Hydrocarbon Processing 02 2016(2).pdf

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PROCESS OPTIMIZATION Troubleshoot multistage vacuum systems to avoid unit fouling and shutdown

MAINTENANCE AND RELIABILITY Prevent overfilling of storage tanks and hazardous materials leakage

INDUSTRY LEADERS’ FORECASTS Continuing viewpoints from key industry executives on 2016 markets and technologies

CLEAN FUELS AND THE ENVIRONMENT Improve gasoline quality with FCC optimization Control technology for GHGs in modified plants

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FEBRUARY 2016 | Volume 95 Number 2 HydrocarbonProcessing.com

28

8 SPECIAL REPORT: CLEAN FUELS AND THE ENVIRONMENT 29 Maximize petrochemicals in the FCCU to increase refinery margins and improve gasoline pool quality C. Chau, R. Schiller and M. Ziebarth

37

Add power to environmental real-time data through analytics P. Black

41

Build a solid GHG BACT cost-effectiveness calculation to avoid CCS costs R. Crum

OUTLOOK: INDUSTRY LEADERS’ VIEWPOINTS 49 2016 Industry Leaders’ Viewpoints—Part 2 L. Nichols

PROCESS ENGINEERING AND OPTIMIZATION 55 Use discrete event simulation as decision support

DEPARTMENTS 4 8 19 21 81 83 84 85 86

59

Troubleshoot operation of a steam ejector vacuum system N. Lieberman and R. Cardoso

MAINTENANCE AND RELIABILITY 65 Prevent the overfilling of storage tanks A. Dokhkan

PROCESS CONTROL AND INSTRUMENTATION 69 Utilize APC solutions to resolve hydrocracker conversion optimization challenges G. Oleszczuk and M. Bożek

75

Enhance PSM design with metrics-driven best practices M. Marshall

GAS PROCESSING SUPPLEMENT GP-1 Technology and Business Information for the Global Gas Processing Industry Cover Image: Gazprom Neft’s 12.15-metric-MMtpy refinery in Moscow, Russia produces high-octane gasoline and diesel, servicing approximately 40% of petroleum demand in the Moscow area.

Business Trends Industry Metrics Global Project Data Innovations Marketplace Advertiser Index Events People

COLUMNS 7 Editorial Comment A low-sulfur world

23

Reliability

25

Global

for storage and shipping—Part 2 J. Vazquez-Esparragoza and J. Chen

Industry Perspectives

Combine metallurgical, structural and physics know-how Reforms will shape future of Nigeria’s refining industry

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Industry Perspectives Downstream disputes breaking the 10% ‘blend wall’ for US ethanol US refiners are set to break the 10% “blend wall” for using ethanol in gasoline, but downstream professionals are certainly not happy about it. Poll findings. In a recent poll conducted on Hydrocarbon

Processing.com, 81% of respondents said they did not agree with the US Environmental Protection Agency’s (EPA’s) decision to break the 10% “blend wall” for ethanol. The other 19% said they agreed. Many in the US refining sector believe the 10% threshold is dangerous to exceed because of potential damage to automobile engines and catalytic converters. “It’s unclear how the EPA can simultaneously recognize the E10 blend wall and yet establish requirements that exceed those constraints,” said Chet Thompson, president of the American Fuel & Petrochemical Manufacturers (AFPM). “This decision is hard to view as anything other than an attempt by the EPA to placate the biofuels lobby.” Similarly, the American Petroleum Institute (API) had asked the EPA to set the biofuel mandate at “no more than 9.7% of gasoline demand to help avoid the 10% ethanol blend wall while meeting strong consumer demand for ethanol-free gasoline.” Rules issued retroactively. The new mandate for biofuel volumes in refining processes was issued in late November 2015 for the years 2014, 2015 and 2016. The oil and biofuels industries have sparred for years over whether the US government should mandate higher blends of the fuel—so much so that the EPA took the unprecedented step of delaying the issuance of its annual targets in an effort to reexamine the program. “For starters, that the EPA is just now—on the last day of November—establishing standards for calendar years 2014 and 2015 is indicative of just how dysfunctional the program has become,” Thompson said. Specifics of new mandate. Under the new set of rules, the

EPA ordered US refiners to blend a record 14.5 Bgal of ethanol into gasoline in 2016. For the first time ever, this means ethanol will make up more than 10% of the total US fuel mix. However, those targets are still about 500 MMgal short of statutory benchmarks laid out when Congress first passed the Renewable Fuel Standard (RFS) in 2007. “We applaud the EPA for recognizing that the E10 blend wall is real and for using its waiver authority to reduce the volume requirements,” Thompson said. “But, the fact that the EPA has had to invoke its waiver authority year after year demonstrates that the program is not functioning as Congress intended and that change is desperately needed.” Visit HydrocarbonProcessing.com today to vote on additional industry polls and to comment on related news.

4 FEBRUARY 2016 | HydrocarbonProcessing.com

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Editorial Comment

LEE NICHOLS, EDITOR/ASSOCIATE PUBLISHER [email protected]

A low-sulfur world As the world continues to welcome more vehicles on the road, and as emerging economies invest in civil, industrial and energy projects, global fuels demand is forecast to increase through the end of the decade. More vehicles on the road equates to higher emissions rates and, in turn, more airborne pollutants. To combat these effects, legislation mandating decreased emissions and lower levels of airborne pollutants is coming into effect. In response, refiners are implementing operational and processing changes to reduce sulfur levels in transportation fuels.

The refining industry has already made incredible strides in reducing sulfur in transportation fuels. As shown in FIG. 1, sulfur levels in diesel fuel have been cut dramatically around the globe within the past decade. Refiners have invested, and continue to invest, billions of dollars in new units, upgrades/retrofits and expansions to meet new sulfur and emissions regulations. These investments promote the reduction of airborne pollutants in both diesel and gasoline passenger vehicles, help produce higher-quality transportation fuels and continue to move the industry toward a low-sulfur world.

INSIDE THIS ISSUE

8 Business Trends.

Nations around the world are implementing stringent emissions standards and low-sulfur transportation fuel specifications. These regulations are an effort to curb airborne pollutants and provide “cleaner fuels” for consumers. HP examines major clean fuel projects and initiatives being implemented around the world.

41 Special Report.

With the right tools and experienced personnel, a real-time environmental data management system with advanced analytics can assist in developing in-house metrics for operations, and foster a necessary dialogue between plant operators and plant environmental specialists.

49 Outlook. 15 and below* >15 - 50 >50 - 500 >500 - 2,000 >2,000 - 5,000 >5,000 and bbove Conflicting/missing data

In Part 2 of HP’s Industry Leaders’ Viewpoints, industry leaders and esteemed colleagues in the industry provide HP with their insights into growing regions of activity, technological advances and how the downstream industry can innovate in 2016 and beyond.

59 Process Optimization.

15 and below* >15 - 50 >50 - 500 >500 - 2,000 >2,000 - 5,000 >5,000 and above Conflicting/missing data * Information in parts per million (ppm)

FIG. 1. Sulfur levels in diesel fuel: global status 2005 (top) vs. 2015 (bottom). Source: United Nations Environment Program, PCFV Secretariat.

A case study, wherein the operation of a vacuum tower was corrected, highlights the importance of understanding the entire vacuum system, of field observation and of the interpretation of operating vs. design data. Basic concepts to help understand and troubleshoot a steam ejector system are presented.

69 Instrumentation.

Honeywell Advanced Solutions and PKN ORLEN discuss utilizing advanced process control solutions to resolve hydrocracker conversion optimization challenges. Hydrocarbon Processing | FEBRUARY 2016 7

| Business Trends Over the past decade, the refining industry has taken incredible steps to reduce sulfur levels in transportation fuels. Refiners have invested billions of dollars in new units, upgrades/retrofits and expansions to meet new sulfur and emissions regulations. These investments promote the reduction of carbon monoxide, nitrogen oxide, hydrocarbons and particulate matter in both diesel and gasoline vehicles. New technologies are moving the refining industry toward a low-sulfur world. New regulations and fuel standards are acting as catalysts for additional clean fuels projects to develop higher-quality transportation fuels. Photo: Essar Oil’s 20-MMtpy refinery is located in Vadinar, Gujarat, India. The facility concluded a planned maintenance turnaround in 4Q 2015 that included the completion of the D-Max Project. Part of Essar’s Optima Plus program, the project included the conversion of the vacuum gasoil hydrotreater unit into a mild hydrocracking unit, as well as the addition of new installations in the diesel hydrotreating unit. Photo courtesy of Essar Oil.

LEE NICHOLS, EDITOR/ASSOCIATE PUBLISHER [email protected]

Business Trends Clean fuels—a global shift toward a low-sulfur world Around the world, legislation mandating decreased emissions and lower levels of airborne pollutants is coming into effect. In response, refiners are implementing operational and processing changes to reduce sulfur levels in transportation fuels. New technologies are moving the downstream hydrocarbon processing industry toward cleaner, lower-sulfur transportation fuels. A low-sulfur world doesn’t come cheap, though. Refiners are investing billions of dollars in new units, upgrades/retrofits and expansions to meet new sulfur and emissions regulations. These investments will help produce high-quality fuels that meet Euro 4, Euro 5 and Euro 6 specifications. Many refiners around the globe have adopted European standards for fuel quality, as Europe has been the frontrunner on regulations for low-sulfur, “clean” transportation fuels. European passenger vehicle emission standards for Euro 4, Euro 5 and Euro 6 are detailed in TABLE 1 and TABLE 2. These standards promote the reduction of carbon monoxide (CO), nitrogen oxide (NOx ), hydrocarbons (HCs) and particulate matter (PM) in both diesel and gasoline passenger vehicles. As shown in FIG. 1, many nations around the world already produce transportation fuels that meet Euro-4 specifications. Other regions, such as the Middle East, are investing heavily to increase the production of Euro 4 and Euro 5 standard fuels. The following is an overview of major clean fuels projects and trends being implemented around the world. Each region is investing in the implementation of new technologies to meet cleaner fuel requirements. These new processing units will help produce higher-quality transportation fuels. US/Canada. The US transportation fuel

market is the world’s largest. The country's government will begin to enforce the new Tier 3 program starting in 2017. This program will set new vehicle emis-

sions standards and lower the sulfur content in gasoline. According to the US Environmental Protection Agency (EPA), sulfur content in gasoline will be limited to 10 parts per million (ppm). This is a reduction from Tier 2 standards, which limited the sulfur content in gasoline to 30 ppm. The program maintains the current refinery gate per-gallon content of 80 ppm and the 95-ppm downstream distribution cap. The EPA forecasts that the new rule will significantly reduce vehicle pollutants into the atmosphere. For example, the EPA forecasts that NOx emissions will be reduced by about 260,000 tons in 2018 alone. Large US refineries (those producing greater than 75 Mbpd) must comply with Tier 3 standards by 2017. Refiners producing below 75 Mbpd must meet Tier 3 regulation standards by 2020. To comply with new regulations, US refiners have invested in additional units, such as hydrotreaters, to reduce the sulfur content in transportation fuels. In Canada, petroleum fuels constitute 95% of Canada’s transportation energy needs. The country has aligned itself closely with US fuel standards and is making strides to continually reduce sulfur levels in transportation fuels. This includes the introduction of stringent Tier 3 fuel regulations for passenger vehicles and light-duty trucks. These fuel stan-

dards will begin in 2017, which coincides with the startup of US Tier 3 regulations. Canadian refiners have already invested over $8 B over the past decade to reduce sulfur levels in gasoline and diesel fuels. Since 2005, sulfur levels in gasoline and diesel have decreased by more than 90% and 97%, respectively. New Tier 3 standards would be instrumental in continuing to reduce sulfur in transportation fuels, as well as reducing vehicle emissions to nearly zero over the life of the vehicle. China. To help curb air pollution, the

country has set aggressive fuel economy standards through 2020. China is implementing its National V fuel quality standard, which equates to Euro 5 standard transportation fuels. Euro 5 caps sulfur content in gasoline and diesel at 10 ppm. Recent regulations required refiners to produce Euro 4 standard transportation fuels nationwide by the end of 2015. Euro 5 standard transportation fuels will be required for the automotive industry by 2017. These new regulations are being implemented one year ahead of schedule. The implementation of National V fuel quality standards for non-automotive diesel has been pushed back one year to January 2018. This includes “general” diesel used in agriculture and industry. General diesel will need to meet Euro 5 standard requirements within this time frame. Up-

TABLE 1. EU emissions standards for passenger vehicles (gasoline) CO, g/km

HC, g/km

NOx, g/km

PM, g/km

Euro 4

1.0

0.10

0.08

–

Euro 5

1.0

0.10

0.06

–

Euro 6

1.0

0.10

0.06

0.005

TABLE 2. EU emissions standards for passenger vehicles (diesel) CO, g/km

HC + NOx, g/km

NOx, g/km

PM, g/km

Euro 4

0.50

0.30

0.25

0.025

Euro 5

0.50

0.23

0.18

0.005

Euro 6

0.50

0.17

0.08

0.005

Hydrocarbon Processing | FEBRUARY 20169

Business Trends grading the nation’s fuel quality could cost Chinese refiners over $7 B. India. The country has 22 major refineries in operation, with a total throughput capacity of 4.3 MMbpd. To satisfy increasing demand for transportation fuels, India is investing upward of $30 B in additional refining projects through 2020. Capital expenditures are expected to be even higher

due to new regulations to curb air pollution and produce Euro 4 and Euro 5 standard fuels by 2020. In January, Road Transport Minister Nitin Gadkari announced that Indian refiners will need to invest $4.5 B to produce Bharat Stage 6 (BS-6) standard fuels by 2Q 2020. BS-6 fuels are equivalent to Euro 6 fuel specifications. These new regulations are being imposed four years ahead of schedule and call for a 68%

reduction in NOx emissions. Cars sold in the country are subject to BS-4 standards. India’s new regulations will bypass the BS-5 stage and move directly to BS-6. The proposed clean fuels bill was in response to a World Health Organization study that found that 13 of the world’s dirtiest cities were in India. The installation of secondary units to comply with new fuel standards could cost Indian refiners over $17 B. Indonesia. Southeast Asia’s biggest

FIG. 1. Vehicle emissions standards: global status as of February 2015. Source: United Nations Environment Program, PCFV Secretariat.

economy is the world leader in the production of palm oil, and is promoting its use as a biofuel. The country boosted the mandated amount of blending in diesel in 2014 from 7.5% to 10%, and subsequently to 15% in 2015. Indonesia raised the blending requirement to 20% this year and plans to increase it to 30% in 2020. According to the Indonesian Biofuel Producers Association, Indonesia’s biodiesel consumption will increase from 1.1 kiloliters in 2015 to 7.9 kiloliters in 2016. The additional usage of biofuels is expected to decrease vehicle emissions substantially.

