparison of data from before and after the Radial direction CP + ICD trial, tri al, indicating improved oil production and lower water production in 4 weeks. But the direct comparison could be misleading g iven altered operational circumstances. Part of the RESERVOIR WATER CHANNEL FIG. 2 oil rate might result from additional liquid production. Other operating concerns include extra water disposal expenses or the need to reduce liqOpen hole uid production from other wells given constrained Liuhua oil-processing capability. Researchers also indirectly compared production data through indexMini fracture es. The water production index slid to around 14% of baseline data before the Water trial because the ICD screen imposed breakthrough an additional drawdown to reduce zone water in the breakthrough unit. The oil-production index reacted similarly although not as dramatically. The oil

Oil & Gas Journal | Apr. 2, 2018

TECHNOLOGY

57 

TECHNOLOGY

WELL A4H4 COMPLETION

FIG. 3

Hanged packer, 1,383 m

ICD screen, 1,404 m

Continuous pack-off particles

index number was about half the baseline d ata number. Dimensionless water-oil ratio (WOR) post-trial was down 78% overall compared with WOR pretrial data. If the same liquid production rate can be maintained, oil production could increase by 2.6 times, although production started to decline following the trial.

Acknowledgment  The authors would like to thank the collaborative efforts of CNOOC Shenzhen, Southwest Petroleum University, and  Anton Bailin Oilfield Co. Ltd. Special thanks to CNOOC for sharing data and permi ssion to publish the results.

Bibliography  Al-Khelaiwi, F., and Davies, D., “Inflow Control Devices: Application and Value Quantification of a Developing Technology,” Society of Petroleum Engineers (SPE) International Oil Conference and E xhibition, Veracruz, Mexico, June 27-30, 2007. Ellis, T., Erkal, A., Jokela, T., Kvernstuen, S., Leung, E., Moen, T., Porturas, F., Skillingstad, T., Vorkinn, P., and Raffn, A., “Inflow Control Devices: Raising Profiles,” Oilfield Review Winter, December 20 09, Vol. 21, No. 4, pp. 30-37. Lee, B., Fassam, F, Galimzyanov, A., Faizal, S., and Vicario, R., “ICD Evaluation Study Using Numerous PLT Runs to Optimize Design Practice and Maximize ICD Value,” International Petroleum Technology Conference, Kuala Lumpur, Dec. 10-12, 2014. Okwananke, A., Isehunwa S., Adeosun T., and Adeboye Y., “Water Cresting Predictions in Horizontal O il Wells,” Advances in Sustainable Petroleum Engineering Science Journal, September 2012, Vol. 4, No. 3, pp 109-124. Permadi, P., Lee, R., and Kartoatmodjo, R., “Behavior of Water Cresting Under Horizontal Wells,” SPE Annual Technical Conference and E xhibition, Dallas, Tex., Oct. 22-25, 1995. Zeng, Q.S., Wang, Z.M., and Yang, G., “Comparative Study on Passive Inflow C ontrol Devices by Numerical Simulation,” Tech

58

Science Press S.L., Vol. 9, No. 3, May 2013, pp. 169-180. Youl, K., Suhana, W., Regulacion, R., and Jorgensen, T., “Passive Inflow Control Device s and Swellable Packers Control Water Production in Fractured Carbonate Reser voir: A Comparison with Slotted Liner Completions,” SPE-IADC Drilling and Exhibition, Amsterdam, Mar. 1-3, 2011. Sun, X., and Bai,, B., “Comprehensive Review of Water Shutoff Methods for Horizontal Wells,” Petroleum Exploration and Development, December 2017, Vol. 44, No. 6, pp. 1022–1029.

The authors

Feng Li (feng_ [email protected]) is an upstream department head of CNOOC Shenzhen, managing the oil and gas production in the East Part Region, South China Sea. He is pursuing a PhD with State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chendgu, China. Xiaoping Li ([email protected]) is a professor at Southwe st Petroleum University. He holds a PhD in petroleum engineering from Southwes t Petroleum University. He specializes in reservoir engineering and well test analysis. Bailin Pei ([email protected]) is an associate professor in the petroleum engineering department at China University of Petroleum in Beijing. He holds a BS and MS in petroleum engineering from Southwest Petroleum University and a PhD in hydromechanics from the University of Science and Technology of China, Hefei. His research covers horizontal well water control, sand prevention, and inflow control devices.

Oil & Gas Journal | Apr. 2, 2018

TECHNOLOGY

TECHNOLOGY

Songmei Zhang ([email protected]) is a senior reservoir engineer at Anton Bailin Oilfield Technology specializing in water-control issues and sand prevention. Zhang graduated from China University of Petroleum in Beijing with an MS (200 4) in petroleum engineering. Hailong Wang ([email protected]) is a reservoir engineer at Anton Bailin Oilfield Technology. He graduated from China University of Petroleum in Beijing with a BS (2011) in petroleum engineering. Guojiang Feng ([email protected]) is a mechanical engineer at Anton Bailin Oilfield Technology. He has 17 years oil and gas experience. He graduated from Harbin University of Science and Technology, China, with a BS (2000) in mechanical engineering.

Jianchang Wu ([email protected]) has worked for Anton Bailin Oilfield Technology since 2013. He started his oil and gas career in 2006, focusing on well-screen design. He received a BS (1995) in manufacturing engineering from the North China Institute of Aerosp ace Engineering, Langfang.  Xiaoling Li ([email protected]) is an experienced reser voir engineer, having worked in both China and Australia. She completed her BS in petroleum engineering (1991) from Petroleum University (East China) and is pursuing a PhD with the University of Queensland, Brisbane, Australia.

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• Petroleum refining • Pipelines • Well logging

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59

TECHNOLOGY

Study evaluates refiners’ options to meet 2020 bunker fuel sulfur rules LC-LSFO ATB UPGRADE

Tayseer Abdel-Halim Matthew Yu

FIG. 1

LC-FINING reactors

Heavy oil treater (HOT)

Gas cooling, purification, compression

Chevron Lummus Global Richmond, Calif 

Refiners need to modif y their product slate to conform to increasingly strict environmental regulations as efforts to reduce atmospheric emissions have extended to fuel oil burned at sea. In October 2008, the International Maritime Organization (IMO)—the United Nations agency respon sible for the safety, security, and environmental stewardship of international shipping—adopted new, geographically based standards to limit exhaust emissions from engines that power oceangoing vessels. These standards require ships operating in PROCESSING areas with air-quality problems—designated as Emission Control Areas (ECAs)—to meet even tighter emission limits. While portions of the new standards have been gradually phased in over the last several years, final regulations are slated to take effect in 2020, putting refiners with relatively large production of residual fuel oil at risk for adverse impacts to profitability. To comply with these stricter regulations, the shipping industry is considering either burning IMO-compliant fuels or retrofitting ships with an exhaust-gas scrubber or an LNG fuel system. All three options have serious operational and economic detriments

60

Product fractionator

HOT

Medium-pressure, medium-temperature (MPMT) separator

Medium-pressure separator (MPS) Naphtha

Diesel

Heavy oil separator (HOS) Vacuum residue

Hydrogen makeup

Gas oil (GO)

HOT ATB

VDU VGO

Hydrogen

Filter LSVR

LC-LSFO VTB UPGRADE LC-FINING reactors

FIG. 2

Integrated hydrotreater (IHT)

Clean product fractionator

Gas cooling, purification, compression

GO High-pressure, high-temperature (HPHT) separator

Hydrogen makeup

IHT

HOS

MPS HDT naphtha VDU

Filter Vacuum residue

Euro 5 diesel Hydrogen

Fractionator

HOT

Treated VGO UCO

LSFO

Oil & Gas Journal | Apr. 2, 2018

that impact refiners exposed to bunker fuel markets. This article presents refiners with several commercially proven bottomof-the-barrel processes that enhance earning potential in the face of these new bunker fuel requirements, including a detailed techno- economic analysis to compare the different processes.

BASE-CASE REFINERY

Arab Light, Heavy crude blend Crude, vacuum distillation unit; 16,000 tpy

New specifications, options  Current specifications for bunker fuels—in effect since January 2012—limit sulfur globally to 3.5 wt %. With the global specification slated to drop to 0.5 wt % in 2020, however, the impending regulations will threaten the profitabilprofitability of refiners which produce a relatively large proportion of residual fuel oil.1 Since 2015, 2015, ships operating in ECAs ECA s have been required to use fuels with a maximum sulfur level of 0.1 wt %, reduced from 1.0 wt % in 2010. Table 1 summarizes summari zes the historic and proposed fuel sulfur standards and anticipated start dates for ECA and global fuel sulfur limits.  While thes thesee emis emission sion reductions theoretically can be achieved by installing onboard flue-gas desulfurization, this technology has been commercially proven only in land-based industrial applications and is unlikely to be commercially accepted in a shipbased setting in i n the foreseeable future. Issues surrounding use of this technology—including the discharge of treated wastewater—must be resolved, making the number of ships that would be retrofitted for it unclear. It is more likely that ships will be retrofitted to burn low-sulfur diesel fuel while operating in ECAs. Refiners that serve the bunker fuel market have started considering future options.

Refiners’ options  The options available to refiners producing high-sulfur fuel oil (HSFO) are limited and include include:: • Continuing business bu siness as a s usual. usu al. Profitability of HSFO will become less attractive as prices decline. While a

Oil & Gas Journal | Apr. 2, 2018

TECHNOLOGY

FIG. 3

Benzene Naphtha hydrotreater Raffinate (NHT); continuous C7, reformate catalytic reformer (CCR); benzene, toluene, xylenes (BTX) unit

Naphtha Distillates Vacuum gas oil (VGO)

Desulfurized VGO (DS) VGO hydrodesulfurizer (HDS)

Vacuum residue

Hydrocracker

C4 FCC, gas plant

Unconverted oil (UCO)

Alkylation

Alkylate

FCC gasoline Slurry oil to fuel oil Light-cycle oil (LCO)

Diesel

To fuel oil Distillate hydrotreater

To fuel oil

C3

Hydrotreated (HT) jet HT diesel

Naphtha Visbreaker

Visbroken residue to fuel oil To fuel oil

Natural gas, refinery fuel gas (RFG)

H2 plant

H2

CASE 1: RESIDUE HYDROTREATER (RDS), RFCC

FIG. 4

Benzene

Arab Light, Heavy crude   Naphtha blend Crude, vacuum distillation Distillates unit; 16,000 tpy VGO

NHT, CCR, BTX

Existing

Raffinate

Revamp

C7, reformate

New C3

VGO HDS

DS VGO

Vacuum residue Hydrocracker

C4 FCC, gas plant

UCO

Alkylation

Alkylate

FCC gasoline Slurry oil LCO

Diesel Distillate hydrotreater

HT jet HT diesel

LCO Naphtha

RDS

LCO

Distillate

C4

DS atmospheric residue Natural gas, RFG

H2 plant

C3

RFCC, gas plant

H2

Alkylation

FCC gasoline Slurry oil

DS FCC Gasoline gasoline hydrotreater

IMO FUEL SULFUR STANDARDS Timing Before July 1, 2010 Before Jan. 1, 2012 On and after July 1, 2010 On and after Jan. 1, 2012 On and after Jan. 1, 2015 On and after Jan. 1, 2020

Alkylate

Table 1

ECA fuel sulfur limit, wt % 1.5 — 1.0 — 0.1 —

Global fuel sulfur limit, wt % — 4.5 — 3.5 — 0.5

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TECHNOLOGY

ECONOMIC ANALYSIS RESULTS

Table 2

Case

Base

Crude Crud e Arabian Light Arabian Heavy Imported Impor ted Feed MTBE Natural Gas Isobutane Coke

Pric Pr ice, e, $/ $/bb bbll 43.89 42.39 Price,, $/ton Price $/tonne ne 694.00 361.55 440.00 40.00

Products Produc ts Refinery-grade propylene Benzene Sulfur Fuel coke Anode coke Asphalt

Price, Pri ce, $/t $/tonn onne e 445.93

Naphtha Euro-5 95 RON Gasoline Jet A‐1, kerosine Euro-5 diesel 3.5% sulfur HSFO 0.3% sulfur LSFO Slurry oil Delta net revenue, $ million/year TIC, $ million NPV, $ million IRR, % Simple payout, years

629.00 25.00 30.00 200.00 200.00 Price, $/bbl 46.93 65.37

1

2

3 4 5 6 LC‐FINING, Visbreaking RDS, RF RFCC Delayed Co Coker delayed coker LC-MAX, E-Gas LC-MAX LC-SLURRY –––– –– –––– –––– –––– –––– –––– –––– –––– –––– –––– –––– –––– –––– –––– –––– –––– –––– –––V –Vol olum ume, e, b/ b/d d –– –––– –––– –––– –––– –––– –––– –––– –––– –––– –––– –––– –––– –––– –––– –––– –––– –––– –– 175,000 175,000 175,000 175,000 175,000 175,000 175,000 175,000 175,000 175,000 175,000 175,000 175,000 175,000 –––––––– –––– –––––––– –––––––– –––––––– –––––––– –––––––– –––––––– –––––––– –––––Vo –Volume, lume, tonn tonne/ye e/year ar –––– –––––––– –––––––– –––––––– –––––––– –––––––– –––––––– –––––––– –––––––– –––– 299 707 353 349 608 333 321 108 535 368 546 — 663 551 — 182 — — — — — — — — — 1,224 — —

–––––– ––– ––––– ––––– ––––– ––––– ––––– ––––– ––––– ––––– ––––– ––––– –––––– –––––– ––– Vo Volum lume, e, ton tonne ne/ye /year ar ––– ––––– ––––– ––––– ––––– ––––– ––––– ––––– ––––– ––––– ––––– ––––– ––––– ––––– –––– –– 108 315 162 146 118 118

60 60 52 52 47 53 50 178 365 301 360 456 358 373 — — 1,161 — — — — — — — 516 — — — — — — — — 367 — –––––––––––––––––––– –––––––––– –––––––––––––––––––– ––––––––––––––––– ––––––– Volume, thousand b/d –––––––––– –––––––––––––––––––– –––––––––––––––––––– ––––––––––––––––– ––––––– — 12.6 14.6 16.1 14.3 14.3 14.9 108.5 162.0 117.4 119.1 127.5 117.7 117.7

58.78 60.41 36.12 37.97 26.12 —

7 .2 117.9 111.0 — — Base

— 182.1 — — 6.7 698.4

— 200.3 — — — 503.4

— 212.4 — — — 779.9

— 220.1 — — — 978.6

— 220.1 — — — 808.8

— 221.0 — 4.1 — 797.9

— — — —

— — — —

3,283 1,393 25.5 4 .7

2,363 994 25.4 4.7

3,597 1,646 26.6 4.6

4,929 1,771 23.3 5.0

3,594 1,817 28.3 4.4

3,341 1,950 30.8 4.2

change to lower-sulfur crude is possible, higher pricing for these crudes typically makes th is a costly option. reduce the sulfur content of produced fuel • Investing to reduce oil to continue serving the bunker fuel market.  Investments in process options should be carefully evaluated based on differentials in pricing of low-sulfur fuel oil (LSFO) vs. HSFO. • Exiting the fuel oil market completely.   Many refiners are considering implementation of bottom-of-the-barrel upgraders to produce more low-sulfur distillates, including marine diesel. The changes outlined by IMO will have repercussions for many refiners, particularly in the Asia Pacific region where much of the world’s bunker fuel is produced. Refiners will need to consider available investment options to remain profitable as the market for HSFO is eliminated. Desulfurization of atmospheric or vacuum residues remains the predominant technology available for producing 0.5 wt % LSFO from residues and is widely used throughout the Asia Pacific region. Proper integration of atmospheric or vacuum residue residue desulfurization into an existing refinery can offer additional processing benefits that can improve return on investment. Using this technology to produce LSFO with less than 0.1 wt % sulfur to comply with proposed regula-

62

118

tions for ECA compliant fuels, however, will be difficult and impractical. Refiners seeking to exit the fuel oil market are considering several available bottom-of-the-barrel technology options.

Technology overview  In addition to traditional bottom-of-the-barrel technologies such as atmospheric residue desulfurization and delayed coking, Chevron Lummus Global (CLG) developed the LCFINING technology platform—consisting of LC-FINING, LC-MAX, and LC-SLURRY technologies—for technologies—for improved residue conversion and selectivity towards high-value distillate products. Some of the major benefits of CLG’s technology platform include: • Ebullated catalyst beds developing mini minimal mal pressuredrop buildup. • Recycle pump at the bottom of the reactor creating nearly isothermal reactor conditions. • High-level conversion to dist distillate illate products. • High onstrea onstream m factor. The technology platform has been further enhanced by recent features:

Oil & Gas Journal | Apr. 2, 2018

TECHNOLOGY

TECHNOLOGY

• Integrated hydrotreating simplifies the fractionation and production of finished clean products. • Integrated two-stage hydrocracking maximizes the amount of high-value distillates produced from the unit, including selective cracking to produce Euro V diesel. • An interstage separator in the reaction reaction section considerably increases conversion and per-train capacity by reducing the vapor superficial velocity and gas hold hold-up -up in the reaction section.

Continuing advancements  To address the IMO regulations taking effect January 2020, CLG recently patented a new process focused on producing finished LSFO L SFO.. LC-LSFO is an enhancement to the LC-FINING technology platform that produces low-sulfur bunker fuel from unconverted residue oil. LC-LSFO applies the process technology developed for LC-SLURRY to unconverted residue vacuum tower bottoms (VTB) and atmospheric tower bottoms (ATB). The processed VTB-ATB is then treated in a fixed-bed reactor with CLG’s hydrotreating catalyst. CLG’s LC-LSFO pilot unit has operated using 27 different feeds in more than 30 different operating conditions, improving on the already high-conversion LC-FINING process, with the last unconve unconverted rted barrels converted to low-sulfur bunker fuel or used as feedstock to an RFCC unit.

Figs. 1-2 show flow schemes for ATB and VTB upgrading, respectively. This article examines the potential economic benefit of various modified refinery configurations incorporating these technologies in a typical t ypical 350,000-b/d 350,000-b/d Asia Pacific refinery.  A 50-50 blend of Arabia Arabian n Light and Arabia Arabian n Heav Heavyy crudes was assumed for all cases in the accompanying economic analysis. These crudes were selected because they are processed throughout the world but especially in the Asia Pacific region, where a large portion of the world’s bunker fuel oil is produced. Fig. 3 shows the base-case configuration for a refinery equipped with a visbreaker visbreaker.. The authors evaluated six modified refinery configurations and the benefits associated with each of these variations (see accompanying box). In each case, the existing visbreaker unit was replaced with one or more bottom-ofthe-barrel technology options. Figs. 4-9 show simplified block-flow block-flow diagrams diagram s of the six modified refinery configurations.

Economic evaluation  Platts data from 2015 provide the price basis for economic analysis, togethe togetherr with CLG’s internal projections for LSFO and HSFO pricing following the IMO sulfur reduction to maximum 0.5 wt %.

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TECHNOLOGY

CASE 2: DELAYED COKER Arab Light, Heavy crude   Naphtha blend Crude, vacuum distillation Distillates unit; 16 million VGO tpy

FIG. 5

Benzene NHT, CCR, BTX

Existing

Raffinate

Revamp

C7, reformate

New

Case 1: RDS, RFCC integrated with new distillate hydrotreater, alkylation unit.