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Business Trends Africa. Few countries have adopted lowsulfur fuel regulations, but multiple countries in southern Africa have announced a commitment to produce cleaner fuels by the end of the decade. The African Refiners Association has developed AFRI specifications as a guideline for the production of cleaner fuels. The region aims to produce fuels with AFRI-4 specifications by 2020. This would constitute maximum sulfur content in diesel and gasoline of 50

ppm and 150 ppm, respectively. To meet these goals, African refiners would need to invest over $7 B in additional units. The most notable clean fuels initiative has been put forth by South Africa. The country’s Clean Fuels Program 2 (CF2) is an effort to develop Euro 5 specification fuels. This would entail developing fuels to contain 10 ppm or less of sulfur, a lowering of benzene from 5% to 1%, and the reduction of aromatics from 50% to 35%.

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The CF2 program was initially designed to begin in 2017, but it has been pushed back to 2020 or beyond. The extended deadline provides South African refiners with time to make the necessary upgrades to produce cleaner fuels and is a more realistic timetable for the program’s implementation—one that could cost South African refiners billions in upgrade costs. The country’s refiners are hesitant to make the necessary upgrades due to the low return on investment. The country is also in talks with Iran to build a new clean fuels refinery in the country. The plan could replace the $10-B Project Mthombo, in the industrial port of Coega, which has been in limbo for some time. The new refinery, fed with Iranian crude, would produce Euro 5 specified fuels, meeting the government’s mandate. Other countries, such as Egypt and Algeria, are planning projects to improve local fuel quality. With ultra-modern refineries being built in Asia and the Middle East, Africa may continue importing refined products to meet demand, in lieu of investing heavily in capital-intensive projects. Middle East. The region continues to increase refining capacity to diversify exports and provide higher-quality refined products to the global market. Traditionally, Middle East refineries have had simple configurations and high fuel oil yields, partly due to strong power generation requirements. This condition is changing. A new generation of highly complex plants, combined with upgrades and expansions at existing plants, is radically altering the product mix. New unit configurations include hydrocracking, catalytic cracking and hydrotreating capacities designed to minimize fuel oil output and maximize low-sulfur middle distillate, diesel and gasoline production. Saudi Arabia and Kuwait are leading the charge in new clean fuels projects in the region. To comply with mandatory sulfur specifications for gasoline and diesel, Saudi Arabia is spending billions of dollars to construct multiple clean fuels projects. The country is seeking to reduce sulfur content in diesel and gasoline to 10 ppm and to lower benzene content in gasoline to 1%. This represents a dramatic shift in sulfur levels from 2012, when Saudi Arabia’s maximum sulfur level for diesel was greater than 500 ppm. The country plans to commission its 400-Mbpd Jazan refin-

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Business Trends ery by 2018. The refinery will produce higher-grade transportation fuels, including ultra-low-sulfur diesel. Along with its JVs, Saudi Aramco will upgrade all of its domestic refineries to produce lower-sulfur transportation fuels. Several projects—the Ras Tanura Refinery Clean Fuels and Aromatics project (which was on hold, but was reinstated in mid-2015), the Riyadh Refinery Clean Transportation Fuel project, the Saudi Aramco Mobil Refinery Co. Clean Fuels project (completed in 2014) and the PetroRabigh Clean Fuels project—are designed to accomplish the Kingdom’s goal of producing near-zero-sulfur fuels. Kuwait is investing over $30 B on ambitious plans to overhaul its refining sector and become the region’s clean fuels leader. The plan focuses on modernizing and integrating the country’s Mina Abdullah and Mina Al-Ahmadi refineries, as well as on building the region’s largest refinery, the Al-Zour plant. Once completed, the reconfigured and integrated Mina Abdullah and Mina Al-Ahmadi refineries will decrease the sulfur in gasoline production from 500 ppm to less than 10 ppm. Ben-

zene and aromatics concentrations will also decrease. Bunker fuel oil sulfur content will decrease from 4.5 ppm to 1 ppm, and maximum sulfur content of full-range naphtha will drop from 700 ppm to 500 ppm. With the construction of Al-Zour and the upgrading and integration of its domestic refineries, Kuwait is set to become the largest producer of clean fuels in the Middle East by 2019. Other countries in the region are also making sizable investments to produce higher-quality transportation fuels. Efforts include the Ruwais refinery expansion (completed in 2015), the Jebel Ali and Fujairah projects in the UAE, the Sohar refinery upgrade and Duqm refinery projects in Oman, the Sitra refinery modernization project in Bahrain, and the SOCAR Turkey Aegean Refinery project in Turkey. Latin America. Due to the growth in

the region’s middle class, Latin America has seen tremendous petroleum product demand growth over the past decade. Demand has been shifting to more middle and light distillates, as opposed to fuel oil.

Multiple refinery upgrades, expansions and greenfield facilities have been delayed or canceled due to the drop in oil prices. Latin American countries, which rely heavily on oil export revenues, have been hit hard by the drop in oil prices. In turn, this has left little money to fund capacity expansions and upgrades to produce higher-grade transportation fuels. New clean fuels initiatives are taking place in the region, however. In late 2014, Brazil increased its ethanol blending mandate in gasoline from 5% to 7% and in diesel from 25% to 27%. These new blend requirements, along with the startup of new refining capacity, are forecast to help mitigate a substantial portion of refined fuel imports. Additional refinery plans have been announced, but massive debt, corruption and cost overruns have put projects on the back burner. In late 2015, Mexico’s state-owned oil company, Pemex, announced plans to reinstate its domestic refinery upgrade program. The $23-B investment will upgrade Pemex’s refining system to increase production of cleaner-burning diesel and

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Business Trends gasoline. The plan’s goal is to more than double the production of ultra-low-sulfur gasoline and increase the production of ultra-low-sulfur diesel. Colombia is also investing heavily in the production of higher-grade transportation fuels. State-owned Ecopetrol plans to complete the full ramp-up of its Cartagena refinery in 2Q 2016. The $7-B expansion project more than doubled capacity to 165 Mbpd, which included the modernization of the existing refinery to take advantage of the new complex and improve efficiencies. The project will help reduce regional refining constraints; produce ultra-lowsulfur gasoline and diesel from heavy, high-sulfur crudes; adhere to the latest emissions protocols and requirements; increase the refinery’s conversion capacity from 76% to 95%; and meet international standards for transportation fuels. Russia. The country produces more than enough refined products to meet domestic demand, but it lacks advanced facilities to produce higher-grade transportation fuels, such as Euro 4 and Euro 5 fuels. In

response, Russia launched a $55-B program in 2011 to modernize its existing plants and encourage exports of highquality products. The plan called for the installation of 130 new units by 2020. The program saw delays in 2015 due to falling oil prices and Western sanctions, which have limited the ability for Russian companies to secure financing. The peak of Russia’s modernization program is forecast for 2016–2018. The country’s two largest refiners, Rosneft and Lukoil, have led the charge on refinery upgrades to produce Euro 4 and Euro 5 fuels. Smaller Russian refiners are also upgrading their refineries to reduce sulfur content in transportation fuels. Russia's modernization program will continue to focus on increasing its light products yields, with a key focus on meeting demand for gasoline and jet fuel, increasing fuel standards to Euro 5 specifications, and replacing old units to decrease residual product yields and maximize utilization. Bunker fuels. A major change for European Union (EU) refineries is the required

sulfur content reductions for marine fuels. Marine fuels constitute about 7% of EU refining output, according to Concawe. New regulations kicked into effect in 2015 that require shippers to switch from marine residual fuels to lower-sulfur marine fuels in designated emission control areas (ECAs). These areas include the Baltic and North Sea, coastal areas off of the US and Canada, and the US Caribbean Sea. Sulfur content in marine fuels consumed in ECAs was capped at 0.1%, the same quality as lower-sulfur distillate materials. The International Convention for the Prevention of Pollution from Ships (MARPOL) directive also sets limits on marine fuels in non-ECAs. Beginning in 2020, the sulfur content of marine fuels used in non-ECAs will be reduced from 3.5% to 0.5%. Although the initial start date of this new regulation is January 1, 2020, the plan will be reviewed in 2018 to check the availability of the required fuel oil. Depending on the outcome of the review, the startup date of new non-ECA sulfur regulations could be postponed until at least 2025.

Drier Steam Means Higher Profits Steam drum design is critical to maintain steam dryness and water quality for optimum performance of your boiler. If water is allowed to carryover, then damage can occur and energy is lost. Carryover is your boiler’s enemy. Dyna-Therm’s high performance steam drums have been protecting downstream equipment including superheater tubes and turbines for decades. We offer proven designs for the following: • High pressure • Intermediate pressure • Low pressure • Retrofitting of existing drum internals No steam production rates are too high and no carryover problems are too difficult for us to solve—steam qualities of 99.995% with .001 PPM/TDS are possible!

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This water wash injector uses an offset flange and a WhirlJet® hollow cone nozzle. A CFD study determined that this design provides the best coverage without heavy wall impingement.

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MIKE RHODES, MANAGING EDITOR [email protected]

Industry Metrics

7

Cracking spread, US$/bbl

10 0

Dec.-15

Nov.-15

Oct.-15

Sept.-15

July-15

May-15

June-15

Dec.-15

Nov.-15

Oct.-15

Sept.-15

Aug.-15

July-15

June-15

Dec.-15

Nov.-15

Oct.-15

Sept.-15

Aug.-15

July-15

June-15

May-15

Prem. gasoline unl. 98, 10 ppm S Jet/kero

Gasoil, 10 ppm S Fuel oil, 1% S

Dec.-15

Nov.-15

Oct.-15

Sept.-15

Aug.-15

July-15

June-15

May-15

April-15

Mar.-15

Feb.-15

-10 -20

Singapore cracking spread vs. Dubai, 2014–2015*

Brent dated vs. sour grades (Urals and Dubai) spread, 2015*

Dec.-15

Nov.-15

Oct.-15

Aug.-15

July-15

June-15

May-15

April-15

Gasoil, 50 ppm S Fuel oil, 180 cSt, 2% S

Sept.-15

July-31 Aug.-07 Aug.-14 Aug.-21 Aug.-28 Sept.-04 Sept.-11 Sept.-18 Sept.-25 Oct.-02 Oct.-09 Oct.-16 Oct.-23 Oct.-30 Nov.-06 Nov.-13 Nov.-20 Nov.-27 Dec.-04 Dec.-11 Dec.-18 Dec.-25 Jan.-01 Jan.-08

Dubai Urals

Prem. gasoline unl. 92 Jet/kero

Mar.-15

0

0

-10 -20

Feb.-15

2

10

Dec.-14

4

20

Jan.-15

Cracking spread, US$/bbl

30

6 Light sweet/medium sour crude spread, US$/bbl

April-15

20

Source: EIA Short-Term Energy Outlook, January 2016.

-2 -4

April-15

Mar.-15

40 30

Dec.-14

2017-Q1

6 5 4 3 2 1 0 -1 -2 -3

Stock change and balance, MMbpd

Supply and demand, MMbpd

2016-Q1

Mar.-15

Rotterdam cracking spread vs. Brent, 2014–2015*

World liquid fuel supply and demand, MMbpd Forecast

Fuel oil, 180c

Prem. gasoline unl. 93 Jet/kero Gasoil/diesel, 0.05% S

Feb.-15

Cracking spread, US$/bbl

60 50 40 30 20 10 0 -10 Dec.-14

Oil prices, $/bbl

115 105 95 85 75 W. Texas Inter. 65 Brent Blend 55 Dubai Fateh 45 Source: DOE 35 D J F M A M J J A S O N D J F M A M J J A S O N D 2013 2014 2015

2015-Q1

Feb.-15

US Gulf cracking spread vs. WTI, 2014–2015*

Selected world oil prices, $/bbl

100 Stock change and balance 98 World supply 96 World demand 94 92 90 88 86 84 82 2011-Q1 2012-Q1 2013-Q1 2014-Q1

May-15

Production equals U.S. marketed production, wet gas. Source: EIA.

Japan Singapore April-15

60

US EU 16

Mar.-15

D J F M A M J J A S O N D J F M A M J J A S O N D 2013 2014 2015

70

Jan.-15

0

80

Jan.-15

20

2 1 0

Feb.-15

Monthly price (Henry Hub) 12-month price avg. Production

Jan.-15

3

40

90

Utilization rates, %

4

Dec.-14

60

100

Gas prices, $/Mcf

Production, Bcfd

5

Brent, Rotterdam

Global refining utilization rates, 2014–2015*

6

80

Jan.-15

US gas production (Bcfd) and prices ($/Mcf) 100

Arab Heavy, US Gulf LLS, US Gulf

WTI, US Gulf Dubai, Singapore

Aug.-15

16 14 12 10 8 6 4 2 0 Dec.-14

An expanded version of Industry Metrics can be found online at HydrocarbonProcessing.com.

Global refining margins, 2014–2015* Margins, US$/bbl

US product markets weakened despite unseasonably strong gasoline demand, and the gasoil crack spread hit the lowest level seen in more than five years, under pressure from increasing supplies amid thin demand due to warmer winter weather. Asian margins remained relatively healthy due to stronger regional demand for gasoline and naphtha. European markets exhibited mixed performance.

* Material published permission of the OPEC Secretariat; copyright 2016; all rights reserved; OPEC Monthly Oil Market Report, January 2016. Hydrocarbon Processing | FEBRUARY 201619

Select 99 at www.HydrocarbonProcessing.com/RS

LEE NICHOLS, EDITOR/ASSOCIATE PUBLISHER [email protected]

Global Project Data At present, Hydrocarbon Processing’s Construction Boxscore Database is tracking over 2,100 projects around the world. At the time of this publication, approximately 60% of active projects are in the preconstruction stage. The Asia-Pacific region continues to dominate in total active projects in all sectors of the downstream

hydrocarbon processing industry. The closest contender is the Middle East, which has witnessed a significant number of downstream projects over the past several years. The region continues to increase refining, petrochemical and lube operations to provide value addition and portfolio diversification.

39 16

6

119

16

Canada

115

106 88 35

95

55

Europe

26

162

142 75

US

63 32

42

28

105 63

Refining Petrochemical Gas processing/LNG Other

51

Middle East

189 205 112 71

Africa

46 39

Asia-Pacific

Latin America

Total active projects by region and sector, 2016 30 24 21

26

25

27 22 17

17

18

26 20

27% Planning 18

13

Dec- Jan- Feb- Mar- Apr- May- Jun- Jul- Aug- Sep- Oct- Nov- Dec- Jan14 15 15 15 15 15 15 15 15 15 15 15 15 16

Boxscore new project announcements, December 2014–present

40% Under construction 6% Study 10% FEED 17% Engineering Breakdown of downstream HPI projects by activity level

Detailed and up-to-date information for active construction projects in the refining, gas processing and petrochemical industries across the globe | ConstructionBoxscore.com Hydrocarbon Processing | FEBRUARY 2016 21

COMPLETE SOLUTIONS FOR YOUR REFINERY CHALLENGES Today’s Refinery Challenges ƒ Processing tight oil ƒ Managing stringent sulfur limits ƒ Monetizing orphan streams ƒ Upgrading residuals CB&I’s Comprehensive Solutions We are with you through every stage of the process plant life cycle, from feasibility studies through technology selection, full-scope EPC, commissioning and start-up, to plant optimization and upgrades. CB&I’s broad portfolio of both refining and petrochemical technologies, combined with our execution expertise, will help you maximize processing flexibility and achieve margin benefits in the widest range of scenarios. PROCESS PLANNING AND DEVELOPMENT LICENSED TECHNOLOGIES AND CATALYSTS FULL-SCOPE EPFC SERVICES PROJECT MANAGEMENT AND CONSULTING AFTERMARKET SERVICES

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Reliability

HEINZ P. BLOCH, RELIABILITY/EQUIPMENT EDITOR [email protected]

Combine metallurgical, structural and physics know-how We recently received an update on the capabilities of a modern professional entity that combines metallurgical, structural and practical applied physics know-how in a US Gulf Coast location (see www.knighthawk.com). Combining these areas of expertise is taking on increasing importance to the petrochemical and oil refining industries. In years past, it was customary for these industries to send failed parts to stand-alone laboratories. These laboratories then subjected the components to one or more types of metallurgical analyses. Their findings were typically reported in a language understood only by other trained metallurgists. If the client was fortunate, the report would attribute the failure to, for example, “high cycle fatigue.” The equipment owner would then be tasked to determine what vibrated, why it vibrated and how the problem should be cured. Combining knowledge areas in specialized laboratories. Fortunately, today, users have access to metallurgical labs that take into account all of the above knowledge areas. As an example, Knighthawk often begins an investigation by using a scanning electron microscope (SEM) to find failure mechanisms. Its detailed reports then comment on contributing issues, such as environmentally assisted cracking. The company uses energy-dispersive spectroscopy in making corrosion assessments of certain nickel alloys found in the hydrocarbon processing industry. Here, too, suitable techniques make microscopic fatigue failures visible and distinguish surface flaws from subsurface flaws. Measuring the length of striations—which usually occur once per cycle—is well within the capabilities of a modern metallurgical laboratory, as is optical microscopy. Established as an advanced laboratory, Knighthawk can conduct field metallography to determine, among many other items of interest, boiler tube heat excursions and stages of creep. This laboratory moves on to determine and quantify fitness for service based on measuring the depth of decarburization. As an example, its reports have squarely (and without “hedging bets”) attributed root-cause reasons to flawed post-weld heat treatment. Design reviews in parallel with investigations. Time is of the essence in failure investigations. Accordingly, we were impressed with the initiatives advocated and pursued by Knighthawk. These concentrated on a review of the entire system. Secondary modes of failure were occasionally identified, and long-term monitoring was mapped out, in some instances. Process parameters were closely examined, and process dynamics were reviewed with modern computer tools. In many

Length of spline engagement

Spline straight

Spline twisted

Torque

Twist plane

Torque

FIG. 1. Ductile twisted spline.

instances, Knighthawk initiated the development of a computational fluid dynamics model and surprised the client with unanticipated findings. Our advice is to work with practical experts and conduct several types of investigations in parallel. Recall the Deepwater Horizon disaster. When aspersions were cast on many kinds of equipment, Knighthawk carried out metallurgical investigations on a supplier’s product and established—authoritatively and conclusively—that the supplier had provided flawless products. Here is proof that it pays to work with experts. Never overlook practical knowledge. However, we do not want to leave the impression that one should only work with laboratories. Many times, a plant or facility will greatly benefit from calling in an expert with decades of practical work experience in the exact industry where a particular failure has taken place. The answer can be found on p. 271 of Analytical Troubleshooting of Process Machinery and Pressure Vessels by Anthony Sofronas, where an expert looks at fretting and wear (FIG. 1). Both are usually associated with misalignment or lubrication issues. Fatigue failures can result from cyclic torques, such as those occurring from torsional vibration or from bending fatigue originating with defective shaft couplings. A twisted spline is the signature of bulk yielding of the shaft due to excessive torque; fatigue is ruled out here. The question, then, becomes: What torque is required to produce such permanent deformation? Rest assured that the practical expert knows your machine and will explain it! HEINZ P. BLOCH resides in Westminster, Colorado. His professional career commenced in 1962 and included long-term assignments as Exxon Chemical’s regional machinery specialist for the US. He has authored over 650 publications, among them 19 comprehensive books on practical machinery management, failure analysis, failure avoidance, compressors, steam turbines, pumps, oil mist lubrication and practical lubrication for industry. Mr. Bloch holds BS and MS degrees in mechanical engineering. He is an ASME life fellow and maintains registration as a professional engineer in New Jersey and Texas. Hydrocarbon Processing | FEBRUARY 2016 23

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Global

SHEM OIRERE Contributing Writer

Reforms will shape future of Nigeria’s refining industry

Crude program blamed for refinery underperformance. A report published by the nonprofit policy advisory and advocacy organization Natural Resource Governance Institute (NRGI) singled out the Domestic Crude Allocation (DCA) program as the leading cause of the chronic poor performance by Nigerian refineries. The report advocates the scrapping of the DCA scheme to create opportunities for competition in the supply of crude oil, and also to pave the way for a possible privatization of the plants as a long-term solution to boosting crude oil refining in Nigeria. Under the DCA program, the government allocates 445 Mbpd to NNPC, which transmits the crude to its subsidiary, Pipelines and Product Marketing Co. (PPMC). PPMC then sends the supplies to the three refineries for processing. PPMC is, in turn, tasked with selling the refined products (including gasoline, jet fuel, diesel, fuel oil and liquefied petroleum gas) and using the proceeds to pay NNPC for the crude feedstock. NNPC is also required to pay the government for the allocated 445 Mbpd of oil. However, the NRGI report, released in August 2015, claims that the DCA has become the main cause of waste and revenue loss from NNPC oil sales, with the Nigerian treasury receiving only 58% of the $16.8-B value of the oil. According to the report, the DCA was designed to feed Nigeria’s refineries, although NNPC actually exports three-quar-

ters of the domestic crude oil. In practice, the refineries process approximately 100 Mbpd (NNPC statistics peg the figure at 64 Mbpd), with NNPC ultimately rerouting most of the DCA oil into export sales and oil-for-product swaps. The payments enter separate NNPC accounts, which NNPC officials then draw upon freely, according to the NRGI. The Nigeria Extractive Industries Transparency Initiative (NEITI) had also called for the termination of the DCA plan because the three refineries have been operating at low capacities for many years, with the extra crude being diverted to meet the Offshore Processing Agreement (OPA). NNPC signed the OPA at the beginning of last year with Duke Oil Co. Inc., Aiteo Energy Resources Ltd. and Sahara Energy Resources, under which the corporation allocated 210 Mbpd for refining at companies’ offshore locations in exchange for petroleum products at a pre-agreed yield amount. However, the contracts were revoked in August, with the new NNPC management team claiming that they were skewed in favor of the companies, such that the value of product delivered was significantly lower than the equivalent crude oil allocated for the program. NNPC contract fluctuations impact crude use. NNPC also terminated a contract for the delivery of crude oil to the three refineries using marine vessels, claiming that the contract cost was exorbitant and the process of engagement was inappropriate. In the short term, NNPC has mandated its subsidiary, NIDAS Marine Ltd., to deliver crude oil to the refineries pending the establishment of a more advantageous contract. NEITI’s Zainab Ahmed told Nigerian media in August that some of the changes by NNPC may have resulted in “…a lit60 KRPC PHRC WRPC

50 40

%

Oil-rich Nigeria’s new presidential administration has announced several changes in the country’s oil sector, as it sets out to fulfill a pre-election campaign pledge by President Muhammadu Buhari to streamline the West African nation’s hydrocarbon industry. Among the administration’s goals are the eradication of corruption and mismanagement that brought the country’s three state-run refineries to their knees. Port Harcourt Refining Co. (PHRC), Kaduna Refining and Petrochemical Co. (KRPC) and Warri Refining and Petrochemical Co. (WRPC) are chronically underperforming, with an average throughput of 64 Mbpd last year—or approximately 14% of their nameplate capacity. Nigerian National Petroleum Corp. (NNPC), the owner of the refineries, reports that PHRC has a 210-Mbpd capacity, while KRPC and WRPC have capacities of 110 Mbpd and 125 Mbpd, respectively. At present, the country meets 70% of its fuel needs through imports. Analysts say that these refineries have attracted little investment because the facilities are known for a high level of corruption, poor maintenance, theft and operational hiccups. The oil sector reforms proposed by President Buhari include identifying specific factors that hamper investment in the refineries, along with their causes; what the government can do to address these issues; and how the private sector can be brought on board for the revival and management of the plants.

30 20 10 0

Jan.

Feb.

Mar.

April

May

June July Month

Aug.

Sept.

Oct.

Nov.

Dec.

FIG. 1. Refinery capacity utilization in Nigeria, 2014. Hydrocarbon Processing | FEBRUARY 2016 25

Global tle improvement [on refinery performance], but still far from their installed capacity, which is below 30%.” Mr. Ahmed also suggested that the reduction of the domestic crude allocation to NNPC would “serve as incentive for refineries to improve their capacity development.” Although Nigeria produces an average of 63.34 MMbbl of crude oil and condensate, the country’s refineries process only 261 Mbbl with the three refineries’ combined capacity utilization, according to NNPC. This discrepancy is not unique to Nigeria. Market analyst Wood Mackenzie reported a 7-MMbpd gap between crude production and refinery output in Africa between 2010 and 2013. Refinery maintenance issues dent profits. NNPC reported that the utilization levels of the refineries dropped from 11.18% between January and August 2014, before shutting down between February and June of 2015, when the corporation implemented a much-discredited maintenance program for the three processing plants. The utilization level increased by 13.62% in July 2015 and by 24.08% in August 2015, before plunging to an all-time low of 1.96% in September 2015. Under the maintenance program, NNPC planned to rehabilitate the refineries, using the original refinery builders for each plant. However, the builders declined the offer and, instead, nominated partners to perform the rehabilitation. NNPC rejected the partners’ price offers, based on the high estimated costs. In August 2015, however, new NNPC Group Managing Director Ibe Kachikwu hinted at the possibility of incorporating private investors into the revival and expansion of Nigeria’s state-run refineries. Mr. Kachikwu advocated establishing some level of independence, along with performing turnaround maintenance when it is due and creating contractual models to make the businesses profitable. At present, the refineries are losing more than $200 MM/month as a result of underperformance. Suggested reform plans drive discussion. The NRGI

has made several suggestions that President Buhari’s administration may find useful in reforming Nigeria’s hydrocarbon processing sector. The NRGI says that NNPC should consider granting the refineries operational independence and leasing refining capacity from them in exchange for providing crude oil. The provision could be in the form of a repurchase agreement, under which the corporation would buy crude from its upstream partners on behalf of the refineries. The agreement would leave room for additional parent-subsidiary sales, with volumes capped at the refineries’ actual needs. Another option presented by the NRGI is to force the refineries to buy their own oil from upstream operators, although the report cautions that some producers might be initially hesitant to conduct business with the underperforming, cashstarved refineries. The government could also consider the controversial proposal of new legislation that coerces international oil companies or other operators to sell parts of their equity production to the refineries. “Finding the best transaction type depends in part on whether the government plans to change the refineries’ ownership and management structures—for example, by signing product-sharing and technical service contracts with competent foreign refining companies, or by selling off equity

26 FEBRUARY 2016 | HydrocarbonProcessing.com

to a private investor through a formal privatization exercise,” reported the NRGI. In the meantime, Mr. Kachikwu said that NNPC plans to proceed with the construction of new refineries next to the existing ones to increase the capacity of Nigeria’s light petroleum products for domestic consumption and export markets. In 2000, NNPC said it planned three new crude processing plants with a combined capacity of 400 Mbpd–550 Mbpd in Lagos, Bayelsa and Kogi. “The strategy is to develop investment consortia—in partnership with local and foreign investors—for these projects, with the government only retaining a minority interest,” announced NNPC in a 2002 release. The corporation said that the consortia would then decide on the locations, configurations and shareholdings of the refineries. A feasibility study by Mackenzie Energy Consulting Ltd. and Foster Wheeler Energy in 2011 reported that the planned refineries were economically viable, and proposed capacities of 200 Mbpd for Lagos, 100 Mbpd for Kogi and 100 Mbpd for Bayelsa. According to NNPC, with the completion of the new refineries, West and Central African countries will look to Nigeria for fuel supplies and discontinue imports from Northwest Europe, the Middle East and Asia. Lagos private refinery project under development. Dangote Group, owned by Africa’s wealthiest man, Aliko Dangote, has received approval to build a $9-B refinery, along with fertilizer and petrochemical plants, in Lagos, Nigeria. The refinery, which would have an estimated capacity of 500 Mbpd to 650 Mbpd, is the first private crude processing plant in Nigeria in decades, after the cancellation and delay of earlier projects due to uncertainties surrounding government plans to deregulate the downstream sector. Dangote Group has acquired interests in at least three blocks to secure feedstock for the new refinery, which is planned to come online in 2017, at the earliest. The company has also taken up to a 9% stake in Block 1 in the joint development zone between Nigeria and São-Tomé. Other partners include Chevron and ExxonMobil. Additionally, Dangote Group has acquired a 10% interest in Block 3 in the same basin where Anadarko operates, as well as a 6% investment in Block 315 with partners Statoil and Petrobas. In late 2014, Dangote Group reported that it had signed a $3.3B loan agreement with a consortium of local and foreign backers to fund the ambitious refinery project. The company is expected to provide $3 B in equity, while $6 B will come from loan capital. After many decades of mismanagement and corruption in Nigeria’s downstream sector, it is hoped that the ongoing industry reforms will help transform the country’s refineries into viable business entities. SHEM OIRERE has reported widely on the business beat for Kenyan newspapers The Daily Nation, Kenya Times and The People. He also freelances, reporting extensively on Africa’s energy, construction and chemical industries for various international publications. He graduated from journalism school in London.