C3   VGO HDS

DS VGO

Vacuum residue Hydrocracker

C4 FCC, gas plant

UCO

Alkylation

Alkylate

FCC gasoline Slurry oil LCO

Diesel Distillate hydrotreater Naphtha Delayed coker

HT jet HT diesel

LCO

Light-cycle gas oil (LCGO) Heavy-cycle gas oil (HCGO)

Coke

Natural gas, RFG

H2 plant

H2

CASE 3: LC-FINING, DELAYED COKER Arab Light, Heavy crude   Naphtha blend Crude, vacuum distillation Distillates unit; 16 million VGO tpy

FIG. 6

Benzene NHT, CCR, BTX

LC-FINING Distillates, unit VGO UCO Naphtha Delayed coker

DS VGO

Hydrocracker

UCO

HT VGO Distillate hydrotreater

HT jet HT diesel

LCO

HCGO

Anode coke

64

New

C4 FCC, gas plant

Alkylation

FCC gasoline Slurry oil LCO

Alkylate

The RDS, RFCC process configuration is used to enhance production of gasoline or LSFO (Fig. 4). Investment in this process configuration depends on feed metals (e.g., nickel, vanadium), as processing high-metal crudes requires larger catalyst volumes to achieve desired product qualities, increasing project cost and deteriorating overall economics. Though typical RDS units have frequent turnaround cycles (every 6-15 months), units can be designed with multitrain, independent RDS modules to maintain RFCC capacity during catalyst changeout, increasing onstream factor and refinery profitability. This configuration is particularly attractive when economics favor a high-gasoline yield.

Case 2: Delayed coker, new distillate hydrotreater integrated with new hydro-  cracker. Delayed cokers have the b enefit of eliminating fuel oil production. This configuration has the lowest investment cost of the options evaluated (Fig. 5). Distillate products require extensive hydroprocessing, however, and large quantities of low-value fuel grade coke are typically produced. Future environmental regulations also may impact profitability of this processing unit.

Diesel

LCGO

Natural gas, RFG

Revamp

C7, reformate

Vacuum residue Naphtha

Existing

Raffinate

C3   VGO HDS

Case descriptions

H2 plant

H2

Case 3: LC-FINING, delayed coker inte-  grated with new distillate hydrotreater, hydrocracker. LC-FINING uses CLG’s ebullated-bed reactor technology, allowing for an improved onstream factor (3+ years) compared to traditional fixed-bed reactors. The combined LC-FINING and delayed coking process configuration results in very high vacuum-residue conversion (typically 6085%), eliminates fuel oil production, and minimizes coke production (Fig. 6). This process produces high-value anode coke as opposed to the fuel coke produced by a delayed coker-only configuration. This option can be particularly attractive as an addition to an existing coking refinery planning to

Oil & Gas Journal | Apr. 2, 2018

TECHNOLOGY

TECHNOLOGY

CASE 4: LC-MAX, E-GAS

FIG. 7

process more or heavier crudes.

Case 4: LC-MAX, E-Gas unit integrated with new distillate hydrotreater, hydro-  cracker. LC-MAX is an improvement on LCFINING technology, integrating a solvent deasphalting (SDA) unit with LC-FINING ebullated-bed reactors (Fig. 7). Inclusion of the SDA section enhances unit reliability, reduces required reactor volumes and catalyst additions, increases residue conversion, and improves product quality. LC-MAX is capable of extremely high vacuum-residue conversion (typically 80-90%) and eliminates fuel oil and coke production. The unconver ted residue from the LC-MA X unit, along with imported coal-coke, can be converted into a hydrogen-rich synthesis gas for substitute natural gas production or power generation using E-Gas gasification technology.

Case 5: LC-MAX integrated with new distillate hydrotreater, hydrocracker. This proposed configuration is similar to Case 4 but excludes the E-Gas gasification unit (Fig. 8). Without the E-Gas unit, highquality asphalt is produced. This option requires substantially reduced capital investment compared with Case 4.

Case 6: LC-SLURRY integrated with new distillate hydrotreater, hydrocracker. LC-SLURRY achieves nearly full conversion of vacuum residue (95%+) and eliminates low-value slurry oil and coke production (Fig. 9). The LC-SLURRY process uses LC-FINING ebullated-bed reactors integrated with a catalyst recovery unit, which filters out the catalyst from the bottoms oil in a series of diluent-added filter loops. The spent catalyst is then sent offsite for metals reclamation. LC-SLURRY is currently the only slurry technology to demonstrate long-term 90%+ vacuum residue conversion with little to no fouling due to the unique characteristics of its ISOSLURRY catalyst. This process also demonstrates superior selectivity and product quality at the same conversion level as compared with thermal slurry hydrocracking processes.

Oil & Gas Journal | Apr. 2, 2018

TECHNOLOGY

Arab Light, Heavy crude   Naphtha blend Crude, vacuum distillation Distillates unit; 16 million VGO tpy

Benzene NHT, CCR, BTX

Existing

Raffinate

Revamp

C7, reformate

New C3

  VGO HDS

C4

DS VGO

FCC, gas plant

Vacuum residue

Alkylation

Alkylate

FCC gasoline Slurry oil

Hydrocracker

UCO

LCO

Diesel HT VGO

Naphtha LC-MAX unit

Distillates, VGO

Distillate hydrotreater

HT jet HT diesel

LCO

Natural gas, RFG UCO

Imported coke, coal

E-Gas gasification

H2

H2 plant

H2

CASE 5: LC-MAX Arab Light, Heavy crude   Naphtha blend Crude, vacuum distillation Distillates unit; 16 million VGO tpy

FIG. 8

Benzene NHT, CCR, BTX

Existing

Raffinate

Revamp

C7, reformate

New C3

  VGO HDS

C4

DS VGO

FCC, gas plant

Vacuum residue Hydrocracker

UCO

Alkylation

Alkylate

FCC gasoline Slurry oil LCO

Diesel HT VGO

Naphtha LC-MAX unit

Distillates, VGO

Distillate hydrotreater

HT jet HT diesel

LCO

Natural gas, RFG

H2 plant

H2

UCO

65

TECHNOLOGY

 Alongside providing a payout period of 5 years or less, the cases deBenzene Arab Light, liver large improvements in refinery Existing Heavy crude Raffinate margins while eliminating the refiner’s Revamp NHT, CCR, Naphtha blend BTX C7, reformate exposure to the dwindling HSFO marCrude, New vacuum ket. The optimal option for any refiner C3 distillation Distillates will be based on a variety of factors unit; C4 Alkylate 16 million VGO Alkylation DS VGO such as initial cost, natural gas availVGO HDS FCC, tpy gas FCC gasoline ability, and environmental factors. Vacuum plant The delayed coker configuration Slurry oil residue UCO (Case 2) requires the least amount LCO Hydrocracker of investment but also provides the Diesel smallest revenue increase over the HT VGO base case. A simi lar payout period can HT jet Distillate be realized with the higher-cost investhydrotreater HT diesel Naphtha ment options of RDS with RFCC (Case LCO 1) and LC-FINING with delayed coker LC-Slurry Distillates, VGO (Case 3). Cases 1 and 3 have notably unit higher net present values (NPV) and H2 Natural gas, RFG H2 plant similar internal rates of return (IRR) as compared with Case 2. UCO to low-sulfur fuel oil (LSFO) LC-MAX (Case 5) and LC-SLURRY (Case 6) options report the most favorable economics of the cases evaluated  Assumptions used to develop these economic estimates with similar investment requirements as Case 1 and Case included: 3. While LC-MAX with E-Gas (Case 4) is the most capitally • Project life, 15 years. intensive option and has the longest payback period, it may • Interest rate, 8%. be a desirable option if natural gas prices are high or avail• Inflation, 2%/year. ability is scarce. • Investment escalation, 2%. Fig. 10 shows a comparison of the different configura• Initial feed inventory, 5 days. tions based on each respective configuration’s potential to • Owner’s costs, 10% of total investment cost (TIC). create value. (Capital efficiency hurdle is the ratio of NPV-to• Contractor risk-profit, 5% of TIC. capital expenditure at present value.) Table 2 summarizes results of this evaluation, including  While an individual operator will undoubtedly have its assumed crude a nd product prices. own minimum hurdle by which it evaluates different prospective projects, CLG’s pilot studies show that both LC-SLURRY and LCMAX technologies have the potential VALUE CREATION FIG. 10 to more than double the returns gener2.5 ated by using a single technology configuration (e.g. delayed coking). CASE 6: LC-SLURRY

FIG. 9

LC SLURRY LC MAX

2.0    $   n 1.5   o    i    l    l    i   m  ,    V    P 1.0    N

LC MAX-GSFR

LCF-DCU

1. “Ships face lower sulphur fuel requirements in emission control areas from 1 January 2015,” International Maritime Organization, Briefing: 44, December 23, 2 014.

RDS-RFCC DCU

 r d l e  c y h u  n   e  i  c 0.5  a l e f fi  C a p i t 0 1.0

1.5

2.0

2.5

3.0

3.5

4.0

References 

4.5

5.0

Present-value investment, million $

66

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TECHNOLOGY

The authors Tayseer Abdel-Halim (tabdelhalim@chevron. com) is vice-president of Chevron Global Technology Services Co. Before joining Chevron, he served as director of heavy oil at KBR Inc. Abdel-Halim has more than 46 years’ experience in heavy oil, hydrogen production, and corporate planning. He holds an MS (1975) in chemical (refining) engineering from the University of Tulsa. Matthew Yu ([email protected]) is a technical service engineer for Advanced Refining Technologies (ART), a joint venture betwe en Chevron Corp. and W.R. Grace & Co., where he supports clients using ART’s premium atmospheric residue desulfurization catalyst technology. He previously worked as a process design engineer for both Chevron Lummus Global and Chevron’s refinery in Richmond, Calif. Yu holds a B S (2010) in chemical engineering from the University of California at Davis.

Manuscripts welcome Oil & Gas Journal editors are happy to consider for publication manuscripts about exploration and development, drilling, production, pipelines, LNG, and processing (refining, gas processing, and basic petrochemicals). These papers may be highly technical in nature and appeal or they may analyze oil and natural gas supply, demand, and markets. OGJ accepts manuscripts submitted exclusively to it or those adapted from oral and poster presentations. An Author Guide is available at www.ogj.com; click “Home,” then “Submit an article.” Or, contact Christopher Smith, Managing Editor—Technology ([email protected]; 713/9636211; or, fax 713/963-6282), Oil & Gas Journal, 1455 West Loop South, Suite 400, Houston TX 77027 USA.

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TECHNOLOGY

BEYOND

B A C K -T O - B A S I C S :

PROCESS

PRINCIPL ES

AND

CONCEPTS —5

Understanding how distillation trays work Norman P. Lieberman

Process Improvement Engineering Metairie, La.

 A distillation tray is used to mix vapors and liq“Welcome, Norman, to the Eternal Life,” Stokes uids together. The better the mixing, the more effiannounced to me cordially. “Can we answer any ciently the tray works. Tray efficiency also depends questions?” on two other factors: how well the droplets of en“Well, yes, Mr. Stokes. I’m interested in entraintrained liquids are separated from the vapor’s flow ment. On earth, this is a big problem affecting fracPROCESSING rising from the tray deck and how well the bubtionation efficiency. I assume it’s also a problem bles of vapor are separated from the liquid f lowing here in the Eternal World. Can you tell me, then, down from the tray deck through the downcomer. what factors increase entrainment?” Regarding tray fractionation efficiency, the latter Stokes explained several main factors that imfactor is of secondary importance. The former factor—i.e., pact entrainment. These include: entrainment—is of primary importance. It’s what Stokes’s • Droplet size. The smaller the drop, the greater the rate of law is all about. entrainment. • Viscosity of the continuous phase. High viscosity promotes entrainment. Entrainment, tray efficiency   As a young man, I would often dream of meeting my child• Density difference between the vapor and liquid phases. hood heroes: Nikola Tesla, Daniel Bernoulli, Isa ac Newton, Reduced density difference promotes entrainment. Sir George Stokes. • Velocity. Higher velocities promote entrainment as well. On one occasion, I dreamed that I’d passed on to my eter“I’ve actually reduced all thes e factors into a simple equanal and heavenly home and was welcomed by my famous tion,” Stokes explained with a smile. “I call it Stokes’s law.” colleagues and fellow scientists. Mathematically, we say entrainment i s proportional to V x (D V ÷ DL)0.5, where V = velocity of vapor phase, D V = density of vapor phase, and DL = density of liquid phase. “But Mr. Stokes,” I objected, “how about viscosity and the GENERAL INTRODUCTION droplet size?” “Well, Norman, the droplet size is usua lly unknown. VisGeared to young and seasoned professionals alike, “Beyond cosity of a vapor phase is usually small, and I normally neback-to-basics: Process principles and concepts” is a new glect it. By small, I mean less than 0.3 cp.” series of articles designed to present a straightforward ap“That’s all quite interesting. But if I could take a single proach to mastering the principles and concepts all process step to suppress entrainment, which is a source of evil on engineers should be able to apply without the need of a earth, what would you recommend?” computer. “The best option would be to avoid high localized velociWhile simulations and models are useful for examining ties of the vapor phase. Norman, I would also…” long-term operational issues, they cannot replace the di“Wait a bit, Mr. Stokes!” Nikola Tesla interrupted. “Mr. mension of human logic and reason required when tackling Lieberman has arrived in Eternity prematurely. He’s being the array of complex—and sometimes life-threatening— deported at once, back to his earthly home in New Orleans.” situations that occur in process plants. Using experiences from the author’s more than 50-year career in the process industry, articles in the series will provide approaches to understanding core process concepts in ways that will equip the engineer to walk out of an office, into a plant, and directly resolve process deficiencies via small operational changes or simple retrofits. This is the fifth article in the series.

68

Liquid entrainment, fractionation  Originally, the process of distillation did not utilize trays. It relied on pots (Fig. 1). The pots, which were very large, completely separated the liquid phas e from the vapor phase before the liquid and vapor left each pot. That is, there was no entrainment. Each pot was an individual separation stage. If the sepa-

Oil & Gas Journal | Apr. 2, 2018

TECHNOLOGY

TECHNOLOGY

and the tray above gets smaller, it takes less vapor velocity to blow the liquid from the lower tray up to the tray above. For example, let’s say that I’m separating propane from butane. My propane product (i.e., LPG in 5-gal containers sold in Walmart) has a max imum butane spec of 2%. If the vapor rate flowing up through a tower increases, the droplets of liquid from a lower tray will be entrained and blown up to the tray above. As the liquid in the lower tray is rich in butane, the entrained droplets will increase the butane content of the upper tray. Eventually, as the entrained droplets reach the top tray, the overhead LPG propane product will be contaminated w ith butane. Thus, fractionation efficiency is reduced.

SAFETY NOTE: INSPECTING REFINERY DISTILLATION TOWERS Most refinery distillation towers will be fouled with iron sulfide. The black, fine material that you find hard to wash off your hands is not normally coke but iron sulfide. Iron sulfide will not autoignite until it dries out. When it does dry, it will begin to burn at ambient temperatures, and the sulfide deposits will tend to smolder rather than flare up. The heat liberated is relatively small, as the sulfides burn with a pale blue flame not visible in sunlight. The danger is not he at, but sulfur dioxide (SO2) liberation in a confined space. SO2 is deadly at 1,000 ppm. It will kill you just as fast and efficiently as hydrogen sulfide. I’ve almost learned this deadly lesson from personal experience on two occasions. In general, refinery distillation towers should be chemically cleaned for iron sulfide removal before the tower is opened for inspection. Note that iron sulfide is not water soluble. Citric acid is one solvent that can safely remove iron sulfide deposits.

ration of vapor and liquid phases was perfect, the pot had a separation, or stage efficiency, of 100%. The more pots that were arranged in serie s, the greater the degree of separation that could be achieved between the two products. In our case, we are try ing to separate propane and butane as efficiently as possible. To avoid the expense a nd mechanical complexity of dozens of these pots, the distillation column was invented about 180 years ago. Each tray is intended to represent a pot, or at least a portion of a pot. If the tray rea lly is working as well a s a pot, it’s said to have 100% tray fractionation efficiency. If the tray is only working half as well as the pot, it is said to h ave a 50% tray efficiency. The usual cause of low tray efficiency is entrainment due to excessive vapor velocity.  As the distance between the liquid level on the tray below

THREE-STAGE PRIMITIVE DISTILLATION UNIT Cooling water (CW)

CW

Feed

Bottoms product, butane

Heat

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TECHNOLOGY

Heat

Foam  The fluid on a distillation tray deck is not actually liquid but foam or froth. The vapor bubbling up through the holes on the tray deck mixes with the liquid from the tray above to form foam. The foam overflows the low dam into the downcomer (Fig. 2). If the downcomer is too small, however, the foam fills up the downcomer and backs up onto the tray above it. The foam level on the tray then increases. As the froth or foam level increases on the tray, so does the height of the entrained liquid, or spray height.  When the spray height from the tray below reaches the tray above, tray fractionation efficiency becomes worse due to entrainment.

Reflux  More reflux improves tray fractionation efficiency. The trays work harder and better due to the increased vapor and liquid traffic on the tray decks. The problem is that the reflux comes from the vapor generated by the reboiler. If there is too much vapor flow through the tray decks, then t he vapor velocity may become excessive. According to the law of Mr. Stokes, my mentor in the Next World, this will cause excessive spray height, or entrainment. FIG. 1 It’s rather like exercise, where too CW much running actually can be bad for one’s health. Too much reflux and too much reboiler heat are going to make fractionation efficiency worse rather Overhead product, than better due to entrainment. propane Of course, you can’t just increase the reflux rate without more reboiler duty because the reflux i s just condensed vapor generated from the reboiler that rises through the trays, through the overhead condenser, and into the tower’s reflux drum. Heat

Downcomer backup  Downcomers often back up onto the

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TECHNOLOGY

tray above, causing a high froth or foam level on t he tray and a consequent entrainment of droplets of liquid to the tray above the tray draining into the downcomer. Usually, it’s not the downcomer itself that has too small an area. It’s more typically because the downcomer is too short. The height of foam in the downcomer is mainly a consequence of the pressure drop of the vapor flowing through the tray above the downcomer (Fig. 2). As the vapor flows through this tray, it undergoes a pressure drop due to the restriction of the caps, or orifices, on the tray deck and the weight of the liquid on the tray deck. In other words, the pressure of the vapor below the tray pushes up the foam height in the downcomer. Once the downcomer becomes full of foam, the foam backs up onto the tray above that downcomer. The extra weight of foam on the tray deck then increases the pressure drop of the vapor through that tray deck, which in turn increases the force pushing up the liquid out of the downcomer. The problem feeds upon itself until the tower’s trays above the tray where the problem began start to operate in a state called “fully developed flood.”  A tray downcomer can also fill with foam because it can’t drain out of the downcomer fast enough. This common problem is most often caused by a too-small downcomer clearance (Fig. 2). A reasonable downcomer clearance is usually 2-3 in. Any clearance less than 1.5 in. is likely to result in downcomer flooding and liquid backup on the tray above. Unfortunately, if the downcomer clearance is greater than the tray’s outlet dam height, the downcomer will also back up onto the tray above. This is called unsealing of the downcomer. Vapor will blow into the bottom of the downcomer and displace the liquid f low, resulting in fully developed flood.  As you read this section, keep in mind that the downcomer is full of frothy foam and not the denser liquid phase. Hence, this foam is rather easily displaced by the vapor flowing up through an unsealed tray downcomer. DISTILLATION-TRAY ENTRAINMENT Weir

Foam

Downcomer clearance

70

Downcomer

BENEFIT OF VALVE-CAP TRAYS Valve caps are supposed to act as check valves to retard liquid leakage through tray decks. This appears not to be the case. The valve caps don’t seem to appreciably reduce tray deck leakage. What they certainly do in refinery dirty services is to stick to the tray decks. This restricts vapor flow and pushes up the foam level in the downc omer, causing the tray to flood. My practice is to us e a grid-type tray. This is like a valve tray, but the cap is in a fixed position. It’s more or less the same as a sieve tray but with about 10-15% more capacity.