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| Special Report CLEAN FUELS AND THE ENVIRONMENT The global refining industry continues to invest with the goals of increasing processing flexibility, reliability and safety. Outside of the US, demand for transportation fuels is shifting toward diesel and other middle distillates. However, gasoline demand will continue to increase in developing nations. The highestdemand region for refined products and transportation fuels remains Asia-Pacific. Refiners will continue to make investments to increase environmental and sustainability performance, as well. The special report investigates opportunities available to cost-effectively process clean transportation fuels and products, and adhere to existing and impending environmental regulations. Photo courtesy of Saudi Aramco Total Refining and Petrochemical Co. (SATORP).

Special Report

Clean Fuels and the Environment C. CHAU, R. SCHILLER and M. ZIEBARTH, W. R. Grace, Worms, Germany

Maximize petrochemicals in the FCCU to increase refinery margins and improve gasoline pool quality rent market dynamics, challenging the FCCU to move out of its Over the last several years, the refining industry has been “maximum gasoline” comfort zone is a winning strategy to drive weathering a storm of volatile market conditions. Overall overall refinery profitability. growth in fuels demand and global gross domestic product have driven new refinery construction and supported refinery utilization rates. Refiners have also had to contend with extreme oil Optimizing FCC products. The FCCU is at the heart of the remarket volatility, driven in part by the shale, or tight oil, revofinery and plays a key role in operations due to its remarkable calution in North America (NA). Additionally, more stringent pability to convert a wide range of hydrocarbons into more valuenvironmental regulations for fuels quality have required refinable products—including gasoline, but also light olefins, such as ers to make capital investments and alter operating strategies to propylene and butylenes—for both refining and petrochemical maintain compliance. These shifts, among others, have created applications. Beyond its core role in producing transportation a dynamic market environment that requires flexibility. fuels, as described in FIG. 1, the FCCU can play a major role The most flexible unit within any refinery is the fluid catawhen integrated into a petrochemical-oriented complex. The lytic cracking unit (FCCU). Refiners need that flexibility to FCCU has the ability to adapt to changing market conditions operate with a dynamic feed slate of varying quality, as well as and the relative demands of fuels and petrochemicals. Maxito produce a range of products to meet market demand. The mum unit profitability relies on the constant optimization of shift to more liquefied petroleum gas (LPG) olefins production the value of FCC products through high-performance catalytic using the FCCU is worth noting. The majority of new refinery solutions. Specific emphasis is given in this article on innovaconstruction in the Middle East and Asia-Pacific is geared totive solutions and opportunities offered to refiners when impleward maximum propylene operations to feed either existing or new downstream Fuel gas petrochemical processing. In existing reAmine SRU Sulfur fineries, a general trend toward incremenunit H2 tal octane has been observed. Tight oils LPG H2 Isomerization C3 often result in lower refinery pool octane Total naphtha C4 due to the nature of the hydrocarbons H2 HDT C3= C3= present in the feedstock. Catalytic Crude Crude reformer Increasingly stringent environmental distillation Gasoline Ethanol H2 unit regulation is causing more refiners to seek Naphtha solutions to offset octane loss due to deepU95 iC4= HDS ETBE Atm. er hydrotreating of the naphtha streams to U98 residue nC4= remove sulfur. Incremental high-octane, C4= VGO HDS/MHC Alkylation zero-sulfur gasoline blendstock from the Vacuum Diesel LVGO H2 H2 Selective alkylation complex compensates for ocdistillation FCC Jet fuel gasoline HVGO unit tane loss due to post-treater severity. It Hydrocracker Diesel LCO HDT also enables refinery compliance with Heating H2 Vacuum residue oil strict fuels regulations. An additional Visbreaker Clarified oil burden on catalytic reforming has also Residue occurred with tight oil in refinery crude. Fuel oil Aside from capacity, to maximize alkylate Coker naphtha to NHDT LS FO LCGO/HCGO to HDT or FCC production, the FCC feedstock must be HS FO Coker PetCoke available in the refinery. The FCC process has the flexibility to meet these product demands when optimized with the right FIG. 1. The FCCU: A fully integrated unit with the flexibility to maximize light olefins for alkylation catalyst technology. In light of the cur- or petrochemicals. Hydrocarbon Processing | FEBRUARY 201629

Clean Fuels and the Environment ing (DCC), but the use of highly selective and active catalysts can continue to drive propylene yields in traditional FCCUs.1 Besides the LPG consumed by refining applications, propylene is a raw material and a precursor to various chemicals, as shown in FIG. 3A. Propylene can be routed through various reaction schemes for final use in resins, fibers, solvents or polymers. Propylene can also be sent to an alkylation unit as a supplement to butylenes feedstock for high-value gasoline production. Butylenes can be used as starting chemicals for the copolymer industry or as polyisobutylene rubber (FIG. 3B) as an alternate to automotive fuel applications through the etherification of isobutylene into ethers—namely methyl tert-butyl ether (MTBE) and ethyl tert-butyl ether (ETBE)—to boost gasoline octane. FCCUs play a significant role in supplying incremental propylene and butylene demand from petrochemical markets, since ethane steam cracking generates mostly ethylene, whereas higher olefins are produced by naphtha steam cracking. Butylene contributes by far the most to gasoline production via alkylation, with a continuous increase in capacity and demand worldwide, shown in FIG. 4, even though alkylation capacity in the US remains relatively constant despite refinery rationalization over the same period. Aromatics—Aromatic components resulting from crack160 ing at elevated temperatures in the FCCU may also be valuable 140 for petrochemical applications. The catalytic reforming process Propylene gap produces most of the aromatic streams for refining, as well as 120 xylenes for petrochemicals. Benzene extraction from FCC naph100 tha is an option that is being considered to both comply with C3= other sources gasoline specifications and add value to the aromatics produced, 80 but this option requires capital investment. Moreover, steam C3= ex-refinery crackers and new unit constructions and startups in the petro60 chemical sector do target increased aromatic production, and, 40 as a result, extraction of aromatics from the FCCU is not the C3= ex-steam cracking preferred option. Extracting aromatics from FCC streams could 20 become more popular in the future if specifications on aromatic 0 content of gasoline become more stringent. Direct extraction of 2005 2010 2015 2020 2000 aromatics from FCC gasoline can also help rebalance gasoline FIG. 2. Selective propylene production needed to fill a growing surplus in some regions. Besides blending strategies, alkylation demand gap. Sources, forecasts and permission: IHS Chemical. units, which produce high-octane gasoline without aromatics, are the best option for refiners to comply C4 Based chemicals with aromatic specs in gasoline. This opFibers PP n-butane Resins tion will be discussed further below. Syn gas Resins Polybutadiene Optimizing products from changOxo2 Ethylhexanol Pesticides 1,3-butadiene alcohols butanol SER Pharmaceuticals ing feedstocks—The FCCU’s flexibility ABS resin Propylene Propylene Polyester Fibers 1-butene is also linked to its ability to process feedHexamethylene- Adipic oxide glycol Resins 2-butene stocks with a wide range of properties, Adiponitrile Nylon-6,6 acid diamine HCN Acrylic fiber Synthetic wool mainly in terms of specific gravity, contamAcrylonitrile acrylic resins Polyacrylic acid-diapers inants, Conradson carbon and crackabilPropylene Phenolic resins Maleic C6H6 O2 BDO THF n-butane Phenol Polycarbonate-CDs, anhydride ity, as reflected by paraffinic, naphthenic comp. casings Cumene and aromatic content. This flexibility is Solvents Acetone Polyisobutylene made possible by selecting the proper opMMA-plexiglass H2O (butyl rubber) erating conditions, and by using optimized Isopropyl Solvents Methyl tertiary butyl ether (MTBE) alcohol Personal care products catalysts, as described in the next section. i-butene Methanol O2 Acrylic Methacrolein Methacrylic Methyl methacrylate Acrylic Coatings Whether processing nickel- (Ni) and vaacid acid esters Resins nadium- (V) containing residue, or proiC4 Formaldehyde+ethylene Gasoline Alkylate cessing shale oil with higher levels of iron Butenes Ethylene propylene copolymers and calcium, FCCUs must achieve maxiA B mum bottoms upgrading despite facing a FIG. 3. The propylene and butane/butylene petrochemical value chains. challenging variety of feed contaminants. Propylene demand, metric MMtpy

menting dual-zeolite FCC catalysts for enhanced butylenes and the subsequent optimization of downstream alkylation units. Light olefins—Production of propylene and butylenes best illustrates the optimization strategy and balance between refining and petrochemicals. Optimizing propylene yield is beneficial to the profitability of numerous FCCUs. Propylene yields can be increased from 3 wt% to 5 wt% in conventional FCCUs, and from 12 wt% to 30 wt% in high-severity FCCUs. Propylene demand is increasing (FIG. 2), and, apart from the steam cracking, refineries are a key source. With a shift from naphtha toward lighter feedstocks, such as shale gas and ethane feeds, steam crackers, especially the newly erected large units, are producing less propylene. To partially fill the supply gap, “on-purpose” propylene is needed from alternate or complementary technologies: propane dehydrogenation (PDH), methanol-to-olefins (MTO) from gas or coal, olefins cracking and metathesis. Despite being thought of as a mature technology, FCC can play an increasing role in satisfying higher propylene demand. Several new FCC-type processes to maximize propylene have been introduced to the market, namely high-severity FCC (HS-FCC) and deep catalytic crack-

30FEBRUARY 2016 | HydrocarbonProcessing.com

Clean Fuels and the Environment push the FCCU to its operating limits, producing higher-value yields, often with higher throughputs. Close collaboration between the catalyst supplier and refiners contributes to FCCU profit optimization. This can be achieved by the proper choice and application of customized catalyst formulations and additives. Innovative FCC catalysts and additives—developed by representative testing and deactivation methods at the pilot scale—that mimic industrial commercial equilibrium catalyst (Ecat) properties have demonstrated improved profitability in

Alkylation capacity, Mbpd

Fine-tuned catalyst formulations are required for the FCCU to expand its operational flexibility within common unit constraints like air availability, delta coke, regenerator temperature, catalyst circulation, riser temperature, wet gas compressor limit, LPG handling capacity or downstream separation of LPG olefins, etc. The requirement to maximize product values in demanding market conditions and a competitive environment is equally important in adapting to challenging feeds. Generally, the deeper the feed conversion, the higher the added value, except in the case of high light cycle oil (LCO) demand, 2,500 when lower 430°F (221°C) conversion is desirable. Maximizing the conversion of Ex-US US the bottom of the barrel and pushing FCC 2,000 Worldwide flexibility to its limits, out of the “comfort zone,” increases unit profitability through the optimal balance of propylene, butyl1,500 ene, gasoline and distillates. The balance between refining and 1,000 petrochemicals is crucial to maximize the product slate value in the face of market dynamics. 500

Optimizing the FCC catalyst. Challenging the comfort zone by operating at multiple constraints drives improved unit profitability. Fine-tuned FCC catalyst formulations are developed and designed to

0 1990

1995

2000

2005

2010

2015

FIG. 4. Increasing alkylation capacity worldwide, driving butylenes demand in refining sector (data by Oil and Gas Journal).

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Clean Fuels and the Environment commercial FCCUs.2, 3 Customized catalysts are a key tool for refiners to match—with a wider flexibility—light olefins production to the market demand. FIG. 5 illustrates a multi-faceted approach to optimize gasoline octane and LPG olefins within the FCCU’s constraints, using: • Adjusted operating conditions or changes in feedstocks • Octane and olefin boosting ZSM-5 additives • New FCC catalysts • Dual-zeolite catalysts that increase butylene yield. Changes in operating conditions or feedstocks—Depending on economics, refiners make changes to their operating strategies to maximize total FCC gasoline, gasoline plus alkylate or gasoline plus distillate. Operating conditions and strategies are of primary importance, but many refiners do not have the flexibility to drive significant yield shifts with operational moves alone. However, significant shifts can be achieved with a catalyst formulation optimized for the refinery crude slate, objectives and limitations. Customized catalytic systems and optimized formulations enable the maximization of the FCCU’s profitability within the unit constraints.4 LPG handling capability, wet gas compressor capacity or regenerator temperature are some of the constraints that can limit FCCU operating flexibility. From an operational standpoint, increasing reactor temperature will improve octane but also LPG conversion. Higher conversion and LPG yield may not be desirable in the face of an LPG constraint. Product olefinicity can be modified by adjusting FCC catalyst zeolite unit cell size (UCS) by changing the rare earth to zeolite (RE/Z) ratio. Minimizing hydrogen transfer reactions and promoting isomerization or branching reactions in the gasoline range are also key to promote LPG olefins and higher-octane gasoline components, respectively.5, 6

7

0

6

-2

5

-4

4

-6

3

-8

2

-10

1

-12

0

Gasoline, wt%

∆C3=, ∆C4=, wt%

FIG. 5. Maximizing LPG olefins and/or gasoline octane with FCC catalytic and additive solutions.

-14 ZSN-5 in inventory, wt%

FIG. 6. Boosting LPG olefins, especially C3=/C4=, by using ZSM-5 additives.

32FEBRUARY 2016 | HydrocarbonProcessing.com

If the refinery is limited by compressor capacity, a reduction in dry gas or hydrogen can provide the flexibility to increase LPG olefins and gasoline octane, either catalytically or through the optimization of operating conditions. Operating changes that reduce dry gas include lowering riser temperature and modifying the heat balance. If possible, selection of feedstocks with reduced metal contaminants can relieve hydrogen and gas make constraints by reducing dehydrogenation reactions promoted by Ni and other contaminants. Additionally, higher LPG olefinicity can provide a more desirable feedstock for the alkylation unit, ultimately increasing the refinery octane. In the US, the growth in light, sweet domestic crude processing has resulted in an octane shortfall in some refineries, creating a clear value proposition for higher octane from the FCCU. Catalyst properties, such as porosity and active sites, can be modified to improve tolerance to feed contaminants contained in shale oils, typically iron (Fe) and calcium (Ca) at unconventional levels. These improved catalysts can reduce required catalyst addition rates and improve bottoms upgrading, despite the higher levels of contaminants.7 In Europe, the Middle East and Asia, heavier crudes containing higher levels of Ni, V and Concarbon, which translate into higher delta coke in the FCCU, require improved catalytic coke selectivity and superior bottoms upgrading capability and stability to ensure activity maintenance at optimal catalyst consumption. A change in the catalyst composition may also be required to enable additional resid processing in the FCCU without exceeding operational constraints and by keeping coke and gas make under control. With different target product mixes, FCC catalyst innovation, process, design and equipment have shifted for optimum conversion. This includes, for example, using slurry recycle to maximize distillate yields. Other examples include specific unit configurations like dual-riser naphtha cracking for maximizing light olefins production.8 Octane and olefin boosting ZSM-5 additives. ZSM-5 additives provide an efficient and flexible route to increase alkylation unit throughput and better economics via higher LPG olefinicity (throughput will not increase; only quality of feed and product will improve) and higher gasoline octane. Propylene and butylene yields increase at the expense of FCC naphtha with ZSM-5 additive use (FIG. 6). The resulting FCC naphtha has higher octane values, both in terms of research octane number (RON) and motor octane number (MON). As prevailing economics shift, the LPG/octane benefit can be optimized by adjusting additive injection rates without changing the base FCC catalyst. New FCC catalysts to maximize octane. FCC catalyst suppliers continually drive innovation to address market needs. Catalysts have been developed to provide a more olefinic yield slate when formulated with multiple zeolites with tailored acidity. These catalysts deliver an optimum level of butylenes to keep the downstream alkylation unit full and increase refinery pool octane. The incorporation of isomerization activity into the catalyst particle itself results in a more desirable yield pattern than would be realized by the use of a traditional octane boosting FCC additive. Using tailored FCC catalysts offers additional flexibility to reach higher octane with butylenes being valued in downstream alkylation units. Dual-zeolite catalysts to maximize butylenes. Incorporating an active and selective catalytic phase into a dual-zeolite

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Clean Fuels and the Environment higher reactivity and preferential saturation of the larger olefins.5,6 Therefore, high 30 1.2 RE/Z catalysts that equilibrate to high UCS in the FCCU tend to be undesirable 20 1.0 when trying to maximize C4 olefin yields. Low zeolite to matrix (Z/M) surface area 10 0.8 catalysts favor the production of gasoline range olefins, and so are favored for pro0.6 0 ducing LPG olefins. When adding ZSM0.8 1.0 1.2 1.4 tC4= 0.6 cC4= iC4= 1-C4= 5 additives, the propylene to butylene ∆C3= , wt% C4= distribution ratio tends to increase with additive level FIG. 7. Selectively promoting C4= over C3= using dual-zeolite FCC catalysts with constant (FIG. 6). At low ZSM-5 levels, the ratio of C4= distribution. incremental C3= to C4= is about 1, but it steadily increases proportionally to usage rates. The reason behind the change in product selectivity is the = TABLE 1. Achieving higher commercial C4 yields and gasoline type of gasoline olefin that is being cracked. Longer-chain gasooctane with dual-zeolite FCC catalysts line olefins are the most reactive and tend to crack preferentially, Base Base catalyst + Dual-zeolite making more C olefins (i.e., C olefins make two C4 olefins; C7 4 8 catalyst ZSM-5 additive catalyst olefins make a C4 olefin and propylene). Once C6 olefins are beCat to oil 8.7 9.2 8.3 ing cracked, the main product is propylene. 0.28 0.27 0.28 H2, wt% In the following case study, using a dual-zeolite catalyst as 0.8 0.8 0.8 C2=, wt% detailed above enabled the refiner to increase butylenes yield together with higher gasoline RON and MON, as compared to Dry gas 2.8 2.8 2.7 the base catalyst with ZSM-5 additive. The incremental gain in 4.3 5.1 5.3 C3=, wt% the ratio of incremental butylene to propylene using a dual-zeoTotal C4 9.3 10.2 10.6 lite catalytic solution was over 20%, from 0.89 to 1.10 (TABLE 1). 1.5 1.7 1.6 iC4, wt% The improvement in butylene yields achieved by using dual-zeolite FCC catalyst has been highlighted both in com0.4 0.4 0.4 nC4, wt% mercial units and by pilot plant testing. A comparison between 7.3 8.1 8.5 Total C4=, wt% a dual-zeolite catalyst and another vendor’s catalyst is detailed – 0.89 1.1 ΔC4=/ΔC3= in TABLE 2. In the commercial unit, the butylenes yield is inGasoline, wt% 50.8 49.1 48.7 creased by 1.2 wt% with an improved propylene production at constant coke yield. The dual-zeolite catalyst enabled a higher LCO, wt% 18.4 18.2 18.2 bottoms upgrading by lowering slurry yield by 1.1 wt%. Bottoms, wt% 6.6 6.7 6.7 Lab testing confirms the advantage of the dual-zeolite cataCoke, wt% 6.9 6.8 6.7 lyst, with gains both in propylene and butylenes and lower botRON 93.5 93.5 94.1 toms at constant conversion. The commercial advantage reaches an even higher level of performance. Lab testing, supported MON 79.7 79.8 80.1 by modeling studies, generates a set of performance data that is consistent with the commercial yields and helps define the optisystem, combining ultra-stabilized faujasite and pentasil zeolite mal FCC catalyst formulation matching the refiners’ objectives functionality, contributes to a breakthrough innovation. The and FCC targets. Moreover, evaluation of catalyst performance proximity of specifically tuned pentasil activity to sites where at pilot-scale facilitates a smooth process for catalyst change and LPG olefin feedstock (gasoline range olefins) is generated inrisk management through a prediction of the yield profile in the creases selectivity toward butylenes compared to conventional commercial unit. These consistent data—between testing and ZSM-5 additives. This feature of the dual-zeolite system, in comin-unit results—also contribute to evaluate techniques to quanparison to traditional ZSM-5 additives, generates an incrementify the improvement in profitability generated. tally higher butylene to propylene ratio, demonstrated both in piThe higher butylene yield translates ultimately into a siglot plant testing and commercial units. FIG. 7A and 7B illustrate a nificant improvement of FCCU profitability. The results of the commercial application of a dual-zeolite FCC catalyst where the economic sensitivity analysis are described in FIG. 8 for a 50gains in butylenes are significantly higher than those achieved by the use of ZSM-5 additive at similar conversion. Moreover, the Mbpd FCCU, taking into account the spread between butylC4= distribution remains essentially unchanged. enes and gasoline, i.e., depending on the relative attractiveness for butylenes as petrochemicals or as a feedstock for alkylate. Understanding the drivers for butylene selectivity is key and The higher the spread, the higher the refinery’s benefits when critical for catalyst optimization. From a catalyst perspective, a dual-zeolite catalyst is used. Even at low differentials between the catalyst hydrogen transfer activity has the largest effect on butylenes and gasoline, the annual value ranges from $0.5 MM C4 olefinicity. High hydrogen transfer catalysts lower gasoline to $1 MM. Depending on the size of the FCCU, higher butylrange olefins, the feedstock for pentasil or ZSM-5 additives, to enes can be worth $2 MM/yr to $5 MM/yr if 0.5 lv% uplift is produce LPG olefins. Hydrogen transfer also has a more signifireached. Innovation in FCC catalysts, as illustrated here with a cant effect on C4 olefin yield than on propylene yield due to the 1.4

40

Base catalyst + ZSM-5 additive Dual zeolite catalyst

Total, C4= %

∆C4= , wt%

Base catalyst + ZSM-5 additive Dual zeolite catalyst

34FEBRUARY 2016 | HydrocarbonProcessing.com

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Clean Fuels and the Environment TABLE 2. Dual-zeolite FCC catalyst: Commercial performance supported by consistent pilot plant evaluation Commercial FCCU Conversion, wt%

DCR pilot plant riser

Other supplier

Dual-zeolite catalyst

Other supplier

Dual-zeolite catalyst

Base

+0.2

Base

Isoconversion

Dry gas, wt%

Base

0.0

Base

0.0

C3=, wt%

Base

+0.7

Base

+0.3

C3s, wt%

Base

+0.7

Base

+0.3

C3=/C3s

0.81

0.83

0.88

0.89

Total C4=, wt%

Base

+1.2

Base

+0.5

iC4, wt%

Base

+0.2

Base

–0.1

C4s, wt%

Base

+1.4

Base

+0.3

C4=/C4s

0.60

0.63

0.69

0.71

Gasoline (C5-430°F)

Base

–1.8

Base

–0.3

LCO (430°F–650°F), wt%

Base

+0.9

Base

+0.4

Slurry (650°F+), wt%

Base

–1.1

Base

–0.4

Coke, wt%

Base

Isocoke

Base

+0.1

3

Annualized value, $MM

C4=, to gasoline spread

$20/bbl

2 $15/bbl 1 $8/bbl 0

0.0

0.1

0.2 0.3 0.4 Uplift from gasoline to C4=, vol. %

0.5

0.6

FIG. 8. Dual-zeolite FCC catalyst providing an increased unit profitability—e.g., with a 50-Mbpd FCCU.

dual-zeolite catalytic system, provides opportunities for refiners to enhance their profitability and optimize the added value from butylenes and propylene for refining or petrochemical applications in an ever-challenging environment. Pushing the FCCU to its operating limits. In a dynamic

and volatile market environment, refiners are pressed by challenging economics, tighter environmental regulations and product specifications. Flexibility is key to adapting to these conditions with a focus on balancing product slate between clean transportation fuels and petrochemicals for an optimum profitability. Operating conditions and strategies are of primary importance, but many refiners do not have the operating FCCU flexibility to drive significant increases in octane or LPG olefins with process changes alone. A more dramatic shift can be achieved with catalyst optimization and the use of selective additives to leverage the FCCU flexibility and profitability in a versatile economic environment and respond to refining and petrochemical market demands. FCC catalysts are fine-tuned formulations designed to push the FCCU to its operating limits and produce higher yields and

36FEBRUARY 2016 | HydrocarbonProcessing.com

increased unit performance, while processing more challenging feedstocks within the FCCU’s constraints and ultimately widening the operating flexibility in an ever-demanding economic environment. Beyond the use of ZSM-5 additives that primarily favors propylene, a solution has been developed that relies upon dual-zeolite catalysts for maximizing butylene over propylene, thus enabling refiners to adapt to increasing gasoline octane demand, run alkylation units at high or maximum throughput, and export LPG olefins to capture value in the petrochemical sector. In a rapidly changing market, the ability to switch product slates back and forth between clean fuels and petrochemicals provides the refinery with maximum flexibility and the ability to monetize and take advantage of shifts in market. ACKNOWLEDGEMENT The authors would like to thank Eric Ye of DuPont Clean Technologies for fruitful discussions on alkylation. LITERATURE CITED Complete literature cited available online at HydrocarbonProcessing.com. CHRISTOPHE CHAU is the global marketing manager for refining technologies at W.R. Grace. He has over 20 years of experience in refining catalysts, including new catalyst development, catalyst evaluation and scale-up, technical service and training in EMEA/CIS, and, more recently, sales in the Middle East. He joined Grace in 2014. He holds a degree in chemical engineering and a PhD in zeolite catalysis from the University of Montpellier/Total. ROSANN SCHILLER is the director of marketing for refining technologies at W.R. Grace. She joined Grace in 1998 and has held roles in technical service, technical sales and product marketing. She most recently served as marketing director for FCC commercial strategy. Ms. Schiller earned her MS degree in chemical engineering from Johns Hopkins University. MIKE ZIEBARTH is the director of catalyst research in refining technologies at W.R. Grace. He has over 22 years of research experience at Grace on FCC catalysts and additives. Mr. Ziebarth has co-authored 23 granted US patents and seven pending patents in FCC catalysts, environmental additives and olefins additives. He holds a PhD in inorganic chemistry from the University of Wisconsin—Madison.