Tray efficiency 

Certainly, tray fractionation efficiency is reduced by entrainment, which is also called jet flood. Most tray efficiency problems, however, are caused by tray decks that are not level. The liquid on the tray deck may leak through the perforations on the trays in those areas which are lowest. The vapor flow will be concentrated at the highest tray deck areas. This all results in vapor-liquid channeling, which is bad for tray vapor-liquid contacting efficiency. The out-of-levelness of a tray that will cause a large loss in tray fractionation efficiency is related to t he pressure drop of the vapor flowing through the tray deck holes or valve c aps. If the low points of a tray (i.e., portions of the tray deck below the tray support ring) are less than the pressure drop of the vapor flowing through the tray deck perforations, then the liquid will leak through the tray deck and fail to come in good contact with the vapor flow. To calculate the pressure drop of the vapor through the tray perforations, use the following equation: DP = K x (D V ÷ DL) x V 2 = inches of liquid, where D V, DL = density of vapor, liquid; V = hole velocity, fps; K = 0.3 (sieve trays); K = 0.9 (valve-cap trays); and K = 0.6 (grid-type trays). FIG. 2  Valve caps do not appreciably retard the tendency of liquid to leak through the tray deck panels. Bubble-cap trays would retard the liquid leakage through Tray deck the tray decks, but are unfortunately seldom used in a modern distil lation tower Entrainment (see accompanying box). I asked Mr. Isaac Newton while I was awaiting my transport back home from the After Life about why bubble caps were no longer used in hydrocarbon distillation service. Foam “Norm,” Isaac explained, “the answer is that there is no answer. That goes also for Downcomer the meaning of life. Only God knows.”

Oil & Gas Journal | Apr. 2, 2018

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Subsea pipeline projects advance in 2018 Christopher E. Smith Managing Editor, Technology

Even with offshore field development having slowed in the wake of the 2014 oil TRANSPORTATION price collapse, a variety of subsea pipeline projects are underway. Each meets producers’ need to rationalize the paths by which their hydrocarbons get to market, some of the larger natural gas projects taking land-based production to landbased consumers even as growth at both ends of the LNG market accelerates.  What follows is a regional breakdow n of the more significant offshore pipeline projects.

Europe  Nord Stream 2 is a 1,200 km, 55-bcmy natural gas pipeline

system crossing the Baltic Sea from Russia to Germany (Fig. 1). It will use 48-in. OD pipe following roughly the same path as Nord Stream, placed into service by Gazprom in 2012 and operating at 93% of its SPECIAL own 55-bcmy capacity. REPORT Nord Stream in January 2018 received the construction and operation permit required to lay roughly 55 km of pipe through German territorial waters to landfall near Greifswald. Nord Stream expects to start construction in 2018. But new legislation in Denmark could prohibit construction in its territorial waters and route alternatives are bei ng developed. More than 70% of the roughly 200,000 pipe joints required for the project had been produced as of January 2018.  Allseas will perform pipelay. Statoil SA is building two pipelines to export production from its Johan Sverdrup development to shore. Gas will trav-

NORD STREAM 2

FIG. 1

Oslo

FINLAND Vyborg

NORWAY Helsinki

St. Petersburg Baltic  Sea 

Stockholm North  Sea 

Ust-Luga

Tallinn ESTONIA SWEDEN

   m     2    a    e    r    m     t    a     S    e    r     t    d    r     S    o    d     N    r    o     N

DENMARK Copenhagen

RUSSIA

Riga LATVIA RUSSIA

LITHUANIA Vilnius

Greifswald

GERMANY

RUSSIA

BELARUS

POLAND 0 0

Miles Km

100 161

Minsk

Atlantic  Ocean 

Operating gas pipelines Nord Stream 2

Source: Gazprom

72

Oil & Gas Journal | Apr. 2, 2018

TURKSTREAM

FIG. 2

UKRAINE

MOLDOVA

Sea of  Azov 

ROMANIA

RUSSIA Krasnodar Anapa

Russkaya CS Bucharest

Beregovaya CS

Black Sea 

    m    a    e     r      t      S    e     u      l      B

 t r e a m  T u r k S

BULGARIA

RUSSIA

Atlantic  Ocean 

GREECE

Luleburgaz

TURKEY

Istanbul 0 0

Miles Km

100 161

Samsun

Operating gas pipelines TurkStream Prospective gas pipeline Compressor stations

Source: Gazprom

el 156 km through 18-in. OD pipe to a hot-tap connection to the Statpipe system and continued shipment to Karsto. Oil will use a 283-km, 36-in. OD pipeline to reach Mongstad. Saipem’s Castorone will perform pipelay in 2018, using pipes fabricated in Japan by Nippon Steel & Sumitomo Metal Corp. DEA Norge AS will move gas produced at its Dvalin field to the Heidrun development via 14.9 km of 12-in. OD pipe, from which it will travel another 7.5 km to a tie-in with the Polarled trunk line. Dvalin production is expected to begin in 2020. In an effort to expand and diversify export routes for its natural gas to Europe, Gazprom is building the TurkStream pipeline across the Black Sea from the Russkaya compressor station near Anapa to Luleburgaz, Turkey (Fig. 2). The 1,090-km TurkStream will follow the route of the onceplanned South Stream pipeline for 660 km and a new 250km corridor toward European Turkey for the balance of its subsea route.  Allseas Pioneering Spirit is laying the 32-in. OD pipe, having reached Turkish waters in November 2017. Gazprom expects the first of two 15.75 bcmy strings to enter service in 2019, supplying domestic Turkish demand. Gas from the second string will continue to southern and southeastern Europe. The 878-km Trans Adriatic Pipeline (TAP) will transport natural gas sourced from the Shah Deniz II field in the Caspian Sea through an interconnection with the Trans Anato-

Oil & Gas Journal | Apr. 2, 2018

TECHNOLOGY

lian Pipeline (TANAP) at Kipoi on the Greek-Turkish border, crossing Greece, Albania, and the Adriatic Sea (115 km) before landfall in southern Italy. The offshore section will use 36-in. OD pipe, the onshore 48. First gas deliveries to Italy are targeted for 2020. Construction was two-thirds complete as of February 2018. TAP is owned by BP (20%), SOCAR (20%), Snam (20%), Fluxys (19%), Enagas (16%), and Axpo (5%).  An EU-funded study is underway regarding building a 159-km natural gas pipeline between Gela, Italy, and Delimara, Malta, connecting the island nation to the European gas grid via Sicily. The 22-in. OD pipe would move 2 bcmy, with a planned construction start in 2020 allowing first shipments by 2024. Malta is also studying the feasibility of building LNG bunkering infrastructure in conjunction with the project. Middle East   At least two projects are under consideration to move gas from the Leviathan field offshore Israel and Cyprus to European markets. The first of these is IGI Poseidon SA’s Eastern Mediterranean (EastMed) pipeline project. The 10 billion cu m/year (bcmy) system would move produced gas to Cyprus for processing before shipping it to Greece via Crete (which would extract 1 bcmy). Israel and Turkey are also negotiating a 10-bcmy pipeline to move Leviathan gas to Turkey and, via interconnection with TANAP, the European gas grid. The line would use 292 miles of 24-in. OD pipe. Saudi Aramco in November 2017 signed agreements to-

73

TECHNOLOGY

SUR DE TEXAS-TUXPAN

FIG. 3

Texas MEXICO

Matamoros

Tamaulipas Sur de Texas-Tuxpan

Altamira

Pacific  Ocean 

Tuxpan

Pacific  Ocean 

MEXICO  

Gulf of  Mexico 

0 0

Miles Km

200 322

Source: TransCanada Mexico

taling $4.5 billion for assorted oil and gas projects. Included among these were what Aramco terms free flow pipeline packages allowing an early start to development of the Haradh gas increment program. The packages will total 450 km of pipeline, installed by early 2019 to deliver 290 MMscfd of free-flowing gas from Haradh field to Hawiyah gas plant and allow sustained production until compression plants are complete. China Petroleum Pipeline Co. w ill complete the work.  Abu Dhabi-based National Petroleum Construction Co. will install 25.5 km concrete-weight coated 30-in. OD trunkline between the new TP-21 platform in the Persian Gulf and the onshore Safaniya GOSP-1 gas-oil separation plant. Saudi Aramco and Bahrain Petroleum Co. (Bapco) in 2018 plan to finish work on a 350,000 b/d crude oil pipeline. The line will move Saudi crude to Bahrai n for refining, replacing an older 230,000 b/d line. The expansion coin-

74

cides with expansion of Bapco’s Sitra refinery. The pipeline will use a variety of pipe diameters (12, 18, and 22-in. OD) over its 115 km, 74 of which will be on land and the other 41 offshore in the Persian Gulf. National Iranian Gas Export Co. is studying building a pipeline to Oman to export natural gas for both consumption in Oman and conversion to LNG. The 380-km pipeline would feature a 180-km offshore stretch. A gas supply agreement between the two countries calls for shipment of 28 million cu m/day, roughly two-thirds of which would be consumed locally. Initial gas flows planned for 2019 depend on the start of construction.

The Americas 

TransCanada Corp. and Sempra Energy’s Sur de Texas-Tuxpan natural gas pipeline will move 2.6 bcfd of USsourced gas to Mexico using a subsea route beginning off Brownsville, Tex., Gulf of  Mexico  and Matamoros, Mexico, and running south to Altamira and Tuxpan (Fig. Veracruz 3). It will supply Comision Federal de Electricidad (CFE) power generation plants with fuel. Gas will feed into the pipeline from a line between the Agua Dulce hub in Nueces County, Tex., and Brownsville. The line will also interconnect with the Tuxpan-Tula pipeline to supply CFE powerplants to the west. It will use 500 miles of 42-in. OD pipe. Construction began in Altamira in May 2017 with an estimated completion time of 30 months.  Williams Cos.’ Northeast Supply Enhancement natural gas project includes a 23.5-mile, 26-in. OD loop into NY waters of Raritan Bay from Middlesex County, NJ. Williams subsidiary Transco will operate the pipeline as part of its system and expects to h ave it in service in time for the 201920 winter heating season. BP Trinidad & Tobago (BPTT) will use a 21-km, 26-in. OD pipeline to export up to 600 MMcfd of dry natural gas from its Angelin project to the 14.8-mtpy Atlantic LNG plant in Point Fortin, sending liquids to the Galeota term inal. Angelin lies in 65 m of water. Pipeline construction is expected to be complete in 2019.

Other projects   A few other large projects are in various stages of discussion but have not yet moved to development. Edison SPA

Oil & Gas Journal | Apr. 2, 2018

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Oil & Gas Journal | Apr. 2, 2018

76

APRIL

reports the 8 billion cu m/year (bcmy) Galsi pipeline delivering gas from Algeria to Italy as expected to go on stream in 2018. A feasibility study on the 890-km pipeline was completed in 2005 but work on the system has yet to begin. The system would include two sections: an international section from El Kala, Algeria, to Porto Botte in southern Sardinia (310 km) and a domestic section running overland from Porto Botte to Olbia (300 km) and subsea from Olbia to Piombino, Tuscany (280 km). Edison says the leg between Algeria and Italy would be the deepest subsea pipeline ever built, with a maximum depth of 2,885 m. Two offshore pipeline projects would compete to bring gas from the Middle East to India: one starting in Iran, the other in Oman. The 1,200-km pipeline from Iran would largely parallel the shoreline between the two countries and serve as a substitute for the onshore Iran-Pakistan pipeline which India pulled out of under US pressure. Gazprom has expressed interest in building the pipeline, but would like to supply gas to Pakistan as well via Gwadar. South Asia Gas Enterprise (SAGE) envisions building a 1,300-km, 1.1bcfd capacity pipeline through deep water between Oman and India. Construction between a compressor station in Oman and a terminal in Gujurat, India, would take 10 years. Iranian gas sourced from Chabahar could also be shipped through this pipeline. Talk of building a pipeline between Oman and India has been occurring since at least the mid-1990s (OGJ, Aug 1., 1994, p. 27). The Morocco-Nigeria Gas Pipeline (MNGP) would carry Nigerian natural gas to Morocco via an offshore route beginning in Ghana as an extension of the already-operating West Africa Gas Pipeline. The roughly 4,000-km pipe is discussed as a replacement for the long-muted Trans-Saharan Gas Pipeline to provide a non-LNG alternative for moving Nigerian production to European markets.

2018

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OGPE.COM

OIL, GAS &petrochemequipment

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 W H A T ’ S N E W F O R O N S H O R E & O F F S H O R E : U P S T R E A M , M I D S T R E A M , D O W N S T R E A M O P E R A T I O N S

Offshore Technology Conference Edition

Gas analyzers serve well surface logging Real-time, high-resolution geosteering RockView technology is announced “to make real-time, highresolution geosteering possible for the first time.” The new service uses measurements gathered from a full range of sensors on COLT and POLARIS BHAs to enable more accurate wellbore placement plus tangible decrease in footage drilled out of zone. RockView helps avoid difficulties in predicting exact target reservoir position from the surface. AnTech Ltd.: Exeter United Kingdom

PetroAlert® Model 9200 Gas Analyzer combines selective detection of a gas chromatograph with continuous monitoring abilities of a total hydrocarbon analyzer. It performs fast (<30 sec) C1 - C5 analysis at a detection limit of <10 ppm as methane while monitoring total hydrocarbons from 0.003 to 100% as methane — during drilling. AMETEK MOCON-Baseline: Lyons CO For FREE Information, select #2 at ogpe.hotims.com

For FREE Information, select #1 at ogpe.hotims.com

Rotary steerable for high-volume shale drilling RSS™ Rotary Steerable Scout is new and specifically designed for high-volume shale drilling: vertical, nudge, tangent, and lateral well profiles with continuous rotation from the surface. The new electronic control module with a digital mud valve (patent pending) is housed in a slow-rotating housing for isolation from high shock, vibration, stick-slip, and torsional oscillations. RSS™ is fully mud operated. It is built on the proven and latest mechanical Vertical Scout ® measurement and control electronics platform developed by Sanvean Technologies® embedded into the tool to deliver precise steering control. Scout Downhole Incorporated, Turbo Drill Industries Inc. : Conroe TX For FREE Information, select #3 at ogpe.hotims.com

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New Products & Services

Pipeline leak detection services Instrumented and optical fugitive methane emission surveys monitor well site or gathering and boosting station components within each company-defined area. Among services: patrol surveillance within high-pressure pipeline transmission corridors for fugitive emissions, changes in areas of high consequence, or complex cross-overs. Red Hen Systems: Fort Collins CO For FREE Information, select #4 at ogpe.hotims.com

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OG&PE Vice President/Group Publisher  

Editor

Paul Westervelt  J.B. Avants

Production Director

Charlie Cole

Production Manager

Shirley Gamboa

Art Director Digital Audience Development Manager Social Media Marketing Analyst Marketing Manager

On-demand & low-volume manufacturing, fast-turn & advanced prototyping services On-Demand Manufacturing Services comprise a broad range of processes and technologies from prototyping through production. In addition to traditional manufacturing and investment casting patterns — a number of additive manufacturing ser vices are offered. These include stereolithography, selective laser sintering, direct metal printing, colorjet printing, and fused deposition modeling. Free literature offers complete details. 3D Systems Corporation: Atlanta

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Clark Bell Jim Cowart Anna Alaback Myla Lowrance

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Italy Ferruccio & Filippo Silvera Tel. 39 02 28 46716 [email protected]

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For FREE Information, select #6 at ogpe.hotims.com United Kingdom , Scandinavia, The Netherlands and The Middle East Graham Hoyle + 44 1934 733871 [email protected]

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Germany, Switzerland, Russia, Austria, and Eastern Europe Andreas & Wilhelm Sicking 49 0 2903-3385-70 [email protected] Singapore Michael Yee +65 9616 8080 [email protected]

Subsea electrical network integrity monitoring V-IR Network Integrity Monitoring System is newly developed to provide more cost effective subsea fault-finding to minimize maintenance and repair. The multi-LIM improves IR visibility by dividing a subsea network into monitored sections. It uses V-SLIM subsea line integrity monitoring nodes at strategic network points — installed using divers or underwater ROVs. Full details are yours free. Viper Innovations Ltd.: Portishead, Bristol United Kingdom For FREE Information, select #7 at ogpe.hotims.com

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D&L Oil Tools . . . . . . . . . . . . . . . . . . 3 SENSONICS Ltd. . . . . . . . . . . . . . . . . 9

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Need Reprints of your ad or recent editorial? Contact Jill Kaletha at Mossberg & Co. for a quote: 800 428 3340 x149 / [email protected]

Graco High Pressure Equipment Company . . .7 S. Himmelstein and Company. . . . . . . . . .4 MOXA . . . . . . . . . . . . . . . . . . . . . .5  Advertiser Product & Service Followup . . . . 10 Oilfield Improvements. . . . . . . . . . . . . .6 38th ILTA Conference & Tradeshow . . . . . 11 For Print / Online Advertising Information, Assistance: http://www.ogpe.com/index/advertise.html

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April 2018

Oil, Gas & Petrochem Equipment makes every reasonable effort to verify its content. However, neither Oil, Gas & Petrochem Equipment nor our parent firm, PennWell Corporation, assume responsibility for validity of manufacturer claims or statements made in published items.

NEW GETS IT RIGHT. Our new family of retrievable tubing anchor/catchers provides bi-directional holding power with full bore opening allowing for increased annular flow and capillary tube bypass area. Increase production with revolutionary Trilobite Hydro and Quarter Turn

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 New Products & Services

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 New Products & Services

Industrial flow energy solution is all-in-one complete, with three advanced technologies

Platform delivers self-service capabilities, simplifies creation of AI-driven applications

Manage and optimize flow measurement in facilities of all sizes with new Big-3™ flow energy solution. It comprises QuadraTherm 640i/780i thermal flow meters, InnovaMass 240i/241i vortex flow meters, and new InnovaSonic 207i ultrasonic flowmeter. Big-3™ shares the same Raptor firmware and many of the same software apps.  As a complete, accurate solution, it’s designed for compressed air, natural gas, steam, or hot and chilled water flows. The configuration helps facilities engineers avoid challenges of dealing with an assortment of companies to obtain the right instrumentation required for flow energy measurement. Complete Big-3™ solution and components data are free. Sierra Instruments: Monterey CA

Maana “Q” is available to advance the core Maana Knowledge Platform with enhanced self-service capabilities. These enable subject matter-experts and business analysts to use the Maana Computational Knowledge Graph to develop a digital knowledge layer over operational and industrial data. Maana Exploration, Development, Production, Downstream, Trade and Finance, and Risk and Compliance Knowledge Platform serves broad and varied oil and gas sectors. These include well offset analysis, upstream exploration, digital connected wells, predictive maintenance, crude corrosion mitigation, reduced refinery corrosion via water-in-crude prediction, LNG demand/supply/pricing forecasts, well risk assessment, and HSE. Maana: Palo Alto CA

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The Right Torque Solution Now Will Save A Lot of Headaches Later Measuring and applying correct torque to equipment can prevent costly breakdowns and improve efficiencies in all types of drilling operations, such as:  Leg load balancing for jack-up oil rigs,  Torque monitoring and/or calibration of make-up/breakout machines,  Top drive torque measurement and control, in-line measurment of  torque as PMI of motors, pumps, compressors and more,  Load distribution and balancing for  winches and hoists, and  Measure actuation torque for valves. For over 50 years, all Himmelstein torque measurement devices have been proudly engineered and manufactured in the USA. Contact us to learn how our experience and solutions can help you

MCRT  ®  39000X

The MCRT 39000X has been certified by both ABS and DNV to become a standard for oil fielduse. All devices ship with an ISO 17025 accredited calibration.

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April 2018

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3-phase power quality loggers simplify tasks Fluke 1740 Series Power Quality Loggers simplify how you collect and report utility power quality trends. Compact designs are used to study and monitor utility PQ and demand to industry standards. They offer advanced data aggregation and analysis to save time, reduce manpower, and eliminate errors associated with traditional data collection. 1740s are fully IEC 61000-4 30-compliant and meet Class A requirements. Models can simultaneously log more than 500 parameters for each averaging period. This allows technicians to analyze power quality in detail and to correlate intermittent events with detailed waveform data to identify disturbance root causes. Fluke Corporation: Everett WA For FREE Information, select #11 at ogpe.hotims.com

HiP-manufactured air-driven liquid pumps Sprague Hydraulic Pumps are manufactured with specific pressure ranges and configurations to meet a broad range of high-pressure demands. The positive-displacement pumps convert air-drive pressure into hydraulic discharge pressure with outputs up to 36,500 psi. Models maintain a liquid-air balance indefinitely in a holding condition with minimal energy consumption and no increase in fluid temperature or parts movement. Complete Sprague Hydraulic Pumps specifications and information are yours free. HiP: High Pressure Equipment Company: Erie PA For FREE Information, select #12 at ogpe.hotims.com

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OGPE.com

Products New Products & Services

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Products New Products & Services

Engineering and pipeline integrity management services with cross-functional global resources

Vibration accelerometers monitor combustion turbines that burn NG to generate electricity

Complete engineering and pipeline integrity management services are available to “leverage cross-functional global resources to customize project plans so clients and their assets stay protected, productive, and profitable.” The Integrated Engineering team supports complex pipeline and facilities projects which require multiple mechanical to civil/  structural and electrical/controls disciplines. They provide comprehensive, turnkey designs critical to safe, reliable operation. The Integrity Management team ensures asset integrity and longevity as it protects, maintains, and monitors assets. It performs in-line inspection, pressure testing, direct assessments, serves cathodic protection, and enables compliance. The Operational Services Team provides comprehensive services that integrate quality and preserve the life of client assets via capabilities that include pipeline design and construction management utilizing trenchless technologies. Lake Superior Consulting: Duluth MN

Models 357A94 & 357A95 charge accelerometers offer 1,200°F. extreme service as differential output designs with a UHT-12 sensing element and integral hardline cable terminating in a 7/16-27 two-pin connector. They monitor vibration of combustion turbines that burn natural gas to generate electricity. Model 357A94 has an axis of measurement parallel to the direction of the mounting screw, while Model 357A95 has an axis of measurement perpendicular to the direction of the mounting screw. Both feature new UHT-12 proprietary crystal technology sealed in a hermetic package for long-term reliability. With UHT-12 there is no pyroelectric output to ensure accurate lowfrequency measurements as well as reduced thermal noise spikes to eliminate false alarms during monitoring. Complete accelerometers specifics are yours free. PCB Piezotronics Incorporated: Depew NY

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Software offers live port pressure & fracture gradient monitoring GEOSuite is released with a number of updates including live pore pressure and key usability enhancements. Key features of the pore pressure monitoring surveillance workflow include predrill model creation using seismic velocities, real-time PPFG calculation from a choice of methodologies, end of well PPFG presentati on with interpreted PP profile, and automated PPFG daily report. GEOSuite features a range of methodologies for PPFG calculation and top hole pseudo-density options and composite density curve facility. Among updates are curves to easily compile composite curves and easily turn display on/off. Geologix Limited: Norwich United Kingdom For FREE Information, select #17 at ogpe.hotims.com

Oil, gas, water fibre optic pipeline leak detection monitoring Hawk FOS: fibre optic leak detection systems help oil, gas, or water pipelines avoid undetected leakage and its environmentally and financially damaging risks. They utilize an in-field fiberoptic cable which not only tells you about leak occurrence but gives accurate location of any potential leakage. This enables very rapid in-field assessment and repair. FOS combines multiple measured sound, temperature, and vibration variables within one cable to automatically cross reference and remove false signals. Multivariable sensing detects changes in temperature caused by liquid or gas movement in pipe leaks; sound and vibration from pipe leaks or third-party intrusions; and change in stress / strain experienced due to pipe bending or loss of support. Hawk Measurement: Nunwading Australia, Lawrence MA For FREE Information, select #18 at ogpe.hotims.com

April 2018

New Products & Services

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New Products & Services

Ejectors entrain gas, produce micro-bubbles for oil-in-water separation Liquid-driven ejectors are available to accommodate produced water where they help quickly remove oil from process streams. They entrain gas to produce ultra-fine bubbles — microbubbles — at targeted size ranges to improve oil-in-water separator efficiency, notes the manufacturer. Using a micro-bubble ejector as a secondary stage in oil/water separation yields a low maintenance solution to provide reduction in running costs. Full micro-bubble ejectors data are free. Transvac Systems Ltd.: Derbyshire United Kingdom For FREE Information, select #19 at ogpe.hotims.com

Breather valves accommodate valve sizes well  An increased number of breather valve configurations are announced to best fit valve size with an application — to reduce oversizing and number of valves needed to fulfill requirements. Their design is taken from automotive and lean manufacturing philosophies to deliver more flow performance with easy maintenance via better access to internal parts. Models are designed to work in combination with this manufacturer’s flame arresters so less spare parts are needed and upgrade to higher performance is provided. FNC Tank Protection Division, Fabbrica Nazionale Cilindri S.p.A: Cisalog Italy.

OGPE.com

Thermal flow meters feature new data logger Model FT4X thermal mass flow meters for oil and gas processing feature a new data logger which records flow rate, totals, as well as other events and alarms. Data logger features: 40 daily totals, settable contract time that defines the Contract Day, time/date stamped alarm and event logs, seven-year history, power off totalizer, density display, and gross heating value based on selected gas composition. FT4X’s Gas-SelectX provides an expanded selection of gases from three menus: O&G for C1 - C9+, nitrogen, and CO2 gases to mix in 0.1% increments, pure gas for 11 common gases, and mixed gas for 11 common gases available to mix in 0.1% increments. Fox Thermal Instruments Incorporated : Marina CA For FREE Information, select #21 at ogpe.hotims.com

Extreme Conditions & Pressures

For FREE Information, select #20 at ogpe.hotims.com

Optical gas imaging camera guidebook Information and tips to help you get the most of optical imaging cameras is provided in a new and free guidebook . Explained is how OGI cameras use spectral wavelength filtering and Stirling cooler cold-filtering technology to visualize infrared absorption of such gases as methane, sulfur hexafluoride, carbon dioxide, carbon monoxide, and Freon refrigerants. Petrochemical and chemical operations incorporate OGI technology for safer, more efficient ‘Smart LDAR’ (Leak Detection and Repair) programs. Inspectors can quickly detect fugitive emissions and leaks to pinpoint the source immediately. This leads to prompt repairs, reduced emissions, and greater regulations conformity. FLIR Systems: Meer Belgium For FREE Literature, select #250 at ogpe.hotims.com

Nobody Does it Better Count on our proven  valves, fittings & tubing for ALL  your oil, gas & petrochem needs

High Pressure  Equipment Company  HiP…Our Name is High Pressure Erie, PA • USA • 814.838.2028 • HighPressure.com  For FREE Information, select #407 at ogpe.hotims.com

April 2018

OGPE.com

New Products & Services

P7

OGPE.com

New Products & Services

Free tank farm foundations, solutions literature

High-angle release connectors

This free brochure illustrates and summarizes tank farm foundation project successes. Presented is how the company “engineers the ground, making a solid foundation using smart and efficient methods, fast and worth the money.” Terminal petrochemical tank, universal terminal, and tank farm ground improvement successes are shown and summarized. Four foundation techniques are presented and diagrammed: deep vibro, deep-soil-mixing, compaction grouting, and rigid inclusions. The company also offers Soilfrac existing tank remediation Process. Keller Holding GmbH : Offenbach Germany

Xtreme Release Connectors are high-angle designs to enhance safety and reduce environmental risks, with time and money savings — by increasing a vessel’s operating window. By having no maximum disconnect angle, Xtreme also allows a vessel’s crew enough time to respond to challenging scenarios without risk of getting stuck to a wellhead or damaging the connector if they do no react fast enough. Subsea Technologies Ltd. : Aberdeen For FREE Information, select #25 at ogpe.hotims.com

For FREE Literature, select #252 at ogpe.hotims.com

Premium connections alternative Top seal is barrier to produced sand rust that negatively affects insert pumps The SandBlaster Top Seal helps prevent particles from collecting at the bottom of the annular space between the working barrel and production tubing. Four ports above the fins continually flush away any buildup. The seal provides a barrier to produced sand and rust against insert pumps. Since most production tubing is not perfectly round and has some rust or scale buildup SandBlaster Top Seal’s Viton fins conform to tubing ID regardless of shape or condition. This creates a barrier to solid particles. Hydostatic pressure equalizes on both sides of the fins so particles are not forced past SandBlaster. Kajon Oil Tools : Houston For FREE Information, select #23 at ogpe.hotims.com

TEC-LOCK semi-premium connection is introduced as an alternative to premium connections. It is engineered to surpass API performance guidelines and features close-tolerance plus wedge-style thread forms Designed for extended reach horizontal wells that require high bending plus compressive and torsional resistance — TEC-LOCK BTC and BTC-S minimize connection stresses They also eliminate the open ‘J’ area to create a flush ID for turbulent free flow and reduced tool hang-ups. They are available 4.5 to 9.625 in. for multiple make and break capabilities.  When used with their manufacturer’s SealLube thread sealant, TECK-LOC Wedge provides a gas leakproof seal on a product without a metal-to-metal seal. It’s available 4.5 to 7 in. Hunting Energy Services : Houston For FREE Information, select #26 at ogpe.hotims.com

Small, tablet with ruggedized touch screen newly announced to serve in dirt, extremes MTB-7 Tablet is announced with ruggedized touch screen for use in challenging, dirty, extreme conditions. This IP68 and Mil-STD 810G water, dirt, smoke and dust-rated tablet comprises full  Windows operating system so an entire data collection process can be carried out from start to finish. Fast processor, light weight, and ergonomic design also offer minimal fatigue. MTB-7 also provides 7-in. extra-bright PCAP touchscreen display plus all-day/up to 15-hr battery. Complete tablet details are free. Chassis Plans: San Diego For FREE Information, select #24 at ogpe.hotims.com

P8

Hazardous location 4-20 mA transmitter sensors meet I.S. standards LORD 4-20 mA hazardous location transmitter sensors meet current global intrinsically safe standards. The CS, ATEX, and IECEx transmitters allow you global reach to benefit from reduced inventory since you can stock fewer part numbers, it’s noted. The new certification expands this company’s I.S. offerings to nearly all pressure, temperature, load/force/torque, and external 4-20 mA transmitter amplifier designs with a single set of universal electronics. LORD Sensing, Stellar Technology: Cary NC For FREE Information, select #27 at ogpe.hotims.com

April 2018

New Products & Services

OGPE.com

OGPE.com

New Products & Services

Quick connection sensor + cable system = overfill prevention

Power sensitive fluidic control in oil tools offered by new valve

Scully Connect overfill prevention system is now on the market. The patented new quick connection sensor and cable design combines proven optic sensing technology with pre-wired connections. These features save time, eliminate mis-wiring and bypassing sensors to deliver dependable, trouble-free connections to prevent downtime. Scully Connect also eliminates the need for tools and allow quick sensor replacement in minutes. Additional overfill prevention specifics are free. Scully Signal Company: Wilmington MA

This new Magnetically Latching Solenoid Valve serves power sensitive fluidic control in oil tools or where control systems would benefit from reduced power consumption and lower heat generation. These valves are unlike traditional solenoid designs which require continuous voltage to be activated from their natural state, and therefore consume more energy. Magnetically latched design requires only a momentary pulse to switch and remain ‘in-state’ (open or closed). Permanent magnets within the valve’s coil consume less than 1 joule of energy to be activated (and remain switched on). This compares to standard spring loaded 12-v solenoid valves with 26 ohm coil which would require around 5.5 w to open and about 0.35 w to hold in open position. Lee Products Ltd.: Bucks United Kingdom

For FREE Information, select #28 at ogpe.hotims.com

Stainless pressure regulators, valve boosters To support offshore production or other corrosive environments, a new line of stainless steel pneumatic pressure regulators and volume boosters is available. The entire product line comprises rugged construction, use of corrosionresistant materials, with 316L stainless steel used in the housings. Regulators operate on supply pressure up to 290 psi and offer up to 500 scfm flow capacity volumes to regulate air, inert gas, or sweet and sour gases. Two large flow boosters handle up to 150 and 250 psig supply pressure respectively, to deliver an output pressure of up to 150 psig. ControlAir Incorporated: Amherst NH

For FREE Information, select #31 at ogpe.hotims.com

For Ultimate Machinery Protection Sentry G3 ticks all the right b oxes Vibration Monitoring

Turbine Supervisory

Overspeed Protection

For FREE Information, select #29 at ogpe.hotims.com

Rugged mobile touch computers XT100 touch computers are introduced to be “packed with every business-critical feature that enterprise organizations require.” The slim smartphone designs withstand repeated 4-ft drops to concrete and are sealed to IP65 standard for protection against water, dust, and extreme temperatures.  With support for the widely deployed  Android 6 operating system, XT100 provides intuitive user interface to reduce training time. Google Mobile Services certification ensures you have access to all Google  APIs including Google Play, Google Maps, and Google Chrome.  Janam Technologies LLC: Woodbury NY For FREE Information, select #30 at ogpe.hotims.com

Universal module for all vibration, p osition, speed and temperature measurements Fully independent channel signal processing & alarm function Colour LCD display for trend & alarm historian, plu s FFT display

Protect your critical plant and equipment with a system that offers the best function and features... ...Sentry G3 from Sensonics

 Tel: +44 (0) 1442 876833 [email protected] 

www.sensonics.co.uk  For FREE Information, select #409 at ogpe.hotims.com

April 2018

OGPE.com

Advertiser Product & Service Followup and New Equipment

        8         3         9             6         1          B          A

P9

OGPE.com

Advertiser Product & Service Followup and New Equipment

March “Advertiser Product & Service Followup” Companies featured on the upper portion of this page advertised their equipment, product, system, or service specialties in the March 5 Oil & Gas Journal’s OG&PE Section. These summaries provide opportunities to request free information or literature: Go to OGPE.com — Click ‘PRODUCT INFO’ (white type at top of website) to receive response from these highly valued Manufacturer and Service Provider Media Partners.

Your Industrial IoT, Simplified

Intrinsically Safe Test Tools

UC-8112-ME-T-LX data loggers deliver easy Modbus data acquisition, MQTT support and 4G LTE routing. The highly versatile and programmable 4G LTE Modbus data logger gives developers what they want to get their Industrial IoT applications up and running quickly. The instruments are engineered to withstand extreme temperature without cooling fans or heaters. They support Moxa’s easy-to-use ThingsPro Suite. MOXA.com MOXA: Brea CA

Protect yourself and your team with Fluke Intrinsically Safe Test Tools — because one spark is all it takes. Fluke offers the world’s broadest line of intrinsically safe test tools designed to increase safety without sacrificing performance. Rugged, reliable Fluke tools are designed to go where other tools can’t — so you can troubleshoot and calibrate more, without sacrificing uptime. Find out more about Fluke I.S. Test Tools. Fluke.com/EX Fluke Corporation: Everett WA

For FREE Information, select #33 at ogpe.hotims.com

For FREE Information, select #34 at ogpe.hotims.com

Flame resistant NFPA 2112 whole-garment-certified coveralls  Announced to “address the specific needs of workers in the energy industry,” are these60621 / 61621 Red Wing FlashGuard flame resistant coveralls. Designs meet EN ISO 11612, EN 1149-5, IEC 61482-1-2, Class 1 and are NFPA 2112 Whole Garment Certified. Not only do the coverall meet and/or exceed safety and durability performance — they feature one of the lightest, breathable FR finished weights on the market. This includes the Hazard Risk Category 2 arc rating. Among FlashGuard clothing wearer advantages: shoulder pleats with full 360° range of movement, radio loops, chest pockets, plus concealed exterior-to-interior side access pockets. Red Wing Safety: Red Wing MN For FREE Information, select #35 at ogpe.hotims.com

Swing-down-designed emergency eyewashes, safety showers  Just announced is Optimus Swing-Down Laboratory Eyewashes — second generation product line that adds aerated Optimus spray heads and swing-down valves for fast, easy activation. Seven new lab products offer configuration for virtually any application as they minimize space needed and deliver maximum safety protection. Optimus Swing-Down Eyewash and Safety Shower features include upgraded swing activated valve, aerated 2.6-gpm @ 30-psi eyewash spray, plus ANSI / ISEA Z358.1 certification. Speakman Company: New Castle DE For FREE Information, select #36 at ogpe.hotims.com

Thinner, lighter passive fire protection materials introduced New Firestop fire-resistant material is announced as “thinner and lighter than any current passive fire protection materials available to the market.” Easily molded and extruded in all shapes and profiles, Firestop minimizes fire escalation. The certified rubber-based material offers dampening and noise reduction to safeguard equipment from vibration, collisions, explosions, and earthquakes. This is in addition to its basic and important benefit to protect personnel and to give responders time to gain control of a fire. The next-generation material’s newly formulated compound also reduces costs and lead time to customers. Trelleborg offshore operation: Houston For FREE Information, select #37 at ogpe.hotims.com

P10

April 2018

38th A N N U A L INTERNATIONAL OPERATING CON FE REN CE & TRAD E SH OW HOUSTON, TEXAS MARRIOTT MARQUIS HOUSTON GEORGE R. BROWN CONVENTION CENTER

WHAT ATTENDEES SAID ABOUT ILTA’S 2017 EVENT:

Join more than 4,500 terminal industry professionals at the premier annual event for liquid terminal owners and aboveground storage tank operators. ILTA 2018 is the one place to attend informative conference sessions and in-depth training courses, as well as find innovative solutions and the latest technology from over 330 trade show exhibitors.