Special Report

Clean Fuels and the Environment P. BLACK, Wood Group Mustang, Houston, Texas

Add power to environmental real-time data through analytics Advancements in technology are delivering ever-increasing amounts of data that need to be processed and acted upon. In the world of downstream oil and gas, including refining and petrochemicals, the amount of information being generated is rapidly expanding. New systems are delivering increasing volumes of data, providing a wider variety of information sources and producing measurements at a higher pace. In addition to increased measurements, instruments are now able to provide increased diagnostic information. These technological advances are spurring the development of advanced analytics tools necessary to process the data and drive operational efficiency improvements. As big data tools become customized for environmental requirements, corporations are realizing the financial benefits of environmental analytics. The evolution of data. As environmental awareness has increased, the number and scope of regulations have increased significantly. Construction and operating permits have become more complex, and reporting and monitoring requirements have expanded. Consequently, collecting information from diverse data sources has meant significant amounts of copying and pasting. Compiling information for the myriad of regulatory reports has traditionally been managed with collections of Excel spreadsheets on network drives. Tracking compliance has required complex macros and manually reviewing thousands of rows of calculations. As the workforce has aged and the original designers have retired, the results have become black boxes, delivering values without a clear understanding of the underlying process. The increase in the amount of data sources, the growth of information to process, and the additional calculation complexity have made the continued use of traditional methods untenable (FIG. 1). To manage the explosion in storage requirements and integration of data from business activities, companies have deployed enterprise resource planning (ERP) software with centralized data warehouses. These warehouses are designed to consolidate information from multiple sources, store it efficiently and provide a unified view across internal business units for planning purposes. While data from many different business systems was quickly integrated, operational process information remained locked inside process historians. To bridge this gap, environmental management information systems (EMIS) were developed and implemented to provide the specialized processing and reporting requirements unique

to environmental regulations. These EMIS have helped to close the discrepancy between the operational information in process historians, discrete data within ERP systems and reporting based on manual entry. A critical component of these systems was the ability to store the information in such a way as to track changes in operational permits for audit purposes and to manage the changing requirements. EMIS tracked compliance for periodic reporting and monitored many aspects of health, safety and environment (HSE) departments. An industry in transition. With more air quality compliance

requirements being tracked at an hourly or higher frequency, environmental departments began to manage short-term compliance by creating calculations within distributed control systems (DCS) or process historians. These calculations provided muchneeded guidance to operations but were not perfect solutions. Due to the unique requirements of the regulations related to quality assurance of the continuous monitoring systems, it was not possible to obtain the exact results used to certify reports. Operations units were forced to run facilities based on estimates, not actual compliance numbers. At times, final re-

FIG. 1. Data dissemination using traditional methods was inefficient and confusing. Hydrocarbon Processing | FEBRUARY 201637

Clean Fuels and the Environment porting showed that avoidable noncompliance had resulted. In addition, as permits were modified or new regulations released, it was challenging for environmental departments to coordinate with operations staff to implement these new procedures. In addition to the higher frequency of emissions tracking necessary, the level of detail that must be retained for review is increasing. In the US, the Environmental Protection Agency (EPA) is continuing to increase the frequency, intensity and scope of its plant audits. The EPA’s 2011 formal information request to refineries requested highly detailed historical emissions values, operating conditions and design specifications for specific units. These developments mandate the need for consistency and transparency in reporting. Agencies are concentrating on traceability—where the data comes from and the level of quality checks that occurred before it is reported. Their focus includes the speed at which issues are detected, steps taken to resolve the issues and how these issues have been addressed subsequently. This additional information provides the agency with insight into the facility’s compliance commitment.

ating certifiable results and providing sufficient notification to react pre-emptively before problems occur. This new data feed is forming another integral part of a corporate information reporting strategy upon which C-level decisions can be made to improve performance. With the amount of data that is stored by design in a facility’s RT-EDMS, this system becomes a centralized repository of all raw information for emissions compliance. Due to its unique position as a bridge between operations and business, it becomes a natural source of information for an EMIS and ERP platform. Each department within the plant can access relevant information unique to its own needs, as well as be easily integrated within existing dashboards at all levels throughout the enterprise. The ability to seamlessly transfer information to other groups and facilities anywhere in the world allows for the creation of new benchmarks for environmental emissions control, directly impacting operating performance. It further allows global companies to quickly respond to changes in international standards, such as the EU’s National Emissions Ceilings.2

The next frontier. Regulatory agencies are not the only

Analytics adds another dimension. The ability to calcu-

stakeholders requesting more detail at a higher frequency. Management is demanding timely information from all areas of the business. Corporations are implementing real-time operations management systems to increase efficiency and to cut costs in all areas. It is not possible in today’s environment to run a plant without real-time environmental information. Monday morning notifications of problems that occurred over the weekend are no longer sufficient. As a result, facilities are enhancing their EMIS installations with real-time environmental data management systems (RT-EDMS) to automatically process the continuous flow of information. These systems perform low-level instrument signal, as well as regulatory data validation, gener-

• Enterprise planning • Data warehouse • KPIs

• Analytics • Instant notification • Real-time validation

RT-EDMS

ERP Regulatory reporting

Operations Management Environmental Health and Safety

External data sources

• Incident tracking • Carbon management • Health and safety

EMIS FIG. 2. Real-time environmental data systems provide consistent information for intelligent decision-making.

38FEBRUARY 2016 | HydrocarbonProcessing.com

late accurate emissions in real time and seamlessly push them back to operations (as often as every six minutes) is opening up opportunities to further enhance environmental performance. The software constantly monitors the results against operating permit levels and can alert multiple operators in time for intervention before a problem occurs. Furthermore, the possibility opens up of developing advanced multivariable predictive models that can be used for guidance, planning and future permitting requirements. The amount of emissions information, combined with large amounts of process measurements over multiple-year periods, has added analytical capabilities not previously available to environmental teams. When tightly integrated into an existing EMIS package, the combination provides the ability to investigate process conditions that were occurring before an incident. The processing power of the systems allows the tracking of near-misses, along with excursions, and provides the starting point for a deeper analysis to reveal underlying factors that may be the root cause of problems. Specific incidents and their timing can be analyzed and traced. This analysis can help ascertain whether processes are more susceptible to events occurring during shutdowns, startups or other identifiable modes of operation. Cutting-edge environmental management systems with embedded analytical capabilities are the necessary solution to building confidence from all stakeholders in monitoring, reporting and addressing potential operational problems. Handling big data is not the only requirement for environmental data management solutions. There is also a need to bolster the data with meaningful insight for tactical decision-making. These advanced software suites provide plant operations with detailed information in a timely fashion so that operators can understand near-misses and noncompliance trends, as well as avoid potential cutbacks in production due to reaching unforeseen environmental limits.

More than software. While analytics provides a robust capability to address potential problems and to achieve maximum performance, there must also be a further investment in highly skilled individuals who can review the data and discern the

Clean Fuels and the Environment underlying patterns. Until now, analytics has been seen as the exclusive domain of data scientists, using tools understood by a select few. This is no longer the case; with the deeper integration of the information into daily operational decision making, three critical skill sets are required to fully deliver the benefits of environmental analytics: • High-speed processing: Qualified personnel must have the ability to design systems that can process and store large amounts of data efficiently. Real-time environmental data management systems are designed and implemented in a similar manner as control systems and plant historians. To maintain processing speed, efficient algorithms must be used. The frequency at which calculations must be performed must be carefully balanced against the computational cost. The strengths and weaknesses of different data-transfer methods must be evaluated, as well as the audience to which the information is directed. • Environmental knowledge: An in-depth knowledge of environmental regulations is necessary, especially for areas related to continuous monitoring, quality assurance/quality control procedures, or sections where specific calculations must be used. An understanding of the periodic reporting, along with incident notification, is also necessary. This understanding helps guide the implementation process to the aspects of compliance where systems can have the most impact. Specialists must be able to understand the intricacies of environmental permits and how to translate the formal regulations into mathematical formulas. • Operational focus: Qualified personnel must have an eye for what is important to operations, and an understanding of the realities of operating in conditions where the data can be dirty and the responsibility is on maintaining production. The individual must be capable of determining the best data that can be used when signal loss or faulty signals are received. There is a requirement

for a combined knowledge of what situations operations can respond to, and the timing necessary for mitigation of potential issues. They must also understand the appropriate level of detail to provide to management to facilitate better decision-making (FIG. 3). With the right tools and experienced personnel, a real-time environmental data management system with advanced analytics can assist in developing in-house metrics for operations and foster a necessary dialogue between plant operators and plant environmental specialists. It can assist in setting operating parameters and identifying key performance indicators, including utilization, capital expenditures, maintenance costs and profitability. Just as important, the system can help improve air-quality excellence, greatly reduce compliance events and enhance community relationships. REFERENCES Environmental Protection Agency, “Agency Information Collection Activites,” November 29, 2010, http:www.regulations.gov/#!documentdetail;ID=EPA-HQOAR-2010-0682-0001. 2 European Commission, “National Emission Ceilings,” November 19, 2015, available at http://ec.europa.eu/environment/air/pollutants/ceiling.htm. 1

PHILIP BLACK leads the environmental practice for Wood Group Mustang. His focus is on providing compliance solutions to global industries and serving as an industry representative on the subjects of air quality and climate change. He has helped develop the company’s ENVision environmental management and analytics software suite and is the product manager. Mr. Black holds a degree in chemical engineering from the University of Kansas and is a licensed professional engineer in Texas.

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39

The Green Solution to Sulfur Recovery

The LO-CAT process, available exclusively from Merichem, is a patented liquid redox system that uses a proprietary chelated iron solution to convert H2S to innocuous, elemental sulfur. The catalyst is continuously regenerated in the process.

LO-CAT Total Package

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Special Report

Clean Fuels and the Environment R. CRUM, AECOM, Baton Rouge, Louisiana

Build a solid GHG BACT cost-effectiveness calculation to avoid CCS costs Determining which technology constitutes greenhouse gas (GHG) best available control technology (BACT) for a new or modified facility often hinges on the GHG BACT cost calculation. This calculation, when done properly, must be approached carefully. An improper calculation can result in increased permit challenges, lengthy permit delays and even the imposition of significantly more expensive control equipment. An iron-clad cost calculation is especially important in light of recent US Environmental Protection Agency (EPA) regulatory positions. In several recent regulatory actions, the EPA has begun using what it terms the “social cost of carbon” (SCC). The social cost of carbon is the projected cost associated with the damages to global systems that GHG will supposedly inflict during the next 300 years. For example, each ton of carbon released this year will supposedly contribute to rising sea levels, more droughts, stronger hurricanes, vanishing species, etc., for the next 300 years. Recent data suggests that the EPA may consider the “social cost of carbon” to be as high as $39/t, and others have advocated that costs could be four to 45 times higher. At the same time, many facilities across the US have submitted prevention of significant deterioration (PSD) permit applications with BACT cost analyses indicating that the cost of carbon capture and sequestration (CCS) is near $50/t. By indicating that the social cost is $39/t and that CCS is only $50/t, the EPA appears to make CCS somewhat economically feasible when, in fact, it is not. These facilities have done a disservice to industry and need to revisit their cost assumptions. If a facility is striving to avoid the imposition of CCS, it is imperative that the BACT cost-effectiveness calculation be error-free, be completed properly and be fully supported with additional documentation. Additionally, it is important that all costs are included in the calculation. A high percentage of BACT cost calculations submitted to agencies in the US omit key cost components, such as insurance, general and administrative costs, maintenance costs and property taxes. Therefore, the cost-effectiveness calculation is biased in favor of CCS. BACT cost calculations are somewhat involved calculations and it is easy to overlook a major cost input. This article will review the various cost items that should always be included in every permit application so as to aid industry in developing a proper, iron-clad BACT cost analysis that will be more than sufficient to pass US EPA regulations and, perhaps, even activist scrutiny.

Issues with EPA regulations and activist review. The

EPA began regulating GHG emissions in January 2011. The long-awaited GHG controls guidance document, “PSD and Title V permitting guidance for greenhouse gases,”1 included over 450 pages of guidance and seven sector-specific white papers focused on controlling and reducing the emissions of GHG through the use of BACT.2 All new major source permits not issued by January 2, 2011 were potentially impacted. Any new facility emitting more than 100 Mtpy of GHG, a relatively small source from an industrial perspective, comes under scrutiny. How large of a source emits 100 Mtpy of CO2e? A 200-MMBtu/hr source fired with natural gas emits about 100 Mtpy. A coal-fired source of 100 MMBtu/hr emits about the same amount of GHG. A typical cracker furnace will emit 200 Mtpy to 250 Mtpy. A single steam cracking furnace will generally emit 200 Mtpy of carbon dioxide equivalent (CO2e), and a new cracker complex with five to eight cracking furnaces will often top 2 MMtpy of CO2e emissions. Thus, almost any capacity expansion at a cracking facility would now require a major source permit. Since 2011, several hundred permit applications have been submitted to state agencies and, in turn, reviewed by the EPA during a 45-day review period. These permit applications are public documents and are available for download and review by the public. Much can be learned from the application itself, and still more can be learned from the EPA’s comments on the application. As has always been the case with the EPA, there are predictable issues that trigger agency interest and comments when reviewing a GHG permit application. The EPA has a few GHG issues that always result in a request for more information or data, which always result in permit delays that can often stretch into months. There are a few things the user must get correct or the permit is held up in abeyance until the user submits new information to support contentions made within the application. These permit delays can and do occur frequently and result in a minimum of a month’s delay—sometimes, the result is a delay of six to 12 months. With the air quality permit being on the critical path for construction, most major capital projects cannot afford a month’s delay. A month’s delay, to say nothing of a six- or 12-month delay, results in significantly higher costs for the applicant. Additionally, the GHG BACT analysis is a major focus of activist groups when challenging permits. These groups will review the BACT analysis in great detail in an effort to derail/delay the Hydrocarbon Processing | FEBRUARY 201641