G R O U P D I S C O U N T S A VA I L A B L E

WWW.ILTA.ORG/AOCTS

SERVICES | SUPPLIERS

“The speakers were well  prepared and cognizant of time. I was able to learn a lot  about preventative maintenance  practices and standards.”  “This event is an amazing resource  for ILTA members.  I’ve been able to connect with so many individuals working in the terminal industry.”  “The number of exhibitors and their wealth of knowledge at ILTA’s trade show was impressive. I discovered a lot of new technology that is available to terminals.” 

SERVICES | SUPPLIERS THE ENERGY INDUSTRIES COUNCIL

SCHLUMBERGER

Celebrates 75 years  EIC trade association for companies that supply goods and services to the energy industries worldwide — celebrated its 75th Anniversary on March 15. It held an exclusive members’ afternoon tea at The House of Lords, hosted by Lord Popat and with special guest of honor Minister of State for Trade and Expor t Promotion, Baroness Rona Fairhead. Approximately 100 EIC members attended, representing companies of all sizes from across the full range of energy sectors, plus EIC staff and friends from industry and government. The EIC was founded in London in

Awarded 2,000-ton module contract  Noble Energy has awarded Schlumberger an engineering and supply contract for a 2,000-ton single-lift process module to be installed on the Leviathan Platform. Announced by OneSurface, Schlumberger President Mohamed Kermoud, scope of the contract includes pretreatment, salt removal, and generation of monoethylene glycol for reinjection in the subsea flowlines for hydrate inhibition. Schlumberger’s PUREMEG reclamation and regeneration system is a proprietary technology to be supplied as a single-lift module for installation on the production platform. Project management, engineering, fabrication, installation support, and lifeof-field activities will be managed by a globally integrated team.

BALDOR ELECTRIC COMPANY

1943 by 13 power supply chain companies wanting to diversify and export into oil and gas markets abroad. It has grown to include over 600 member organizations throughout oil and gas, power, nuclear, and renewables sectors. The EIC has a global network of seven offices: London, Aberdeen, Teesside, Dubai, Houston, Kuala Lumpur, and Rio de Janeiro.

BAKER HUGHES, MCDERMOTT Partner to compete offshore Baker Hughes, a GE company and McDermott International will partner to offer integrated offshore energy services to better compete with other growing players. Their first partnership will provide integrated front-end engineering work for British Petroleum’s Senegal and Mauritania West Africa developments. “Increasingly, industry players are looking for commercially-innovative business models and integrated offerings that help reduce costs as they increase efficiency and productivity,” said Graham Gillies, Baker Hughes, a GE company Vice President of Subsea Production Systems & Subsea Services.

77

SERVICES | SUPPLIERS

Is now ABB  ABB will integrate the Baldor Electric Company name into its global ABB b rand as part of its Next Level strategy which includes harmonizing different ABB-owned brands under the global ABB master brand. ABB Robotics and Motion Division President Sami Atiya noted Baldor, now ABB, will continue to manufacture, design, and market brands of Baldor-Reliance motors and Dodge mechanical power transmission products from 15 U.S. manufacturing locations. It will also continue to support ABB’s entire U.S. motors and generators business unit, including ABBbranded IEC motors, large AC motors, generators, and related services from the motors, generators, and mechanical business headquarters in Fort Smith, Arkansas.

In making the announcement, CEO Craig Feherty notes Tad began his career with Western Geophysical, working in surface seismic exploration and borehole seismic Bostick logging. He has held various field engineering, technical support, and product management positions. In his new role, he will lead the company’s operations and expand delivery of its FiberLine Intervention technology (FLI) in the region.

TURBOMACHINERY L ABORATORY Names new director  Dr. Eric Petersen has been named D irector of The Turbomachinery Laboratory, a center of the Texas A&M Engineering Experiment Station and part of The Texas A&M University System. The Nelson-Jackson Professor in the Department of Mechanical Engineering at Texas A&M University, is a 10-year Turbo Lab veteran. His Petersen research encompasses gas dynamics, propulsion, combustion, shock waves, chemical kinetics, optical diagnostics and spectroscopy, laminar and turbulent flames, and rocket combustion. He has authored more than 400 journal and conference papers in these areas. He holds three Mechanical Engineering Degrees. As Turbo Lab Director, Petersen will oversee all operations of the Lab and Symposia Office including industry and government-sponsored research, education, and workforce development initiatives including short courses and symposia.

OCEANEERING INTERNATIONAL WELL-SENSE Launches U.S. business, appoints director  Aberdeen-based downhole technology specialist Well-SENSE has launched WellSENSE Incorporated as a Houston-based subsidiary to bolster its United States presence. At the s ame time, Tad Bostick has been appointed Wes tern Hemisphere Commercial Director.

Acquires Ecosse Subsdea Ltd. An Oceaneering International Incorporated wholly owned subsidiary has acquired Ecosse Subsea Limited, provider of offshore engineering, seabed preparation, route clearance, and trenching services. The announcement was made by Oceaneering President and Chief Executive Officer Roderick A. Larson.

Oil & Gas Journal | Apr. 2, 2018

SERVICES | SUPPLIERS Ecosse enabling technologies acquired in the transaction include mo dular SCAR Seabed System which completes the entire trenching work scope, as well as its newly developed SCARJet trenching systems for use with standard work class ROVs. They add jetting and post-lay trenching capabilities to existing pre -cut methods offered by the SCAR plowing tools.

TECHNICAL TOOLBOXES

redesigned rail yard accommodates over 100 rail cars. This expansion, along with production capacity enhances, will improve logistics and allow quicker response to market demand.

 STATISTICS

“BIG PICTURE”  You’ve Been Seeking! 03%&3 50%":

FRAMES   Appoints CEO  Frans B. Roozendaal has been appointed Chief Executive of Frames by its supervisory board. He joined Frames’ management board March 1, replacing Jacques Melman who will continue to serve as Chief Operating Officer. Together with Ronald Vochteloo, who has been Chief Financial Officer since 2016, they will form Frames management board. The company deRoozendaal signs, builds, and delivers renewable energy and water solutions, separation technologies, oil and gas processing equipment, as well as flow control and safeguarding systems. It recently added CO2 capture, water treatment, biogas upgrade, and hydrogen applications to its portfolio.

 Names CTO  Drew Lafleur has been appointed Chief Technology Officer of Technical Toolboxes, global provider of integrated and cloudbased pipeline software, consulting, and industry training for pipeline engineering and technical professionals. The announcement is made by Martin Fingerhut, CEO. Based in Houston, Lefleur will lead and manage the company’s technical team. He will focus on company strategy to identify and prioritize development initiatives, Lafleur select technologies and methodologies to employ and set timetables for the evaluation, as well as development and deploy all Techni- EMERSON cal Toolboxes’ technology applications, Order-to-cash software selection  and technical training courses. New hydrocarbon liquids storage and logistics terminal in Mount Airy, Louisiana — Pin Oak Terminals LLC, has selected HEXION INCORPORATED Emerson’s Synthesis order-to-cash softCompletes proppant mfg. plant expansion  The Oilfield Technology Group of Hexion ware. Incorporated has completed its resin The scalable, enterprise-level logistics coated proppant manufacturing plant exmidstream solution integrates with the pansion in Sturgeon County, north of Fort terminals’ back of fice, commercial and Saskatchewan Canada. operational data. It will enhance customer service, which will help the facility achieve quick, accurate closing of each account period to enhance as set availability and reduce operational costs. The announcement is made by Pin Oak  Plant capacity and logistics capabilTerminals Chief Executive O fficer Mike ity have been significantly increased to Reed and Tengbeng Koid, President of the efficiently service the Canadian market, Energy Solutions business of Emerson. according to Jerry Kurinsky, Senior Vice President and General Manager. Working with CN Rail, their primary rail service provider, the expanded and

Oil & Gas Journal | Apr. 2, 2018

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 STATISTICS

IMPORTS OF CRUDE AND PRODUCTS — Districts 1-4 — — District 5 — ———— Total US ———— 3-16 3-9 3-16 3-9 3-16 3-9 3-17* 2018 2018 2018 2018 2018 2018 2017 ––––––––––––––––––––––––— 1,000 b/d ––––––––––––––––––––––––— Total motor gasoline ............. Mo. gas. blending comp..... Distillate............................... Residual .............................. Jet fuel-kerosine .................. Propane-propylene .............. Other ...................................

561 438 122 231 36 114 593

603 592 222 91 47 106 627

2 2 0 7 15 35 141

1 1 0 131 52 37 77

563 440 122 238 51 149 734

604 593 222 222 99 143 707

326 318 127 329 104 135 956

Total products ......................

1,657

1,696

200

298

1,857

1,997

1,977

Total crude...........................

6,087

6,411

990

1,174

7,077

7,585

8,307

Total imports ........................

7,744

8,107

1,190

1,472

8,934

9,579

10,284

Additional analysis of market trends is available through OGJ Online, Oil & Gas Journal’s  electronic information source, at http://www.ogj.com.

OGJ CRACK SPREAD

3-23-18* 3-24-17* Change Change, ———–—$/bbl ——–—— %

SPOT PRICES Product value Brent crude Crack spread

76.58 64.82 11.76

Product value Light sweet crude Crack spread

83.30 64.16 19.13

65.59 47.85 1 7.74

17.70 16.31 1.40

26.99 34.09 7.87

Product value Light sweet crude Crack spread

82.53 62.24 20.29

65.77 49.65 16. 12

16.76 12.59 4.18

25.49 25.35 25.92

Six month

EXPORTS OF CRUDE AND PRODUCTS

–––––––––––––––– Total US –––––––––––––––– 3-16-18 3-9-18 *3-17-17 ––––––––––––––– 1,000 b/d –––––––––––––––

Total products Total crude Total exports NET IMPORTS Total Products Crude

14.54 23.44 14.72 29.38 ( 0.18) (1.48)

FUTURES MARKET PRICES One month

*Revised. Source: US Energy Information Administration Data available at PennEnergy Research Center.

Finished motor gasoline Jet fuel-kerosine Distillate Residual Propane/propylene Other oils

62.04 50.10 11.94

686 359 997 192 1,041 1,718

785 133 1,492 330 809 1,613

*Average for week ending. Source: Oil & Gas Journal Data available at PennEnergy Research Center.

592 191 1,217 262 808 1,714

4,993 1,573 6,566

5,162 1,487 6,649

4,784 550 5,334

2,368 (3,136) 5,504

2,933 (3,165) 6,098

4,950 (2,807) 7,757

*Revised. Source: Oil & Gas Journal Data available at PennEnergy Research Center.

 CRUDE AND PRODUCT STOCKS

District

—–– Motor gasoline —–– Blending Jet fuel, ————— Fuel oils ————— PropaneCrude oil Total comp. kerosine Distillate Residual propylene ———————————————————————————— 1,000 bbl —————————————————————————

PADD 1 ..................................... PADD 2 ..................................... PADD 3 ..................................... PADD 4 ..................................... PADD 5 .....................................

12,736 111,757 232,961 22,462 48,389

59,668 58,775 83,784 8,082 32,756

55,188 52,592 73,837 6,285 30,631

8,860 7,439 12,881 804 10,993

44,933 31,532 38,128 3,740 12,711

6,938 1,890 18,923 257 4,737

3,263 9,882 22,384 1 1,230 —

Mar. 16, 2018 ........................ .. Mar. 9, 2018 ............................. Mar. 17, 20172 ..........................

428,305 430,928 533,110

243,065 244,757 243,469

218,533 220,542 218,877

40,977 41,581 41,828

131,044 133,066 155,392

32,745 33,416 39,572

36,759 38,820 44,334

1

Includes PADD 5. 2Revised. Source: US Energy Information Administration Data available at PennEnergy Research Center.

REFINERY REPORT—MAR. 16, 2018

District

REFINERY –––––– OPERATIONS –––––– Gross Crude oil inputs inputs ––––––– 1,000 b/d ––––––––

–––––––––––––––––––––––––––– REFINERY OUTPUT ––––––––––––––––––––––––––– Total motor Jet fuel, ––––––– Fuel oils –––––––– Propanegasoline kerosine Distillate Residual propylene –––––––––––––––––––––––––––––––– 1,000 b/d –––––––––––––––––––––––––––––––

PADD 1 .............................................. PADD 2 .............................................. PADD 3 .............................................. PADD 4 .............................................. PADD 5 ..............................................

944 3,658 9,088 650 2,667

940 3,654 8,992 655 2,536

3,106 2,534 2,342 323 1,626

85 246 834 37 542

266 1,073 2,510 205 449

22 41 246 13 85

175 454 1,001 1 210 —

Mar. 16, 2018 ..................................... Mar. 9, 2018 ....................................... Mar. 17, 20117 2 ..................................

17,007 16,687 16,183

16,777 16,367 15,801

9,931 10,097 9,730

1,744 1,766 1,635

4,503 4,478 4,828

407 463 407

1,840 1,890 1,763

18,550 Operable capacity

91.7% utilization rate

1

Includes PADD 5. 2Revised. Source: US Energy Information Administration Data available at PennEnergy Research Center.

79

Oil & Gas Journal | Apr. 2, 2018

 STATISTICS

 STATISTICS OGJ GASOLINE PRICES

OGJ PRODUCTION1 REPORT2

BAKER HUGHES RIG COUNT

Price Pump Pump ex tax price* price 3-21-18 3-21-18 3-22-17 ————— ¢/gal ————— (Approx. prices for self-service unleaded gasoline) Atlanta .......................... 188.5 238.0 Baltimore ...................... 190.8 243.0 Boston ........................... 196.0 240.9 Buffalo .......................... 189.3 252.0 Miami ............................ 194.0 253.9 Newark .......................... 192.4 247.9 New York........................ 200.3 263.0 Norfolk........................... 218.1 258.9 Philadelphia. ................. 178.8 255.9 Pittsburgh ..................... 184.9 262.0 Wash., DC...................... 234.1 276.0 PAD I avg .................. 197.0 253.8

211.9 222.4 217.9 229.4 217.9 219.4 242.9 240.4 229.4 241.0 238.9 228.3

Chicago ......................... Cleveland ...................... Des Moines .................... Detroit ........................... Indianapolis . ................. Kansas City ................... Louisville ....................... Memphis ....................... Milwaukee ..................... Minn.-St. Paul ............... Oklahoma City ............... Omaha .......................... St. Louis ........................ Tulsa ............................. Wichita .......................... PAD II avg .................

214.5 189.8 191.3 179.3 194.9 201.8 198.4 209.7 199.5 205.8 194.9 198.9 217.7 190.5 199.9 199.1

268.2 236.2 240.2 240.0 255.2 237.6 242.8 253.5 250.8 252.8 230.3 246.6 253.5 225.9 242.3 245.1

270.7 229.7 224.2 225.2 223.7 210.7 217.9 219.8 214.8 223.3 208.8 225.4 210.9 208.8 215.8 222.0

Albuquerque .................. Birmingham .................. Dallas-Fort Worth .......... Houston ......................... Little Rock ..................... New Orleans .................. San Antonio ................... PAD III avg ................

188.6 189.1 189.0 185.0 190.7 189.0 185.0 188.1

225.9 228.4 227.4 223.4 230.9 227.4 223.4 226.7

206.9 211.9 209.9 205.8 204.9 207.8 206.9 207.7

Cheyenne....................... Denver ........................... Salt Lake City ................ PAD IV avg ................

195.0 207.1 197.1 199.8

237.4 247.5 245.0 243.3

226.3 230.5 231.3 229.4

Los Angeles ................... Phoenix.......................... Portland ........................ San Diego ...................... San Francisco................ Seattle........................... PAD V avg .................

268.4 252.4 224.7 264.7 282.5 241.2 255.7

340.3 289.8 279.9 336.6 354.4 309.0 318.3

321.6 262.9 242.9 295.6 299.1 277.8 283.3

Week’s avg. .................. Feb. avg... ..................... Jan. avg......................... 2018 to date ................. 2017 to date .................

204.9 208.2 203.3 205.0 183.7

254.6 256.3 251.4 253.5 230.3

230.6 228.0 233.5 — —

3-23-18 Alabama............................................ Alaska ............................................... Arkansas ........................................... California .......................................... Land................................................ Offshore .......................................... Colorado............................................ Florida ............................................... Illinois............................................... Indiana.............................................. Kansas .............................................. Kentucky............................................ Louisiana .......................................... N. Land ........................................... S. Inland waters.............................. S. Land............................................ Offshore.......................................... Maryland........................................... Michigan........................................... Mississippi ........................................ Montana ............................................ Nebraska........................................... New Mexico........................................ New York............................................ North Dakota ..................................... Ohio................................................... Oklahoma.......................................... Pennsylvania ..................................... South Dakota..................................... Texas ................................................. Offshore .......................................... Inland waters.................................. Dist. 1 ............................................. Dist. 2 ............................................. Dist. 3 ............................................. Dist. 4 ............................................. Dist. 5 ............................................. Dist. 6 ............................................. Dist. 7B........................................... Dist. 7C........................................... Dist. 8 ............................................. Dist. 8A ........................................... Dist. 9 ............................................. Dist. 10 ........................................... Utah.................................................. West Virginia..................................... Wyoming............................................ Others NV-1.......................................

1 9 1 14 14 0 31 0 0 0 0 0 57 35 3 7 12 0 0 4 1 0 88 0 53 22 120 40 0 499 1 0 37 31 17 13 3 26 2 36 304 15 1 13 7 17 30 1

2 5 1 8 8 0 30 0 2 0 0 0 53 31 4 1 17 0 0 4 0 0 48 1 43 21 118 33 0 404 1 0 41 33 15 10 1 20 8 32 215 18 1 9 9 11 16 0

Total US ........................................ Total Canada ................................

995 161

809 185

Grand total ...................................

1,156

994

US oil rigs.......................................... US gas rigs........................................ Total US offshore ...............................

804 190 13

652 155 18

Total US cum. avg. YTD.....................

3-23-18 3-24-17 –—— 1,000 b/d —–—

3-24-17

964

(Crude oil and lease condensate) Alabama................................. 18 Alaska .................................... 515 California ............................... 488 Colorado................................. 433 Florida .................................... 6 Illinois .................................... 25 Kansas ................................... 99 Louisiana ............................... 1,569 Michigan ................................ 15 Mississippi ............................. 51 Montana ................................. 55 New Mexico............................. 575 North Dakota .......................... 1,230 Ohio........................................ 57 Oklahoma............................... 505 Pennsylvania .......................... 23 Texas ...................................... 4,337 Utah ....................................... 92 West Virginia.......................... 32 Wyoming................................. 237 Other states ........................... 61

20 524 498 295 6 23 101 1,530 16 51 58 440 1,016 49 440 16 3,664 88 22 201 38

  Total

9,096

10,423

1

OGJ estimate. 2Revised. Source: Oil & Gas Journal. Data available at PennEnergy Research Center.

US CRUDE PRICES 3-23-18 $/bbl*

  Alaska-North Slope 27° ......................................... Light Louisiana Sweet ........................................... California-Midway Sunset 13° .............................. California Buena Vista Hills 26° ........................... Wyoming Sweet ..................................................... East Texas Sweet................................................... West Texas Sour 34° .............................................. West Texas Intermediate........................................ Oklahoma Sweet.................................................... Texas Upper Gulf Coast ......................................... Michigan Sour ....................................................... Kansas Common ................................................... North Dakota Sweet ...............................................

*Current major refiner’s posted prices except N. Slope lags 2 months. 40° gravity crude unless differing gravity is shown. Source: Oil & Gas  Journal. Data available at PennEnergy Research Center.

WORLD CRUDE PRICES OPEC reference basket

Wkly. avg.

OPEC reference basket.......................

736

Rotary rigs from spudding in to total depth. Definitions, see OGJ Sept. 18, 2006, p. 46. Source: Baker Hughes Inc. Data available at PennEnergy Research Center.

Includes state and federal motor fuel taxes and state sales tax. Local governments may impose additional taxes. Source: Oil & Gas Journal. Data available at PennEnergy Research Center.

66.85 67.42 66.11 69. 92 68.23 69.77 65.85 65.74 66.36 59.14 68.81 63.53 69. 93

63.48 64.03 62.31 66.02 64.36 66.09 62.27 62.14 63.14 57.68 65.88 60.28 66.01

Fateh 32 -Dubai................................... Minas 34 -Indonesia ............................ Isthmus 33 -Mexico ............................. Brent 38 -UK ........................................ Urals-Russia ........................................

66.15 60.91 67.57 69.13 68.69

62.69 58.15 64.83 65.16 63.01

WTI/Brent ............................................. Brent/Dubai..........................................

(5.43) 2.98

(3.01) 2.47

Other crudes

�

�

�

�

�

Differentials

3-16-18 ¢/gal

 

IHS PETRODATA RIG COUNT 3-16-18 ¢/gal

Spot market product prices US Gulf of Mexico. . . . . . South 190.90 America 190.90 Northwest 196.10 Europe. . . . . West Africa. . . . . . 182.10 Middle East. . . . . . . Propane Southeast No. 2 heating oil Mont Belvieu .............. 80.50 New York Harbor ......... 185.90 Asia. . . . . . . Worldwide. . . . No. 2 Distillate Motor gasoline Low sulfur diesel fuel   (Conventional-regular) New York Harbor ......... New York Harbor ......... 181.40 Gulf Coast .................. 184.90 Gulf Coast.................. Los Angeles ................ Motor gasoline Kerosine jet fuel (RBOB-regular) Gulf Coast .................. New York Harbor ......... 210.70

Source: OPEC Monthly Oil Market Report. Data available at PennEnergy Research Center.

MAR. 23, 2018 Total supply of rigs

US NATURAL GAS STORAGE1

Marketed Marketed supply Marketed utilization of rigs contracted rate (%)

3-16-18

3-9-18

East.................................... Midwest.............................. Mountain............................ Pacific ................................ South Central Salt ................................ Nonsalt...........................

270 315 90 169 602 182 419

84

48

36

75.0

42

36

30

83.3

96

77

59

76.6

59

43

26

60.5

176

163

120

73.6

Total US .............................  

90 790

74 659

44 472

59.5 71.6

Total US2 ............................

Oil & Gas Journal | Apr. 2, 2018

 STATISTICS

Source: IHS Petrodata Data available in PennEnergy Research Center

3-16-17

Change,

314 350 93 169 606 186 420

317 513 137 207 938 299 639

(14.8) (38.6) (34.3) (18.4) (35.8) (39.1) (34.4)

1,446

1,532

(31.5)

Dec.-17

Dec.-16

2,112 Change, %

3,039

3,297

(7.8)

–——––—— bcf —––——–

1

Source: EIA Weekly Petroleum Status Report. Data available at PennEnergy Research Center.

$/bbl 3-23-17 65.08 –– Mo. avg., $/bbl –– Jan.-18 Feb.-18

Arab light-Saudi Arabia ....................... Basrah light-Iraq ................................. Bonny light 37 - Nigeria.. ...... ...... ...... .... Es Sider-Libya ...................................... Girassol-Angola.................................... Iran heavy-Iran..................................... Kuwait export-Kuwait ........................... Marine-Qatar........................................ Merey-Venezuela .................................. Murban-UAE......................................... Oriente-Ecuador ................................... Saharan blend 44 - Alge ria... ...... ...... .... �

*

REFINED PRODUCT PRICES

60.29 61.25 60.70 70.84 62.13 59.50 57.25 62.25 62.25 56.00 54.25 61.50 53.75

%

2

Working gas. At end of period. Source: Energy Information Administration Data available at PennEnergy Research Center.

80

 STATISTICS PACE REFINING MARGINS

WORLDWIDE NGL PRODUCTION

Jan. Feb. Mar. Mar. 2018 2018 2018 2017 Change ——––—––––— $/bbl –––––––––—— US Gulf Coast Composite US Gulf Refinery.............. Mars (Coking) .................................. Mars (Cracking) ............................... Bonny Light...................................... US PADD II Chicago (WTI)................................... US East Coast Brass River ...................................... East Coast Comp ............................. US West Coast Los Angeles (ANS) ............................ NW Europe Rotterdam (Brent) ............................ Mediterranean Italy (Urals) ...................................... Far East Singapore (Dubai)............................

11.55 10.73 10.40 11.78 11.22 10.63 8.75 8.35 7.66 6.47 5.87 5.67

11.76 11.53 9.15 6.63

(1.36) (0.90) (1.49) (0.96)

(11.6) (7.8) (16.3) (14.5)

14.02

11.15

(0.64)

(5.7)

9.24 10.51

12 month Change vs. average previous Dec. Nov. — production — —— year —– 2017 2017 2017 2016 Volume ————–—–––— 1,000 b/d ———––———— %

Change, %

6.80 8.55

5.60 7.29

4.92 6.50

5.40 7.02

(0.48) (0.52)

(8.9) (7.4)

9.73

11.89

15.93

13.36

2.57

19.2

Brazil................................... Canada................................ Mexico ................................. United States ...................... Venezuela ............................ Other Western He mis phe re . ...... ...... ...... ....

Western   Hemisphere..................

213

216

(3)

(1.5)

5,629

5,735

5,399

5,103

295

5.8

351 55

338 75

342 81

349 72

(6) 9

(1.8) 12.0

9

9

9

8

1

6.9

3.59

3.13

3.38

(0.25)

(7.4)

4.15

5.23

5.00

4.52

0.48

10.6

Western Europe .............

415

422

432

429

3

0.7

Russia ................................. Other FSU ............................ Other Eastern Europe ...............................

823 468

821 463

817 447

791 264

26 183

3.3 69.1

Eastern Europe ..............

1,306

1,300

1,281

1,071

210

Algeria................................. Egypt ................................... Libya.................................... Other Africa .........................

450 200 50 117

450 200 50 147

490 199 50 155

502 202 50 131

(12) (3) 0 24

(2.4) (1.2) 0.0 18.5

Africa..............................

817

847

895

885

10

1.1

Saudi Arabia........................ United Arab Emirates .......... Other Middle East................

1,880 681 860

1,878 679 841

1,867 670 841

1,838 646 739

29 24 102

1.6 3.7 13.9

Middle East.....................

3,421

3,398

3,378

3,223

155

4.8

Australia.............................. China................................... India .................................... Other Asia–Pacific ..... ...... ....

48 12 128 146

51 12 129 147

50 12 125 147

55 12 116 150

(4) 0 9 (3)

(8.0) 0.0 7.5 (1.8)

2,347 2,867 203 87 288 251 74 97 134 112 80 42

200 (7) 49 (16) 24 41

27,089 27,486 3,306 2,975 3,168 2,335 917 771 1,543 1,377 708 187

(397) 331 833 146 166 521

2,427 5 773 277 265 1 11

2,322 2,206 6 5 288 762 242 281 236 272 0 0 6 9

221 0 11 (5) (7) 0 2

26,863 26,663 56 57 3,559 3,325 3,039 3,006 2,960 2,917 1 1 78 88

200 (1) 234 33 43 0 (10)

2,838

3,205

242

33,563 32,796

767

Asia–Pacific ................... TOTAL WORLD .................

2,858

3,254

227

33,517 33,051

4,359 3,039

7,398

4,354 3,732

8,086

4,355 3,817

8,172

4,380 3,297

16

334 11,922

17

339 12,041

334 11,719

16

1

332 11,044

2 675

4.7

19.6

0.5 6.1

OXYGENATES

466

Dec. Nov. YTD YTD 2017 2017 Change 2017 2016 Change ———————––—––– 1,000 bbl –––—————————

2,477 (258)

7,677

15

Totals may not add due to rounding. Source: Oil & Gas Journal. Data available at PennEnergy Research Center.

NATURAL GAS IN UNDERGROUND STORAGE Dec. Nov. Oct. Dec. 2017 2017 2017 2016 Change —————————— bcf ——————————

Total gas

216

1.54

SUPPLY

Base gas Working gas

222

(133.6)

3,067 80 300 81 136 83

3,482

13.3 8.1 (9.0) 7.4 (5.9)

(1.67)

DEMAND

Total supply.....................

15 64 (28) 258 (12)

1.25

Dec. Total YTD Dec. Nov. Dec. 2017–2016 ––– YTD ––– 2017–2016 2017 2017 2016 change 2017 2016 change ——————————— bcf ——————––—————

  Production (dry gas) ........ Supplemental gas............ Storage withdrawal.......... Imports ............................ Canada.......................... Mexico ........................... LNG................................

116 791 304 3,478 198

1.17 (0.42)

DEMAND/SUPPLY SCOREBOARD

3,447

131 856 277 3,736 186

0.28

US NATURAL GAS BALANCE

Total demand ..................

135 910 241 4,054 179

Norway..... ...... ...... ...... ...... .... United Kingdom................... Other Western Europe ...............................

Source: Jacobs Consultancy Inc. Data available at PennEnergy Research Center.

Consumption ................... Addition to storage .......... Exports ............................ Canada ... ...... ...... ...... .... Mexico .......................... LNG ...............................

142 940 235 3,936 154

2,219

Source: DOE Monthly Energy Review. Data available at PennEnergy Research Center.

Fuel ethanol Production .................. Stocks.........................

32,809 23,048

32,469 22,863

340 185

MTBE Production .................. Stocks.........................

1,624 1,320

1,571 1,201

53 119

376,619 364,979 23,048 19,531

16,685 1,320

17,342 1,116

11,640 3,517

(657) 204

Source: DOE Petroleum Supply Monthly. Data available at PennEnergy Research Center.

US HEATING DEGREE–DAYS Nov. 2017

Oct. 2017

Nov. 2016

% change

— Total degree days YTD — 2017 2016

New England ................................................................ Middle Atlantic ............................................................. East North Central........................................................ West North Central ....................................................... South Atlantic .............................................................. East South Central ....................................................... West South Central....................................................... Mountain ...................................................................... Pacific ..........................................................................

746 702 774 806 323 408 179 487 351

237 214 292 363 89 147 59 355 178

672 609 582 569 290 339 154 513 331

11.0 15.3 33.0 41.7 11.4 20.4 16.2 (5.1) 6.0

4,866 4,248 4,492 4,779 1,700 2,109 1,078 3,747 2,694

4,875 4,378 4,535 4,529 1,977 2,422 1,308 3,694 2,402

US average*............................................................

491

193

418

17.5

3,035

3,096

% change (0.2) (3.0) (0.9) 5.5 (14.0) (12.9) (17.6) 1.4 12.2

(2.0)

*Excludes Alaska and Hawaii. Source: DOE Monthly Energy Review. NOTE: No new data at press time. Data available at PennEnergy Research Center.

81

Oil & Gas Journal  | Apr. 2, 2018

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Oil & Gas Journal  | Apr. 2, 2018

83

ADVERTISING SALES

ADVERTISERS INDEX

ADVERTISING SALES

ADVERTISERS INDEX

US Sales Mike Moss, (713) 963-6221, [email protected]. Stan Terry, (713) 963-6208, [email protected]. Grace Jordan, (713) 963-6291, [email protected]

COMPANY NAME

PAGE

COMPANY NAME

PAGE

Australia / New Zealand Mike Twiss, Miklin Business S ervices, Unit 15, 3 Benjamin Way, Rockingham, Western Australia 6168; Tel +61 8 9529 4466, Fax +61 8 9529 4488 Email: [email protected]

AFGlobal Corp

Brazil / South America

www.arca-valve.com

Paul Westervelt, (713) 449-6305, pwestervelt@pennwell. com. 1455 West Loop South, Suite 400, Houston, TX 77027

Ariel Corp

Canada

Atlas Copco Group

Stan Terry, (713) 963-6208, [email protected]

France / Belgium / Spain / Portugal /  Southern Switzerland / Monaco Stefy Picoitti Thompson, Tel +33 (0) 6 21 23 67 02, Fax +33 (0) 4 89 81 99 82,  [email protected].

Germany / Austria / Northern Switzerland /  Eastern Europe / Russia / Former Soviet Union Sicking Industrial Marketing, Kurt-Schumacher-Str. 16, 59872, Freienohl, Germany. Tel: 49(0)2903.3385.70, Fax: 49(0)2903.3385.82; E-mail: wilhelms@pennwell. com;  www.sicking.de  Andreas Sicking

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Flotek

C3

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United Kingdom / Scandinavia / Denmark /  The Netherlands / Middle East

Marketing Solutions

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www.diamondbackindustries.com

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Custom Publishing

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Deepwater Operations

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P7 7

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C4

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Pipeline Energy Expo

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Pipeline Week

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PNEC

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www.pnecconferences.com

PumpWorks

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S. Himmelstein & Company

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Saudi Aramco

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Star Communications

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TUBACEX

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www.tubacex.com

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Universal Pressure Pumping Inc

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www.topsidesevent.com

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www.perupetro.com.pe

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17 9

D&L Oil Tools

PennEnergy

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www.bodycote.com

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 Jill Kaletha, Mossberg & Co, 800-428-3340 x149,  [email protected], Attn: Jill Kaletha, Mossberg & Co, 301 E. Sample Street, South Bend, IN 46601

11

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Chaparral Energy

47

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www.arielcorp.com/whoweare

Bodycote

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19

China / Korea / Singapore / Asia-Pacific

Graham Hoyle, 10 Springfield Close, Cross, Axbridge, Somerset BS26 2FE, Phone: +44 1934 733871 Mobile: +44 7927 889916, [email protected] or ghms@ btinternet.com

5

www.afglobalcorp.com/drilling

P6

www.rodguides.com

Victory Energy

27

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This index is provided as a s ervice. The publisher does not assume any liability for errors or omission.

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Oil & Gas Journal   | Apr. 2, 2018

THE EDITOR’S PERSPECTIVE

84

 WATCHING GOVERNMENT

THE EDITOR’S PERSPECTIVE

Automated opinion clogs permitting of energy projects by Bob Tippee, Editor Automated opinion undermines discourse and too often overwhelms legitimate public concern about energy projects. Pressure groups routinely clog project permitting with mass-produced submissions during public-comment periods. The tactic is obstructionist—and undemo-  cratic. Sure, pressure groups have the right to submit as many comments as they like. But repetition doesn’t validate message. And repetition aimed at swamping commentary is pernicious. Meridian Energy Group Inc. has usefully deconstructed a flood of comments submit-  ted about the 55,000-b/sd refinery it wants to build in two phases in the Bakken shale region of North Dakota. The state Department of Health’s division of air quality issued a draft permit-to-construct for the proposed Davis refinery in December and accepted public comments for 45 days. When the comment period closed on Jan. 26, 2018, the division had received nearly 11,000 submissions. Meridian responded to all of them. It also analyzed the sources. In a Mar. 20 press release, the company re-  ported that 97.5% of the comments were form letters, “essentially e-mail blasts from several different member-based web sites.”  One organization with 1.3 million mem-  bers submitted 10,068 form letters via e-mail through its web site. According to Meridian, none of the form e-mails contained comments relevant to the technical or legal basis for the draft permit is-  sued in December. “While 1.8% of the comments received were from North Dakota respondents,” Meridian said, “over 22% were from the West Coast, specifi-  cally Oregon, Washington, and California.”  William Prentice, Meridian chief execu-  tive officer, said reviewing and analyzing the comments were “almost as exhausting as the application review process itself.”  He credited work by the health department for depriving opponents of a “substantive ba-  sis” for their resistance to the project. Especially interesting is Meridian’s observa-  tion that the form emails didn’t address techni-  cal or legal underpinnings of the draft permit. Apparently, senders were interested more in numerical spectacle than genuine issues, more in jamming a system than actuating persua-  sion. Meridian said only 2.5% of all comments received were unique. But they deserve 100% of official attention.

(From the subscription area of www.ogj.com, posted Mar. 23, 2018; author’s e-mail: bobt@ ogjonline.com)

85

 WATCHING GOVERNMENT

Nick Snow Washington Editor

Tillerson’s farewell remarks Some of his harshest critics conceded that Rex. W. Tillerson always was a gentleman in his nearly 14 months as US Secretary of State. It apparently was not enough to keep President Donald Trump from firing him after we eks of rumors that the retired ExxonMobil Corp. chief executive was on his way out. Tillerson nevertheless made some important points to State Department employees in his Mar. 22 farewell address that deserve wider attention. “The country faces many challenges—in some instances perplexing foreign affairs relationships, and in other instances serious national security threats. In these times, your continued diligence and devotion to the State Department’s mission has never been more necess ary,” he told them. Tillerson expressed his hope that each of them would be guided by and their actions driven by two main priorities: First, to value the safety and security of themselves, their loved ones, and their colleagues. And second, to maintain a commitment to personal accountability so they could hold others accountable in a positive environment underpinned by honesty and integrity. “Never lose sight of the most valuable asset you possess: your personal integrity,” he urged. “Not one of you was gifted it; you were born with it. It belongs to you, and always has and will belong to you and you alone. Only you can

relinquish it or allow it to b e compromised. Once you’ve done so, it is very, very hard to regain it. So guard it as the most precious thing you possess. “And finally, I hope you will continue to treat each other with respect. Regardless of the job title, the station in life, or your role, everyone is important to the State Department. We’re all just human beings trying to do our part,” Tillerson said.

‘Each of us chooses’  In closing, he asked each of them “to ensure one act of kindness each day toward another pers on.” His next observation—“this can be a very mean-spirited town”—was met with laughter and applause. “But you don’t have to choose to participate in that,” Tillerson continued. “Each of us gets to choose the person we want to be, and the way we want to be treated, and the way we will treat others.” It’s not likely we’ll ever know whether he regretted accepting Trump’s invitation to become Secretary of State. He possibly has identified things he would have done differently while he was there. But he also may rec all moments during Cabinet meetings when he wondered if he was the only adult in the room. Maybe this is why most of the country’s top business leaders avoid federal service. Tillerson, at least, tried.