Clean Fuels and the Environment Making a project economically infeasible is precisely why the activist community diligently reviews the CCS BACT justification. The activists hope to identify a flaw and force the agency to impose CCS, knowing that this may result in project cancellation. If a permit challenge by the activist community does not result in a project being canceled, then the activists know their challenge will Developing a comprehensive GHG BACT likely delay a project a year or more; a year’s delay cost analysis is critically important, and will often result in the project missing the economic window of opportunity. showing CCS to be economically infeasible The applicant must clearly and resoundingly must be based on proven methodologies. demonstrate that CCS is economically infeasible, and present strong environmental and energy justifications for avoiding CCS. The purpose here is to assist applicants with the development of iron-clad BACT cost While there are no sure-fire ways to avoid the EPA or activist analyses and to identify mistakes made by many applicants in challenges, there are ways to seriously bolster the GHG BACT the preparation of their CCS cost justifications. analysis. The BACT analysis can be strengthened and made ironclad when the analysis clearly addresses the key issues that the EPA and the activist community expect to see. For example, the Cost thresholds for GHG BACT analyses. When assessing a EPA always wants to see a clear discussion of the five-step BACT list of control options for a criteria pollutant like nitrogen oxide process. Many permits have been delayed as applicants rewrote (NOx ) or sulfur dioxide (SO2 ), state agencies often use a value their BACT analysis to specifically “identify” steps 1–5. The EPA of $5,000/t to $10,000/t. Any control options costing less than also wants permit applicants to identify emissions of methane $5,000/t to $10,000/t of pollutant removed are considered “ec(CH4 ) and nitrous oxide (NO), in addition to the emissions of onomically feasible,” while control options costing more than that threshold are considered economically infeasible. CO2 , even if those emissions are infinitesimally small when comAlthough state and federal agencies generally use $5,000/t pared to the CO2 emissions. The EPA also wants to see CCS into $10,000/t as the threshold for criteria pollutants, GHG cluded in every BACT analysis for fired sources. Failure to include emissions are very different from criteria pollutants, and the CCS as one of the “available technologies” in Step 1 of the BACT BACT cost threshold must be different as well. Whereas a process will result in a request that the BACT analysis be redone. mid-sized chemical plant might only emit 100 tpy to 200 tpy of Like the EPA, activists have their focused list of “trigger” items NOx , that same chemical plant will emit as much as 2 MMtpy when reviewing GHG permits and their associated BACT analyses. Activist groups have been known to hire PhD chemical engiof CO2. (The whole reason the EPA had to develop the “Tailorneers to review permit applications, check all of the calculations ing Rule” was to “tailor” the Clean Air Act to meet the new and and verify all of the assumptions. Several retired PhD chemical very different needs associated with the regulation of GHGs.) engineers from academia, in fact, cater to the activist commuIndustrial facilities typically emit GHGs in quantities roughly nity and focus their spare time in challenging industrial permits. three orders of magnitude (1,000 times) higher than the quanTheir analyses of permit applications can be daunting when first tities of criteria pollutants. read by a state regulator and can seriously panic the state agency. As a result of these differences, most state agencies have As the old “saw” goes, “The best defense is a strong offense.” been using a GHG BACT cost threshold of approximately With regard to GHG permitting, putting up “a strong offense” is $10/t of CO2e, three orders of magnitude lower than the cribuilding an iron-clad BACT analysis, and the heart of the BACT teria pollutant threshold. GHG permit applicants, therefore, analysis is the BACT cost-effectiveness calculation. The balance focus on preparation of GHG BACT cost analyses that demonof this article will discuss how to build an iron-clad BACT cost strate that CCS costs much more than the $10/t threshold. As analysis, as well as key issues that can be overlooked by even the a result, the 200+ applications for GHG permits filed in the US most astute practitioners. to date all showed that CCS was significantly more expensive than the $10/t threshold. However, the cost estimates varied widely. Some applicaBuilding a GHG BACT cost-effectiveness calculation. tions showed the CCS cost to be as low as $30/t, while others The EPA targets several issues for scrutiny when reviewing soared as high as $250/t. There was wide variation in the estiGHG BACT analyses. While discussing all of these issues is bemated costs for CCS, too wide to be explained by differences yond the scope of this study, the one aspect of a GHG permit in the CCS technologies selected. While some of the cost variaapplication that is of highest importance is the justification for tions were due to differences in equipment choices, many of avoiding the imposition of CCS.3 the differences were due to poor GHG BACT cost analyses. If CCS is imposed upon a project by a state or federal agency, then the economics of the project are changed so drastically that most projects are no longer economically viable. The huge The importance of the SCC. New development on the hocapital cost associated with the acquisition and construction rizon will require applicants to justify an even higher cost. Reof a CCS system often results in a 40% to 60% higher need for cently, the EPA has begun to use the SCC in its cost benefit capital. These major added costs boost the total project costs so analyses associated with many recent regulatory actions. The much that the project is often canceled. SCC is a cost estimate of the economic damages caused in the permitting process. When an activist organization is unsuccessful in delaying a permit within the permitting process, it will often use litigation as soon as the permit is issued. Then, the permitting process is subject to the vagaries of the US federal court system.

42FEBRUARY 2016 | HydrocarbonProcessing.com

Clean Fuels and the Environment future—typically 300 years—associated with a small increase in GHG emissions; conventionally, 1 metric t in a given year. Said another way, the SCC estimates the benefit that society will gain, expressed in monetary value, by avoiding the damage caused by each additional metric t of CO2 released into the atmosphere. The SCC value, which is determined by computer models, is intended to be a comprehensive estimate of climate change damages. It includes, but is not limited to, changes in net agricultural productivity, effects on human health and property damages from increased flood risk. New types of damages are being added with each model revision. Note: The models used to develop SCC estimates, known as integrated assessment models (IAMs), do not include all of the important physical, ecological and economic impacts of climate change recognized in the climate change literature because of a lack of precise information on the nature of damages and because the science incorporated into these models naturally lags behind the most recent research. As the models catch up to current science, the calculated values of damage estimates (SCC values) will increase, perhaps significantly. The SCC is, perhaps, the most important number that owner/operators may have never heard. It is being used by the EPA to justify a host of new regulatory actions and new government subsidies/taxes/surcharges. When agencies prepare to issue regulations, they must justify proposed regulations by assessing the regulation’s costs and benefits. The EPA uses the SCC within the regulatory rulemaking regime to estimate the climate benefits of proposed new regulatory actions. The SCC is used on the “benefits” side of the cost-benefit analysis. Recent justifications using the SCC include renewable fuel and mileage mandates for our cars; water limits for washing machines and dishwashers; and electrical demand of microwave ovens, among other applications. Using the SCC typically allows the agency to demonstrate huge benefits due to small changes in efficiency because those benefits are shown to last for 300 years, long after the vehicle or appliance is sent to the landfill or to recycling. The 2017– 2025 Light Vehicle GHG and Corporate Average Fuel Economy (CAFE) regulations indicated a net present value (NPV) of $170 B in savings from CO2 reductions through the year 2050. (Astoundingly, only one commenter indicated that SCC should not be used in the cost-benefit analysis.) The SCC will become a very important policy tool in the coming years and a keystone of future climate policy. The use of the SCC by the EPA has largely gone unchallenged by industry. As a result, the EPA is using it in increasingly bolder ways and, in fact, recently proposed newer and much higher SCC values—values that are 60% to 100% higher than those proposed just three years ago. The future use of the SCC will likely be aimed much more directly at emitters of fossil fuels. The EPA SCC value for 2015 is $39/t, assuming a 3% discount rate, and increases rapidly every year thereafter. TABLE 1 presents the various SCC estimates published by the EPA for the years 2015–2050, assuming various discount rates. Permit applicants should assume that the $39/t SCC value represents the GHG BACT cost threshold when submitting a permit. If the EPA is using the SCC costs to justify new regulations, it will not be long before it requests that state agencies with delegated permitting authority use the SCC as the cost threshold

for BACT GHG cost analyses. After all, if the federal agency believes that the release of 1 metric t of carbon will cause $39 worth of damage in the future, then that cost estimate represents the rational and logical GHG BACT cost threshold. [Note: The author does not adhere to this view, but presents it as a likely scenario for the future.] Thus, permit applicants are advised to always submit GHG BACT cost analyses of CCS that significantly exceed the current value of the SCC. While that should be easy to do, there have been a number of permit applications submitted that have shown costs below this threshold. Development of a solid GHG BACT cost analysis. In

Step 4 of the EPA’s five-step BACT cost analysis process, applicants are asked to rank all of the remaining feasible technologies. In Step 5 of the process, the highest-ranking option with reasonable cost, energy and environmental impacts is selected. For all of the reasons and justifications mentioned in the preceding paragraphs, it is important that the GHG BACT cost analysis be prepared in such a way as to clearly show that CCS is not economically feasible. A review of more than a hundred recent GHG BACT submittals revealed many common errors. As the EPA continues to strengthen its GHG review process, as it has during the last three years of GHG permitting, and as it gains further insights into the range of solutions offering CCS, the agency will eventually ask one unlucky applicant to apply CCS to its facility. More than likely, the applicant will then bolster the BACT cost analysis and resubmit it, and the EPA will then waive the CCS requirement. However, the applicant’s permit will have been delayed four to six months and the project may have lost the economic window of opportunity. A solid and detailed GHG BACT cost analysis can prevent this delay and the possible imposition of CCS. The prime mistake that virtually all applicants make is not including all appropriate costs in their CCS cost analysis, and the costs that are omitted are not esoteric costs related to GHG emissions. The omitted costs are costs that should be used in every cost analysis, whether for criteria pollutants or GHGs. That is, the issues discussed below are not specific to GHG permit applications: they apply equally to criteria pollutant permit applications. TABLE 1. The EPA’s SCC issued in 2013 for the period 2015–2050 for various assumed discount rates Discount rate and statistic

Year

5% average

2015

$12

3% average 2.5% average 3% 95th percentile $39

$61

$116

2020

$13

$46

$68

$137

2025

$15

$50

$74

$153

2030

$17

$55

$80

$170

2035

$20

$60

$85

$187

2040

$22

$65

$92

$204

2045

$26

$70

$98

$220

2050

$28

$76

$104

$235

SCC values are $/yr and emissions/yr specific.

Hydrocarbon Processing | FEBRUARY 201643

Clean Fuels and the Environment Costs typically omitted by GHG permit applicants. How does the EPA want to see a cost analysis presented? To address hundreds of requests for such a document, the EPA developed the EPA Air Pollution Control Cost Manual, EPA/452/B-02-001.4 This manual provides information on point source and stationary area source air pollution controls for volatile organic compounds (VOCs), particulate matter (PM), NOx and some acid gases, primarily SO2 and hydrogen chloride (HCl). Unfortunately, the manual has not been updated to reflect GHG costing examples, but it is insightful nevertheless. The objectives of this manual are two-fold: 1. To provide guidance to industry and regulatory authorities for the development of accurate and consistent costs (capital costs, operating and maintenance expenses, and other costs) for air pollution control devices 2. To establish a standardized and peer-reviewed costing methodology by which all air pollution control costing analyses can be performed. To meet these objectives, this manual—for the last 25 years—has compiled up-to-date information for “add-on” (downstream of an air pollution source) air pollution control systems, and provided a comprehensive, concise, consistent and easy-to-use procedure for estimating and (where appropriate) escalating these costs. From a regulatory standpoint, the manual estimating procedure rests on the use of a study-level—or rough order of magnitude (ROM)—cost estimate, which is nominally accurate to within ±30%. This type of estimate is well suited to estimating control system costs intended for use in regulatory development because it does not require detailed site-specific information. While more detailed data is available to the regulator, that data is generally proprietary in nature (which limits its publication), costly to gather and too time consuming to quantify. Therefore, for regulatory analysis purposes, studylevel estimates offer sufficient detail for an assessment while minimizing its costs.

While this document does not specifically address GHGs, it is certainly a solid guide to use when building a cost analysis, since a cost analysis for controlling a criteria pollutant will have many of the same types of costs needed for GHG emissions. The EPA wants applicants to use certain equations as the basis for their approach to costing, and the first and most important is used to calculate the total annual cost. Once the total annual cost is derived, it can be divided by the annual emissions reduction to derive the annualized cost effectiveness, as shown in TABLE 2. The components of a comprehensive cost analysis. As the EPA explains in the aforementioned manual, total annualized cost (TAC) comprises three elements: direct costs (DCs), indirect costs (ICs) and recovery credits (RCs), which are related by the following equation:

Total annualized cost = DC + IC − RC To develop a comprehensive cost analysis (FIG. 1), the components that make up the above three sub-costs—DC, IC and RC—must be understood. First, the equation for DC helps to illustrate those costs that might typically be omitted by applicants in a hurry: Direct costs = Labor + Raw materials, feedstock + Replacement parts + Utilities + Impacts to heat rate, efficiency losses due to the new control system + Outages + Waste disposal.

Lower reductions at higher cost/ton

Increasing total annualized costs, $/yr

Typically, about half of all GHG BACT submittals use nothing more than a “vendor quote” when preparing their GHG BACT permit applications. The applicants probably ask the engineering firm of their larger project, “By the way, when you get a few minutes, can Air preheater you prepare a cost quote for a CCS system for the project?” The client would include the resulting estimate within the GHG BACT analysis section of the application. Economizer Historically, using a vendor quote may Dominant have been sufficient. Even a ROM vendor alternatives curve quote would likely exceed the $10/t cost threshold used by most agencies. However, many vendor quotes will not exceed the EPA’s estimates for the SCC, and venHigher reductions at lower cost/ton dor quotes are insufficient to protect apAnnual tune-up plicants from the imposition of CCS. Boiler blowdown recovery Within the DC equation, there are sevCondensate recovery eral sub-components that the engineering contractor, without seeing the EPA’s costO2 Trim control ing procedure, might omit, including: 1. Raw materials—Many CCS units Increasing emission reduction, CO2e tons/yr will require various types of raw FIG. 1. Graphical illustration of average cost effectiveness of the various control options under material feeds, such as catalysts or consideration. amine solutions. 44FEBRUARY 2016 | HydrocarbonProcessing.com

Clean Fuels and the Environment 2. Replacement parts—Replacement parts can incur a substantial cost and should always be included. 3. Utilities—The annual cost of utilities can be a substantial portion of the total cost of a CCS system and should not be omitted from the GHG BACT cost analysis. 4. Outages related to installation and startup of the new system—The system installation can result in an outage of a month or perhaps much longer. These outages will cost the applicant money, and those costs should appear in the BACT cost analysis. 5. Impacts to heat rate/efficiency—The installation of a CCS system will have an enormous impact upon the overall operation of the new facility. CCS systems will typically have a parasitic energy burden of 25% to 40% of the total energy consumed by the main facility. It is vital to capture those costs in the analysis. 6. Waste disposal—Many CCS units will generate various forms of waste products, such as spent catalysts or spent amine solutions, which need to be sent out for disposal. Capture those costs. A typical engineering quote, as described above, will omit six of the seven DC components needed for an iron-clad BACT cost analysis. The equation for IC includes: Indirect costs = Overhead: typically a % of labor costs + Property tax: typically, a % of total capital cost (TCC) + Insurance: typically, a % of TCC + General and administrative: typically, a % of TCC + Capital recovery: capital recovery factor (CRF) x TCC. Very few engineering quotes will include any of the above line items. While the applicants might include line items related to electrical, piping, insulation, instrumentation, and even taxes and freight, applicants will seldom, if ever, see items like property tax, insurance, and general and administrative costs within the bounds of a vendor quote. These are all perfectly legitimate costs, and all applicants for GHG permits should include these line items when an iron-clad BACT cost analysis is required. Capital recovery (CR) is the last sub-component cost factor in the list of indirect costs. It is a critically important cost factor, and great care should be used in establishing it. Two components are used to establish the CR: CRF and TCC. The CRF is a little more involved and will be discussed later in this article. The equation for TCC is as follows: Total capital cost = delivered cost of the control equipment + Auxiliary equipment + Instrumentation + Piping + Ductwork + Painting + Construction

+ + + + + +

Engineering Working capital costs Startup costs Performance tests Initial catalyst loads Any additional costs that are legitimate upfront costs associated with the planned equipment.