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[energy review] AN IN DEPTH REVIEW OF THE OIL & GAS SECTOR IN THE CANARY ISLANDS

CANARY ISLANDS

AFRICA

THE MID ATLANTIC HUB Located at the crossroads between Africa, Europe and the Americas, Spain’s Canary Islands offer the advantages of Europe 60 miles from Africa, great tax regime and quality of life ver since Christopher Columbus stopped here in 1492 on required technical, organizational and financial capabilities,” his historic journey to the Americas, the Canary Islands have says Vicente Marrero Domínguez, President of the islands’ played a pivotal role in trans-Atlantic transport and trade. Maritime Cluster. Now, as the West African offshore emerges as one of the world’s Supported by a corporate tax rate of just 4%, a pro-business fastest growing oil and gas regions, the Spanish islands are administration, a qualified workforce and an enviable quality of assuming a new role as a logistics hub for operators and services life, the islands look well poised for a new chapter in their history. companies in the region. More than a dozen platforms and rigs “With our connectivity, our security and of course our location, are currently being serviced in ports across the seven-island I think the Canaries could be a hub between three continents,” archipelago, which is located just 60 miles off the West African Clavijo says. coast but which offers all the security and stability of a member It is not only as a base for African offshore development that of the European Union. the Canaries are carving out a new role for themselves on the “Oil and gas companies here have access to Western Africa, global energy map. As the shipping industry steadily evolves because geographically that is where we are located, but they towards the use of LNG as a fuel, the islands are also ideally also have all the legal and positioned as a mid-Atlantic “Oil and gas companies here have access to fiscal guarantees of the center for bunkering. EU, because politically Historically, the islands Western Africa, because geographically that is we are part of Europe,” played a crucial part in where we are located.” says Fernando Clavijo, the trans-Atlantic trade as a President of the Government coaling station for freighters  Fernando Clavijo, the President of the Government of the Canary Islands of the Canary Islands. plying the route between  With more than five hundred years’ experience of Atlantic Europe and the Americas. To this day, they are still Spain’s leading seafaring and trade, the islands are no newcomers to the bunkering center. And while the times of coal-powered ships are maritime industry. Across the ports of the archipelago, local ship long gone, the arrival of a new generation of LNG-fueled vessels repair companies are busy refocusing their activities on offshore could see the Canaries reclaim their traditional role as an Atlantic platforms, while multinational giants such as Rolls-Royce have bunkering hub. The government and port authority of Tenerife also set up bases here. have already published ambitious plans, supported by the EU, “The oil and gas industry now knows that there is a group to transform the island into a regional center for this new era in of companies and shipyards in the Canaries which have all the maritime transport.

E

Project Direction / Editorial Content: Nathalie Martin-Bea • Photography: Oscar Segura

Within the EU… nown by the Romans as ‘the fortunate isles’, in the 21st century the Canary Islands seem blessed with the best of both worlds: while enjoying all the legal security and worldclass infrastructure of a member of the European Union, they are located next to one of the fastest-growing economic regions of the developing world and are allowed by the EU to charge a corporate tax rate of just 4%. “The EU-approved tax system tries to compensate for the fact that we are a small region far from mainland Europe,” says Pedro Ortega Rodríguez, the regional minister for the economy, industry, commerce and knowledge. “Nevertheless, we are also in a good position to serve the  West African market, especially in the maritime sector. “We are an excellent business Fernando Clavijo, platform, an attractive place to President of the Government of the Canary Islands live, and a good hub from which to connect to the rest of the world. Our economy is already feeling the impact of the growth of the offshore sector and the development of the African continent.”  While the 4% tax rate is an immediate attention-grabber, the competitive advantages of the islands extend well beyond the world of financial accounts and investment incentives. The international connectivity of the Canary Islands, their communications infrastructure, the availability of large pool of qualified labor, and their growing experience in offshore services, have all transformed the archipelago into the location of choice for energy companies operating in Africa and the mid-Atlantic Basin. “We are becoming a hub for business in the region,” Ortega says. “In the maritime sector, we want to ensure that the Canaries offers access to world-class ports and gives businesses the perfect platform for their operations in Africa. Many multinationals companies are already establishing bases here, in energy and mining, to serve their  African businesses.”  As an island region, transport connectivity has always been critical to the economic development of the Canaries. In this area, the islands’ heritage as one of Europe’s most popular destinations for tourism and leisure has played an invaluable role: with more than 16 million tourists visiting annually, over 540 direct flights each year connect the Canaries to the UK alone, from six international airports all across the archipelago.  With such a high level of connectivity with Europe, the focus now is on increasing air and maritime links to the African continent. “Our air connections to Africa are increasing, especially to the countries that are closest to us and we are looking to expand with countries that are further away in Africa.,” says Pablo Martín Carbajal, the CEO of Proexca, the islands’ official agency for internationalization and investment. “Our maritime connections extend to almost ever y country in West Africa and the Gulf of Guinea.”

K

Reflecting the islands’ capabilities as a platform for large-scale operations in Africa and beyond, in 2014 the UN World Food Programme inaugurated a logistics hub in the Port of Las Palmas. Since then, the WFP has used the base to respond to events in countries in West Africa, as well as in the Caribbean. During the ebola crisis, the base played a critical role in the transshipment, preparation and delivery of emergency equipment and food by sea.  While its ports and airports are taking increasing advantage of the archipelago’s strategic location, increasing investments in education and training are making sure that investors here have access to a diverse and qualified workforce. Many of the region’s young workers are multilingual or have strong English language skills—another byproduct of the tourism industry. And with

E.U. LEGAL FRAMEWORK

Full application of the EU legal system:

Data protection Free competition Financial regulations International anti-corruption measures:

US FCPA Due Diligence

three public and three private universities on the islands, 36,000 students in higher education and thousands more attending 180 professional training centers, the workforce of the Canary Islands is increasingly well prepared for the specialist challenges of the future. “Our universities and training centers are going to produce all the professionals that are needed,” Ortega says. “At first, we had to bring in people from abroad in the energy sector, but now locals are being trained and they are going to take over those  jobs. Our ports are full of rigs now, because operators know that they will receive the high quality on time service they need at competitive conditions.”

at 4% corporate tax  Wherever they operate in the islands, thanks to the ZEC (the Canary Islands Special Economic Zone), O&G companies committed to create jobs in the Canaries and set up subsidiaries here will benefit not only from the 4% corporate tax rate but from a range of other advantages. Chief among them, dividends paid by entities in the islands to their parent company in most overseas jurisdictions are exempt from withholding tax, while companies in the ZEC are also exempt from the canarian VAT (IGIC) that applies for imports, reducing the cost of merchandise. The low tax scheme tool ZEC, which was authorized by the European Commission in 2000, applies all across the territory of the Canary Islands and has played a vital role in the region’s economic development.

TAX INCENTIVES % EU corporate tax rates The Canary Islands Special Zone (ZEC), offers the lowest corporate tax in Europe and further discounts for R&D activities. This special rate will apply to a maximum amount of the income tax, depending on the number of jobs created. Reduction of up to 90% of non-distributed net profit from taxable base. Companies can also take advantage of close to 5.8 million 800 ft² of Free Trade Zones. Belgium

34

France

33

Germany

30

Luxembourg

27

Spain

25

Netherlands

25

Austria

25

Switzerland

24

Italy

24

UE Average

22

Portugal

21

United Kingdom

19

Poland

19

Ireland CANARY ISLANDS

12,5

4%

Source: Sociedad Canaria del Fomento Económico S.A. PROEXCA, 2016 figures

“The exemption on capital gains, in which dividends are included, is very important specially for foreign companies from outside the European Union,” explains Beatriz Barrera, the president of the ZEC. “In the Canary Islands, they obtain the same treatment as European entities   “A company does not make investment decisions solely due to tax incentives. A geographical area has to be economically attractive. However, taxation is a very important factor. It is an important tool for diversifying and internationalizing our economy and creating jobs in non-tourism sectors such as oil and gas.”  While the tax incentives have a powerful appeal to compa nies operating in the Canaries, Barrera says that the legal stability

and transparency that comes from setting up in an EU member state may be just as important to companies operating here. All businesses in the islands are governed by the EU legal framework, with all the protections that implies to both companies and individuals. Furthermore, the islands are fully compliant with all EU and OECD Pedro Ortega Rodríguez norms and regulations on tax Regional Minister of Economy, transparency and tax evasion. Industry, Commerce and  Just in 2017, the ZEC Knowledge authorized 136 companies to enjoy the benefits of the special regime, who between them have committed to invest 103 million euros and to create 1,640 jobs in the Canary Islands.  While legal certainty and tax incentives are powerful forces driving the economic success of the islands, it is perhaps two more intangible factors that represent the region’s most important competitive advantages: the climate and the quality of life. Speak to anyone with the fortune to live here and they will tell you that the climate is the best in the world, while the islands are home to top-tier medical and educational institutions, plus leisure and cultural opportunities on a par with anywhere in Europe. “In the five years that we have been welcoming people here from the offshore industry, whether from Ireland, Scotland, Norway, the Netherlands, Korea or Japan, they are all stunned by the quality of our infrastructure, our schools and our hospitals when they come here for the first time,” says Claudio Lamas, founding partner of law firm Islaw Abogados. Expatriate workers and their families enjoy total personal security on the Canary Islands, with very low crime rates and almost no incidence of tropical diseases or extreme weather events. “There is very little rainfall, no mosquitos, and no hurricanes,” says Mr. Chang, partner at Islaw. “People sometimes compare us to the Caribbean but our climate is stable and our streets are safer. For employees and their families the safety and the quality of life they can enjoy here is priceless.”  As well as high levels of personal security, EU membership also implies a high level of professionalism and transparency, supported by strong institutions and a rock-solid rule of law. Companies operating in the Canary Islands benefit from a pro-business environment which has no rival in the region for efficiency and speed of responses. “We have a very modern and agile property registry and commercial registry, so that companies can be set up in just two or three days. We have set up in a strong legal tradition and we are also an efficient and relatively inexpensive jurisdiction,” Lamas says. “All these, and it is also one of the few places in the world where you can work outdoors every day of the year.”

Boosting offshore services

The Canary Islands service an average of 25 rigs/year

S

ince the start of the millennium, riding the wave of high oil prices and rising demand for West Africa’s rich hydrocarbon resources, the Canary Islands have become the preferred port of call for drillships and platforms plying the route to the continent’s offshore fields. In their wake, the ports of Gran Canaria and Tenerife have seen a flourishing trade develop in technical services and supplies for the offshore sector, led in large part by local players. Offshore services providers on the islands offer a wide range of services including maintenance and repairs, quality-control inspections, sheet-metal work, waste treatment, and others. All types of bunkering services are also available around the clock, making the islands a center for refueling in the North Atlantic.

Compared to competitors on the African mainland, the islands enjoy a series of strategic advantages: world-class air, maritime and telecoms connectivity, very competitive fiscal incentives and, most importantly, membership of the European Union, with all the legal guarantees and stability that goes with it. “The main reasons to set up base here were obvious—the location and the political stability,” says Odd Are Tveit, CEO of Norwegian subsea supplier Otech and of GCSB, a local joint venture with developer Satocan. Other international services companies who have established operations in the Canary Islands include Korea’s Hyundai and the UK’s Rolls-Royce Marine, while IOCs such as Chevron, Petrobras and Total regularly use the archipelago’s suppliers to service their rigs and vessels.

TENERIFE’S PORT AUTHORITY CONTINUES TO EXPAND CAPACITY

T

he Port Authority of Santa Cruz de Tenerife manages three ports on Tenerife, as well as three facilities on the smaller, neighboring islands of La Gomera, La Palma and El Hierro. Its newest facility is the Port of Granadilla, situated in the southeast of the island, which entered operation in November 2017. Its external quay stretches for 2.5 kilometers, with more mooring space to come and seven million square meters of land for development. “We still have to complete the Ribera quay,” notes Ricardo Melchior, the Port Authority’s Chairman. “By the end of 2019, we will have a port with very large capacity. Santa Cruz could also grow more. We have ports for the next 20 years.  We have important maintenance and repair services [and] are growing at a significant pace. We used to have six companies two years ago and we now have 70.”

The Port Authority currently has one floating dock in place and is about to bring a second facility from a local company, Tenerife Shipyards, onstream, making it the only place in the mid and South Atlantic Ricardo Melchior that can repair big vessels, President of Port Authority of Melchior says. The island Santa Cruz de Tenerife also benefits from great air, maritime and telecoms connectivity with the biggest nations in West Africa, including Côte d’Ivoire, Gambia, Nigeria and Senegal: “Geographically we are in Africa, our administration is in Europe, and our emotions are in America,” he smiles.

PROXIMITY TO STRATEGIC PORTS

UP TO 18 OFFSHORE SERVICES AVAILABLE

Distance by sea from the Canary Islands

To Nigeria To Aberdeen/ Stavanger To Houston

> 7 days > 6 days > 13 days

 As the hydrocarbon boom intensifies, the provision of specialist training is also developing fast, with hundreds of ISOcertified courses taught on the islands to thousands of energy sectors employees. Homegrown providers, such as Grupo Stier (see p.13), may soon have to vie for a share of the lucrative marketplace with global names such as Maersk Training.  According to the latest data available from the regional government, offshore services currently employ about 45,000 workers, with 20,000 new jobs expected by 2020. Over 25 rigs and drillships were serviced in the islands last year, generating an average income of 10 million euros per oil platform. The Port of Las Palmas is emerging as the center of the region’s services industry, with local shipyard Astican at its heart. Astican provides its offshore clients with a full-service offering that covers nearly all their requirements. The company has a Syncrolift drydocking system with a lifting capacity for vessels up to 36,000 DWT; seven docking lanes, 600-ton mobile cranes, and a

PORT OF LA LUZ LAS PALMAS

PORT OF SANTA CRUZ DE TENERIFE

3.008 ha anchorage area 17 km quays and berths 5-24 m draught range 8 tug boats 16 ro-ro boarding ramps

9.176 ha anchorage area 16.8 km quays and berths 6-25 m draught range 11 ro ro boarding ramps

Storage facilities

Storage facilities

424.600 m2 covered area 40.000 m2 open air area 158.544 m3 cold area 332.000 m3 bunker area

48.387 m2 covered area 72.357 m2 open air area 176.189 m3 cold area 179.864 m3 bunker area

deepwater quay covering 140,000 square feet with a draft of 68 feet, an extended berthing area of almost 900 feet and close to 200 feet width. The facility has an open-door storage area, twothirds of which is bonded and hence free from customs duties. “We developed a concept that was used in the industry a few years ago: the one-stop-shop philosophy,” says Germán Suárez Calvo, Astican’s CEO. “One of our main objectives was to cut costs to rig owners coming to Las Palmas, not just to our shipyards… and also to third parties like OEMs. That way, we remove hidden costs and inefficiencies.”  Astican’s expertise extends from conversion projects to the installation of electrical and HVAC systems to mechanical, piping and steel work. Its team of 200 engineers and professionals includes divers, a flying squad and rope-access specialists. An IT company associated with the group—INERZA—provides telecommunications, virtual private networks and cybersecurity services. Astican is also involved in decommissioning, with

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a customer portfolio that reads like a Who’s Who of the West  African energy business. Foremost among its partners is global leader Rolls-Royce Marine. In 2010, a Norwegian rig owner decided on Las Palmas as a base for its West African projects, but rather than send thrusters back home for repair, a costly exercise given the size of the equipment, it suggested that Astican talk to Rolls Royce. “We want to replicate this with the rest of the value chain; we have a long term commercial agreement with risers and we are now chasing Schlumberger, NOV, General Electric; we are talking to the big guys,” Suárez Calvo says. Decommissioning is another growing activity for Astican. “We have been cooperating with Transocean and we are studying the decommissioning of 15 platforms for Petrobras”, Suárez Calvo says. “We have to identify what part of the job should be carried out in western countries.”  Another local company based in Las Palmas is also seeing strong potential for decommissioning and shipbreaking services, as operators looking for a more socially and environmentally way of disposing of their platforms at end of life. With increased concern about the human environmental toll of scrappage

“Over the last 15 to 20 years, Canarian ports and port companies have had to develop a business fabric to serve the energy sector.” Antonio Castañeda, Alfaship’s Manager

services in countries such as Bangladesh and Turkey, the Canary Islands are well positioned to become the first port of call for decommissioning vessels in the Atlantic Basin. “We could carry out 100% of the decommissioning procedure,” says José Mancebo, Operations Director at Logiscrap. “We are already in discussions with a potential business partner who wants us to decommission one of their rigs here in Las Palmas. Unlike other countries, in the Canary Islands we have to abide by strict environmental and labor regulations.”

From decommissioning specialists to ship agents, businesses in the oil and gas value chain in the Canaries are confident that they can provide world-class services while also reducing costs. “The companies have increasingly demanded cost savings, so we carry out all the logistic processes and we don’t outsource to third parties,” explains Alfaship’s Manager,  Antonio Castañeda. The family business is celebrating its 30th anniversary. With offices in 10 Spanish ports, including two on the Canary Islands, Alfaship Germán Suárez Calvo offers a diversified catalog CEO, Astican of agency services. Alfaship’s businesses include an offshore agency division in Las Palmas and Tenerife, which serves traffic in the area, a brokering and chartering department, and a customs brokerage and a legal affairs unit. “Over the last 15 to 20 years, Canarian ports and port companies have had to develop a business fabric to serve the energy sector,” says, Antonio Castañeda. “From the start, it was clear this would imply substantial future traffic. So, the port has adapted in order to be attractive for shipowners and become a strategic point for rigs.” Iryna Krasnikava, commercial manager in charge of business development at Alfaship, says the company has followed market trends closely. “We have moved in synch with the oil and gas market in its development. The first rigs that arrived did so for bunkering. Later, the infrastructure for repairs and service provision began specializing in the offshore industry. Then, personnel transfers and logistics began to develop.”  As demand for services evolved, so did Alfaship, Castañeda says. “The stage that is ahead of us is very interesting because we can apply all the know-how we have acquired during these years. Besides of our vast experience with O&G companies, we have a good in-house training program, so I dare say we are ready for

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any challenges market can bring.”. Alfaship is ISO 9001, 14001, OHSAS 18001 and TRACE-certified and works transparently to ensure that clients, including the Noble Drilling, Ocyan, Boskalis, Siem Offshore, Allseas, know they have a partner they can trust. Elsewhere on the islands, big names including CGG Veritas, PGS, Polarcus and SDV are regular users of services from Canarship, a maritime agency and integrated logistics provider. Established in 2000 in Tenerife and part of the Romeu Group, Canarship has rapidly expanded to Gran Canaria and now has a presence in all of Spain’s major ports. “We started serving mainly the seismic industry which was stopping here before going to  West Africa or Brazil,” explains Javier Delgado, the company’s director. “Then, we became involved in the rig business and signed agreements with some of the largest companies.”  “They always think the Canary Islands are beaches, fun and a tourism paradise. They are quite surprised when we start to talk about the potential of the ports, the repair facilities and all the advantages we have here.” In recent years, Canarship has signed service agreements with drilling contractors such as Ensco, Seadrill, Ocean Rig and auxiliary rig companies like Floatel, and it has expanded its team to cope with rising demand. Terminal TCT, Santa Cruz de Tenerife

“In our offices at the Canary Islands we have a professional team that includes naval engineers.” Javier Delgado, Canarship Director

 “In our offices at the Canary Islands we have a professional team that includes naval engineers in order to be more specialized and able to offer more value in our agency service,” Delgado says. The services industry in the Canary Islands are responding well to the surge in demand, says José Mayor, CEO at Atlansea, a local

shipping agent with a rapidly growing bunkering, cargo handling and logistics offering. “Demand just for bunkering fuels in the Canary Islands is rising by rates of 5 to 7% annually, while we are also supplying new services for oil rigs,” Mayor says. “But I think that both the Port of Las Palmas in general and Atlansea are prepared. The port has been able to expand and adapt and I think that it will become one of the main ports in the region for stopovers, repairs and operational bases. With qualified personnel and a port in great condition, we are certainly up to the challenge. We are reliable, cost-competitive and strategically located, with ports that can attend to all the needs of the energy industry in Africa.”

PORTS AUTHORITY OF LAS PALMAS SETS SIGHTS ON SERVING OPERATIONS SECTOR 

L

ying on the main maritime route from Europe to the Gulf of Guinea, the port of La Luz in Las Palmas, on Gran Canaria, is an ideal base for drillships serving offshore fields. At the start of 2018, nine vessels were moored in the port, which can handle ships up to 100,000 tons. La Luz is now ramping up its facilities to serve the fast-expanding operations sector.  According to Luis Angel Ibarra, the President of the Ports  Authority of Las Palmas, thanks to investments already committed, La Luz’s Reina Sofia quay will be extended by 350 meters. Once completed, the port will have over 2,000 meters of deepwater mooring space, more than any other facility on the neighboring continent. The Port Authority is now studying plans for a new $37-million dry dock, attached to the Reina Sofa quay, for which it is looking to attract private-sector capital.

 A joint-venture between Norway’s Coast Center Base and Canarian company Zamakona signed a $22 million deal in 2016 to develop a platform and FPSO repair center at La Luz. The Ports Authority aims to award a concession to the JV this year that will allow it to offer cutting-edge Luis Angel Ibarra services from the La Esfinge President of the Ports Authority quay: “The offshore sector of Las Palmas has experienced substantial growth over the last five years,” Ibarra points out, “and this will continue to a larger extent over the next three or four years.”

Free zones set their sights high  A

s well as the special corporate tax rate that applies across the entire archipelago, the Canary Islands offer two of the largest free zones in Spain, on the islands of Gran Canaria and Tenerife. In both free zones, companies are able to store, process and distribute their goods without incurring duties or indirect taxes, while bureaucratic procedures have been streamlined and red tape cut to a minimum. The establishment of the two zones has consolidated the islands’ position as a natural platform for serving markets in West Africa. In recent years, companies in the oil and gas sectors have expanded their presence in both zones. At the free zone at the Port of Las Palmas, which is the older of the two, local ship repair, maintenance and logistics specialists such as Transcoma, which brought Transocean to the Las Palmas Port, are expanding their services to the offshore sector. Oryx Energies of Switzerland has built a terminal with over 220,000 m3 capacity of bunkering fuels at the port. “About 30 companies in the oil and gas sector are currently operating here,” says Carlos Ester Sanchez, president of the Gran Canaria Free Zone. “Some of them are already planning to expand their operations. It shows how well our system works for them. The connectivity of the port and the facilities that are available are very attractive to energy businesses.”  With a depth of 30 metres, the port can welcome the largest cargo vessels on their way to and from Africa, mainland Europe and the Americas. “As a door to Africa for the rest of the world, we are looked on favourably by companies who want to make us their logistics hub,” Ester Sanchez explains. “And when it comes to repairing ships and offshore platforms, the Las Palmas Port is on the cutting edge.” In Tenerife, the free zone’s ambitions extend well beyond the immediate region. The free zone is spearheading the creation of a Free Corridor of the Atlantic which would enable the tariff-free

Free Trade Zone of Santa Cruz de Tenerife

transhipment of goods from duty-free zones on both sides of the ocean. With the Canary Islands at its heart, the corridor would reinforce Tenerife’s strategic role in the transport of merchandise between the Americas, Europe and Africa. So far, more than 150 free zones from 36 countries in Europe,  Africa and the Americas pledged their support. “We initially proposed just a mid-Atlantic corridor,” says Ricardo Melchior, the head of the port authority of Tenerife. “Interest has been so high that we have extended the proposal to cover the whole Atlantic.”

From Tenerife…

I

n today’s oil and gas industry, successful exploration, profitable production and the effective management of downstream services and marketing all depend as much on computing power and data analytics as on the traditional hardware of the energy sector. In Tenerife, home to the second most powerful supercomputer in Spain and to a growing network of technology parks, businesses across the upstream and services sectors can enjoy access to all the processing power and connectivity they may need—plus the staff with the technical skills to make sure that they get the most out of them. “Technology is changing the geography of the Canary Islands,” says Carlos Alonso Rodríguez, the President of the Cabildo of Tenerife, the island’s governing council. “With the growth of our Information Technology and Communications sector, physical

“Our cable connectivity, our datacenter and our supercomputer represent a very strong platform for attracting companies to Tenerife.” Carlos Alonso Rodríguez,  President of the Cabildo of Tenerife

distance is becoming less relevant and our communications infrastructure is becoming more competitive.” Elected in 2013, Alonso has made investment in innovation and communications the centerpiece of his economic plan for the island, the largest and most populated in the entire archipelago.  Alonso’s so-called Tenerife 2030 strategy, which enjoys a budget of 100 million euros a year, is focused on transforming the island for the digital age by investing in education, innovation and digital infrastructure. “Tenerife 2030 is a smart island strategy,” Alonso explains. “It represents our long-term vision for Tenerife. Its aim is to develop the capacities of our human talent and above all to prepare younger people for a complex, fast-change and globalized world. It is about supporting creativity, innovation and entrepreneurship and about moving towards a digital society. “The oil and gas industry is completely reliant on the management of information and data. In Tenerife, we have the qualified people and the infrastructure that is needed to process this data and create value. When I talk about Tenerife to businesses, energy companies are among the first to understand this.” The cornerstone of Tenerife’s digital economy is formed by a fast-growing network of submarine cable connections to Africa, Europe and the Americas. Run by a number of independent operators, these connections provide the island with worldclass data transmission capabilities and speeds, plus a high degree of redundancy. For example, one 17,000km connection passes through Tenerife and several West African countries on its journey from France to South Africa, delivering companies on the island with the highest degree of international connectivity in the archipelago.

Linked up to all these submarine cables, the jewel in the crown of Tenerife’s ICT infrastructure is D-ALiX, a giant datacenter that is largely powered by wind and solar energy. The facility is situated at the ITER complex, an institute which focuses on technology and renewable energy and which is also home to the second most powerful supercomputer in Spain, with total of 17,800 computing cores and 36 TB of memory. Combined, the technologies on offer at D-ALiX provide organizations of all kinds and sizes with the complete range of colocation, hosting and processing services they may need to expand their businesses. For example, companies operating in the African energy sector no longer have to send data all the way back to continental Carlos Alonso Rodríguez Europe but can store, process President of the Cabildo of and analyze their data in Tenerife nearby Tenerife. Furthermore, thanks to its use of power from local photovoltaic plants and wind farms, the site is also one of the greenest datacenters in the world. “D-ALiX has connected Tenerife to the rest to the world at low cost and with a high quality service,” says Antonio García Marichal, the minister in charge of innovation, education, culture and sports on the island council. “We have many foreign clients who are using the supercomputer to process the data they gather in other countries.” For O&G companies looking to simulate seismic basins or increase the efficiency of drilling through data analytics, in complete security, Tenerife has no competition in the region. In the near future, García Marichal adds, the island will expand its existing network of connections: consortia of investors are currently assessing the construction of new submarine cables to the Americas and enhancing links to Portugal. Another, even more powerful supercomputer is also in the works.

The Institute of Technology and Renewable Energies supports innovation in Tenerife

 to the world!  As well as developing the computing and communications infrastructure that are now so sought after by energy businesses, Tenerife is also investing heavily in giving young people new skills not only in technology but also in languages and entrepreneurship. The island is already home to an increasingly multicultural and multilingual talent pool as well as two well-rated universities and a growing network of research institutes and technology parks. The Tenerife Science and Technology Park, which currently runs two business incubators in the Santa Cruz de Tenerife Exhibition Centre and in the University of La Laguna, is also developing a new site in Cuevas Blancas in the north of the island. “The spaces that the technology park offers are almost at 100% occupancy today, so we are developing new and more advanced infrastructure to welcome additional companies to the island,” says García Marichal, who is also the CEO of the park. “A lot of biotechnology, IT, animation studios and production companies are setting up at our sites and accessing a wide range of incentives, such as the use of centers for professional training.” Looking further to the future, the current government’s aim is on the younger generation.  As part of the Tenerife 2030 plan, schoolchildren will be given the chance to study abroad and will receive education at the Tenerife Science and Technology Park in STEM-related subjects such as robotics and programming, preparing them for hightechnology future careers in energy and other fast-growing sectors.  Alonso’s stated aim is to provide Tenerife with the

most talented and creative workforce in the region. “Oil and gas companies see that we have a long-term strategy in place for developing our human capital,” Alonso says. “When they come here, they understand that we are providing them with a very good ecosystem for their long-term investments.”

A hub for R&D

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rom pre-salt oil fields off Brazil to shale gas in the US and high-pressure high-temperature (HPHT) wells in the North Sea, oil explorers and producers are pushing up against the boundaries of current industry know-how. In this environment, research and innovation have assumed a critical role across the energy sector, as the upstream races to develop new technologies for finding and extracting hydrocarbons while also reducing costs. For most oil majors, cooperation with research institutes and universities has become a core part of their business.  Although the Canary Islands are a relative newcomer to the world of oil and gas, the islands’ long sea-faring tradition means that companies in the energy sector will benefit from extensive expertise in maritime technology, as well as from a tax framework that incentivizes R&D. “Companies whose activities require investment in R&D will find very favorable conditions in Gran Canaria,” says Cosme García Falcón, managing director of SPEGC, the economic development agency of Gran Canaria. “The direct aid given by the Spanish government through the Centre for the Development of Industrial Technology (CDTI) and the tax deductions for investments in this type of costs can amount up to 75% of the investment carried out. “Moreover, there is a very supportive ecosystem which assists startups in offshore and maritime technology sectors.”

INFactory Building in Tenerife, an innovative business incubator

In some sectors of the energy industry, the Canaries are at the cutting edge of innovation. The Canaries Oceanic Platform (PLOCAN) off the coast of Gran Canaria is one of the world’s leading test centers for the research, demonstration and operation of marine technologies, especially technologies related to marine renewable energy and underwater vehicles. Later this year, PLOCAN aims to install a 5MW offshore wind turbine, which will become the first bottom-fixed offshore wind turbine in all of Southern Europe and the first worldwide to be installed with no need for costly heavy-lift vessels. “PLOCAN provides a magnificent test bed for all companies who want to experiment in oceanic environments,” says García Falcón.

THE JEWEL OF THE CROWN

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n the digital era, in which companies can live or die based on their ability to access and process huge volumes of data, one of the Canary Islands’ greatest assets may be located in an unassuming building in the industrial park of Granadilla, on the island of Tenerife. It is the D-ALiX datacenter at this site that is helping organizations of all shapes and sizes take advantage of the best connectivity and the fastest processing powers in the region. The center serves as a Neutral Access Point for

“Large companies can use the second most powerful supercomputer in Spain here in Tenerife” Antonio García Marichal, Minister for Innovation, Education,

Culture and Sport, Government of Tenerife

carriers and enterprises operating not only in the Canary Islands but across Western Africa: multiple submarine cables from different telecom companies provide world-class connectivity to other Canary Islands, to the African continent and to the European mainland.

The construction of this infrastructure, combined with availability of the TEIDE-HPC supercomputer at the same site, has served as a catalyst for the growth of the region’s Information and Communications Technology sector. Increasing Antonio García Marichal numbers of IT services Minister for Innovation, companies are using the Education, Culture and Sport, Government of Tenerife datacenter to offer critical services such as managed services and application management, all without needing to invest in their own infrastructure. “The D-ALiX project connects Tenerife and the Canaries to the rest to the world at a lower cost and with better quality service,” says Antonio García Marichal, Tenerife’s minister for innovation. “This has led to the rapid development of entirely new sectors that could not have come here before because of the cost of communications.”

Completing the value chain

 W

hen one of the world’s leading suppliers of ship designs and turbines to the offshore sector was looking for a new base for the Atlantic Basin, it did not take long before it selected the strategically located Astican shipyard in Las Palmas on Gran Canaria. For Rolls-Royce Marine, the port is perfectly placed to service growth in the booming offshore market in Africa and beyond. By setting up in Las Palmas, it has given rig and drillship owners, operators and contractors in the region easy access to maintenance and repair facilities, helping transform the Port of Las Palmas into a world-class services center. “We are home to a business cluster that is capable of meeting all the demands of the energy industry for repairs and logistics, and also for technical, professional and personal services,” says Cosme García Falcón, head of the SPEGC, the island’s economic development agency. “We have already become a hub for rig owners,” says Germán Carlos Suárez Calvo, CEO at Astican. “In Las Palmas we currently have 12 rigs. In Tenerife there are 10. At a time when the oil majors are requesting heavy cost cuts from their providers, oil services companies can use the Canary Islands as a one-stopshop where Original Equipment Manufacturers such as RollsRoyce are based. It is a solution which removes inefficiencies and reduces costs for service providers and their clients.”  Across the archipelago, a wave of investments in hard infrastructure such as ports, communications networks and desalination plants, as well as in training and digitization, have turned the Canary Islands into the ideal platform for servicing the West African energy industry. “When you think about all the training programs that we have established, then it is clearly no coincidence that RollsRoyce or Otech chose Las Palmas,” president Clavijo says. Norway’s Otech was one of the first international services companies to spot the potential of the Canary Islands, starting

TRAINED TO THE HIGHEST STANDARDS

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ith a history in the Canary Islands that stretches back more than 20 years, maritime services specialist Grupo Stier is one of the region’s primary providers of offshore training. Located on a government leased land in the Puerto de Ida Stier Taliarte on Gran Canaria, CEO Grupo Stier the Stier Offshore Training Center provides a wide range of approved training to the fast-growing offshore and maritime industries. The facility is accredited for OPITO, the global industry standard in oil and gas safety. As well as offshore survival training, it also provides courses in foreign languages and specialist maritime skills. Such is the success of the center that Stier is planning for September a second center in Tenerife focused on GWO/LMG Training.

operations here back in 2012. Partnering with local developer Satocan, Otech is one of the owners and shareholders of the Gran Canaria Subsea & Offshore Base (GCSB). The base at the Port of  Arinaga provides logistics, ship agency and facility services.  “Using our offshore facility base here, companies can store critical parts and equipment that they can share across their operations,” says Odd Are Tveit, the CEO of Otech and of GCSB. “It makes sense, especially at a time when everyone is cutting costs, to have a central storage base which can be used for different regions.”

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One of the first jobs carried out last year by Techfirm Canarias after its establishment was to implement a new telecom system for a rig that Transocean was reactivating in Las Palmas. “We introduced an IPTV solution to improve crew welfare, restarted safety and security systems, and installed a new video conferencing capability,” says Pierre de Rozario, a veteran in oil and gas telecoms who founded Techfirm Canarias (TFC) in 2017. “We expect to play a big part in developing innovative communications for operators in the West African region, for example using VSAT satellite technologies and LTE/4G broadband services.” On the island of Tenerife, a network of science parks is now home to a thriving ecosystem of technology startups, all benefitting from Tenerife’s world-class broadband infrastructure and from the support of the Tenerife 2030 strategic plan. “We GCSB, an Otech and Satocan JV, at Arinaga Port, Gran Canaria

GCSB’s site on Gran Canaria includes more than 650 meters of deepwater quay, with depths of up to 15 meters, enabling a wide range of logistics and harbour services for visiting clients. Manufacturers are also using the base to supply subsea structures for African offshore operations. “In our base, the port is directly connected to the logistics area.  We can transport materials and unconventional equipment directly into our clients’ customized facilities,” Odd Are Tveit explains.  At the same time as meeting the offshore industry’s services requirements, the islands are also investing heavily in stateof-the-art IT infrastructure. At the same time as meeting the offshore industry’s services requirements, the islands are also investing heavily in state-of-the-art IT infrastructure.

“The Port of Las Palmas is already servicing 14 rigs a year, which shows how competitive we are.” Cosme García Falcón, Director General,

Sociedad Promoción Económica de Gran Canaria

have set up broadband communication networks and we have trained personnel that can meet the needs of any company that chose to establish itself here, just as if they had set up in Berlin or Miami,” says Antonio García Marichal, the minister in charge of innovation, education, culture and sports on the island council.

ON THE CUTTING EDGE

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t a time when emerging technologies in seismic mapping, data analytics and even artificial intelligence are making major headway in the oil and gas sector, the technology research in the Canary Islands represents a significant competitive advantage. Get ready to lead the Future, reads the slogan of University La Laguna in Tenerife; “50% of the  jobs that we will see in the future do not exist today, says  Antonio Martinón, rector of ULL; “It’s under that spirit that we prepare our students”.

“We have the capacity to work together with companies in the energy field in areas such as education, training technology and research” Rafael Robaina, Rector, University of Las Palmas de Gran Canaria

The islands are home to university researchers for whom R&D in the energy industry is a strategic priority. Nowhere else in the region can companies access such a high level of scientific talent or raw computing power. At the University of Las Palmas de Gran Canaria (ULPGC), relationships between

Platea 4D monitoring center at ULPGC

academic researchers and companies from across the energy sector have become increasingly close. “We have always had a lot of contact with the energy sector, especially with the renewable energy sector,” says Rafael Robaina, the rector of ULPGC. One of the most impactful innovations to have emerged from the labs of ULPGC is the Platea 4D system, which enables companies to plan ahead for environmental emergencies such as a spill. The software allows users to simulate risk scenarios in 2D and 3D, based on powerful data analytics, and to design preventative measures to minimize the threat. The award-winning solution helps energy companies not only to comply with legislation but also to take effective action whenever required.

The next Aberdeen for West Africa operations

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s the depletion of reserves in the North Sea accelerates and returns on investment plummet, the center of gravity for the European oil and gas sector is moving south. With new technologies opening up the West African basin and oil prices rising again, the Canary Islands are now in prime position to assume Aberdeen’s mantle as the energy capital of Europe. Few if any of the sun-starved oil workers of the North Sea and their families would resent a move to the Canary Islands: with 4,800 hours of natural light per year, annual average temperatures of 22 degrees Celsius and 256 kilometers of beaches, it is no accident that every year the islands welcome some 16 million tourists, more than Dubai which received close to 15 million in 2016. Add a well-regarded network of local and international schools, universities and hospitals, plus leisure options including 24 golf courses and four national parks, and it is not hard to see why the islands are becoming one of the most sought-after destinations for oil and gas expatriate workers. “We are in a safe location, with good educational facilities and an unbeatable quality of life,” regional president Fernando Clavijo says. “It is a very comfortable place for energy workers to live in with their children.”  Although the islands cannot yet match Aberdeen for the strength in depth of oil and gas services, their long tradition in maritime trade has endowed them with world-class ports and ship maintenance companies. Leading international offshore specialists are also setting up operations in the islands, including Rolls-Royce Marine, Otech of Norway and GEV Group of the UK, injecting new specialist capacities into the fast-developing sector. “We have very convenient logistics and outstanding technical capabilities,” says Germán Suárez Calvo, the CEO of leading local shipyard Astican. “When customers come to the Port of Las Palmas for ship maintenance at the Astican shipyard, they

CLiquid qui am reprovidebis

PLOCAN, the Oceanic Platform test site in Gran Canaria

can also get their thrusters, risers and IT sy stems serviced. Every part of the value chain is located here.” It is not only its connectivity and maritime infrastructure that are attracting international energy companies to the Canary Islands. As an island region, with few natural resources of its own, the Canaries have made it a priority to invest in the skills of its talented and creative people. “We are developing an ambitious programme of specialization, linked to the new demands of the value chain of the sector,” explains Cosme García Falcón at SPEGC, the economic development agency of Gran Canaria. More multilingual and outward-looking than other parts of Spain, the people of the Canaries are now seizing the opportunities of a new chapter in their history.  As Carlos Alonso, president of the Tenerife Council says, “As  Africa continues to develop, it’s a win win situation for us.”

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