Again, there are many sub-components to the TCC equation that are often omitted when a simple “vendor or engineering quote” is requested. Permit applicants need to be sure to add appropriate costs for startup, performance tests, initial catalyst loads and working capital costs. These are all allowed by the EPA and should be included in the GHG BACT cost analysis. Without these costs, the permit application may be at a disadvantage to those that may include these costs, as the annual cost effectiveness (cost/t removed) may be so low as to prompt the EPA into asking the applicant to consider implementation of CCS. When addressing the capital cost recovery factor, the equation is: Capital recovery factor = i × [(1 + i)]n ÷ ((1 + i)n −1) where: i = interest rate n = lifetime of abatement system. Example: When i = 0.06 (6% interest rate) and n = 10 years, the capital cost recovery factor is 0.136. In this example, a company can “recover” 13.6% of the capital cost every year. As is apparent from the equation, a high interest rate and a short equipment life will lead to much higher annualized costs. Using a high interest rate and/or a short equipment lifetime results in a high annual cost recovery of the equipment and, ultimately, a high cost/t removed, which will indicate that CCS is economically infeasible. Higher annualized costs resulting from a high interest rate and/or a short equipment lifetime will result in a greater probability that the equipment will be excluded from further consideration in the BACT analysis, as it will exceed the BACT cost threshold. On the surface, it certainly appears to be beneficial to select a high interest rate and a short lifetime for the equipment. However, permit applicants are cautioned that the EPA scrutinizes these two items very closely. Applicants are advised to choose TABLE 2. Illustration of annualized cost-effectiveness calculation

Option

Total annualized cost, $/yr

Total emissions reductions, CO2e t/yr

Average cost effectiveness, $/t CO2e

Annual tune-up

3,000

2,010

1.49

Boiler O2 trim control

5,308

3,350

1.58

Economizer

124,315

10,049

12.37

Boiler blowdown heat recovery

25,061

1,340

18.7

Condensate recovery Air preheater

11,018

13,399

0.82

130,735

10,049

13.01

Hydrocarbon Processing | FEBRUARY 201645

Clean Fuels and the Environment their interest rate and equipment lifetime carefully. ExxonMobil’s Baytown, Texas olefins cracker project was recently challenged by the Sierra Club on its choice of interest rates (14%). The Sierra Club was suggesting that an interest rate of 0.8% was more appropriate, using the US Office of Management and Budget’s (OMB’s) Circular A-94 “social interest rate” discussed in the EPA Air Pollution Control Cost Manual. In a second example, US Nitrogen submitted a PSD permit and assumed a 13% cost of capital (interest rate) and a 10-year life of the equipment (depreciation). By doing so, it was able to eliminate several technically feasible control solutions from further consideration. The EPA objected to the US Nitrogen interest rate and asked why the standard rate of 7% and the normal 20-yr life span had not been used for its equipment. Common interest rates used by industry and accepted by the EPA for applications include the business’ current borrowing rate, the current prime rate and other acceptable industrial rates of return. Typically, in the absence of other rates, the recommended interest rate is determined as follows: 1. Average the 10-yr US Treasury bond interest rates for the last six months 2. Add 2% to that interest rate 3 Round up to the next higher integer. For example, if the 10-year bond averaged 2.9% for the last six months, the interest rate to use would be 5%. Applicants can certainly use an interest rate higher than 5%, but the application should clearly explain why the higher interest rate was selected in the permit application. Applicants may be able to quote loan documents, internal costs of capital or other sources of information, but any interest rate selection must be supported by solid documentation. Clearly, some equipment, like that in acid service, does not last 20 years, which is the EPA’s “suggested” lifetime estimate for most equipment types. If the application uses a lifetime shorter than 20 years, detailed arguments as to why the equipment cannot be expected to last 20 years should be presented. Lessons learned. Developing a comprehensive GHG BACT cost analysis is critically important. The activist community and the EPA are no longer accepting brief one- to three-page “cost analyses” that blithely conclude that CCS is not economically feasible. Numerous permits have been challenged and held up unnecessarily for months while agencies and courts work through the issues. While CCS is almost always prohibitively expensive, demonstrating that it is too costly is not always easy. Building a strong case to show CCS to be economically infeasible must be done in such a way as to be understandable to all concerned parties, using proven methodologies. Fortunately, the EPA has provided fairly detailed guidance on what it expects and how the analysis is to be approached. A BACT cost analysis developed using this document as a guide will be difficult to challenge and should withstand EPA scrutiny. Permit applicants are advised to properly account for all costs in a BACT cost analysis. Using a simple “vendor quote” will no longer suffice for GHG BACT cost analyses. Vendors leave too many major costs out of their quotes, and the activist community may be able to challenge the costs and gain 46FEBRUARY 2016 | HydrocarbonProcessing.com

a hearing with the state or federal agency. Failing to include key costs in your BACT cost analysis will result in poorer than necessary economics and also possibly result in unwanted and unnecessary permit challenges. Key direct costs that are often left out of permit applications include raw materials (amine solutions, catalysts, etc.); replacement parts; utilities to operate the new unit in the first year; outages related to installation and startup of the new system; impacts to heat rate/efficiency caused by energy and power losses from the CCS unit; and waste disposal of amine or spent catalyst. Key indirect costs that are often omitted from the calculation include company overhead, property taxes on the site occupied by the CCS unit and associated pipelines, insurance, and general and administrative costs. Lastly, most applicants omit several key cost components from the total capital cost computation, including, but not limited to, startup and initial shakedown costs, performance testing costs, costs for initial catalysts loads, and working capital costs. The last two components of an iron-clad BACT cost analysis relate to the capital cost recovery factors: interest rate and equipment lifetime. While higher rates and shorter lifetimes are advantageous when trying to demonstrate the economic infeasibility of CCS, they will also create an easy pathway for agencies and activists to challenge the permit application. It is best to use a 7% interest rate and a 20-year equipment lifetime if the cost analysis still shows a sufficiently high CCS cost. If the applicant adds in all of the often-omitted costs discussed above, the 7% rate and 20-year lifetime may work and demonstrate the high and unacceptable costs associated with CCS. If the estimated annualized cost effectiveness is still too low (below the SCC value) and the actual interest rate is higher than 7%, then the higher interest rate should be used. The use of the higher rate should be fully justified within the text of the permit application. If a vendor declares that the equipment will not last 20 years, then a shorter period of time should be used in the calculations, and this should also be fully justified within the text of the permit application. LITERATURE CITED US Environmental Protection Agency (EPA), “PSD and Title V permitting guidance for greenhouse gases,” http://www3.epa.gov/nsr/ghgdocs/ ghgpermittingguidance.pdf, March 2011. 2 http://www.epa.gov/nsr/ghgpermitting.html 3 Crum, R., American Institute of Chemical Engineers (AIChE) Paper No. 36b, “Building an iron-clad BACT attack—Avoiding imposition of carbon capture and sequestration (CCS) on your next major ethylene expansion,” AECOM, April 2013. 4 EPA Air Pollution Control Cost Manual, EPA/452/B-02-001, 2002, 6th Ed., http://www.epa.gov/ttncatc1/products.html 1

RON CRUM is the vice president of AECOM. With 30 years of experience in the engineering field, he has directed and presently manages large, multi-year, multi-disciplinary projects throughout the US and Europe. Mr. Crum sits on several committees of the American Fuel and Petrochemical Manufacturers’ Association (AFPM) and has provided addresses at numerous national and international conferences. Prior to joining AECOM 24 years ago, he worked as the engineering and IT lead on the global mergers and acquisitions team for Borg-Warner Corp. He earned a BS degree in mechanical engineering from Louisiana State University, and he serves on the LSU Mechanical Engineering Advisory board and the LSU Civil and Environmental Engineering Advisory board.

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Outlook

Industry Leaders’ Viewpoints L. NICHOLS, Editor/Associate Publisher

2016 Industry Leaders’ Viewpoints—Part 2 Industry leaders and esteemed colleagues shared their viewpoints on 2016 and beyond with Hydrocarbon Processing. These viewpoints give insight into growing regions of activity, technological advances and how the downstream industry can innovate in 2016 and into the future. The following viewpoints are a continuation from the January issue.

DOUGLAS N. KELLY, P.E. Vice President, Refining Technology, KBR

The refining industry is innovative, too. When people hear the word “inno-

vation” associated with a company, most people immediately think of companies like Apple, Tesla, Uber or any number of pharmaceutical companies. The latest Forbes list of the World’s Most Innovative Companies does not include any refining companies. The refining industry is generally known for being conservative and mostly adopting well-proven technologies, and that reputation is somewhat expected. After all, refining has been around for well over 100 years, and innovation is often associated with newer industries

and companies. However, to believe that there is no room for novel ideas or creative thinking in such a mature industry could not be further from the truth. Refining companies have had to continually innovate to deal with numerous challenges over the years. One of the challenges driving innovation includes responding to volatile feed and product prices. Crude oil prices have ranged from $15/bbl in 1946 to $145/bbl in mid-2008 to $40/bbl in December 2015, with many significant price variations throughout the history of the industry. In addition to the significant price fluctuations, not all crude is created equal. There is heavy, light, high-sulfur, lowsulfur, high total acid number (TAN), low TAN, high metals and low metals, and every combination in between. Refining companies have had to adjust to these regular and constant changes in markets, as well as crude quality, by deploying new operational approaches and new technologies. In other words, they had to innovate! Additional significant challenges driving innovation and creativity in the refining industry are the ever-increasing environmental pressures. Government regulations around the world require refiners to produce cleaner fuels, putting pressure on refining profitability. The refining industry has responded to these challenges by continually developing better catalysts and process technologies to produce lower-sulfur fuels, while still maintaining refining margins. This has been no easy task, as sulfur specifications in fuel have gone from 2,000 parts per million (ppm) to 10 ppm, as shown in TABLE 1. Each new specification limit has required the refining industry to rethink the traditional approaches fundamental to the refining business, and to develop and deploy new technologies to meet the more stringent requirements. The refining industry has invested billions of dollars in

research and development to ensure the production of cleaner fuels to protect the environment. It is ironic to think about how much the refining industry has done to protect the environment, while receiving little to no credit for the innovation, creativity and costs associated with making clean fuels available to the public. Those outside of the refining industry typically do not see the focus on safety. Refining companies—including the associated companies that supply services, engineering, technology and equipment to support the industry—prioritize safety as a core value. As a result, safety continues to be a driver for innovation in the refining industry. For example, a process that has historically posed significant challenges to safety in refineries is the alkylation process due to the use of strong acids (either sulfuric or hydrofluoric acid) as a catalyst. Countless innovations have been developed to improve the process safety for traditional acid-based alkylation processes. More recently, a new alkylation technology has been developed utilizing a much safer solid acid catalyst, which will allow refiners to meet their production objectives with intrinsically safer operations. There are many examples of innovation in the refining industry, but the final one included here deals with one of the most mature technologies in the refinery, the fluidized catalytic cracking unit (FCCU). FCC technology has been around since the late 1930s, and its main purpose has TABLE 1. The evolution of EU fuel specifications for sulfur content Name

Implementation date

Sulfur limit, ppm

N/A

Oct. 1994

2,000

Euro 2

Oct. 1996

500 (diesel)

Euro 3

Jan. 2000

350 (diesel) 150 (gasoline)

Euro 4

Jan. 2005

50

Euro 5

Jan. 2009

10

Hydrocarbon Processing | FEBRUARY 201649

Industry Leaders’ Viewpoints been to produce gasoline. It has been the heart of the refinery and is an area that most people would consider mature. However, global market drivers, such as declining gasoline demand coupled with increased propylene demand, are changing the operating objectives of FCCUs. In response, new FCC technologies and improved catalyst have been developed that are capable of producing more propylene and less gasoline, providing refiners with flexibility to respond to market demands. While refining may not have been the first industry you think of when you hear the word “innovation,” we should all point to the creativity and innovation that have shaped, and will continue to shape, the refining industry. Innovation in refining continues to provide profitable (economic) solutions in a wildly unpredictable market, as well as provide jobs that have been made safer through improved processes, operations and technologies, all while delivering cleaner transportation fuels that enable us to utilize hydrocarbon resources that protect our environment.

LUIZ HENRIQUE SANCHES Partner, LHS—Consulting and Training Co. Brazil’s upstream and downstream industries have evolved dramatically over the past 30 years. Regarding fuel quality, Brazilian diesel now contains 7% biodiesel, obtained from vegetable and beef tallow. Brazil has also reduced the sulfur content in gasoline, abolished the use of tetra ethyl lead as an octane enhancer and reduced the concentration of aromatics in its composition. The percentage of ethanol anhydrous in gasoline has increased from 20% to 27%. The advent of flex-fuel cars increased the production of hydrated ethanol as fuel. Presently, this market reaches more than 20 MMcmy of anhydrous used in gasoline and hydrous used in hybrid cars. However, Brazil’s largest industry is still run by the state, and is used as an instrument of inflation-reduction policy. Petrobras reached a debt of over $130 B. Furthermore, a series of scandals in management resulted in an investment downgrade. This debt grew from the gasoline price freeze, which was put in place to curb inflation. This resulted in very serious consequences, which included companies such as 50FEBRUARY 2016 | HydrocarbonProcessing.com

Repsol withdrawing from the downstream industry and decreasing growth in the renewable fuels industry. Ethanol distilleries were riddled with high debts, which put them on the brink of bankruptcy. Since most Brazilian refineries are not equipped to process heavy crude from Brazil’s domestic production, the country is forced to export these types of crudes. This results in the country’s need to import lighter, more expensive crude oil. Compounding this, Petrobras’ corruption scandal has canceled additional refining capacity from being built. This has resulted in Brazil being forced to import diesel, gasoline, LPG and naphtha—leading to a trade deficit of $11 B in 2014. In the distribution and retail segment, the market has seen high margins due to the drastic reduction of tax evasion by distributors and unscrupulous stations. This trend should attract new players. New products are not expected to launch in 2016. Fuel distributors will market diesel fuel under the banner of “smaller sulfur content,” and gasoline will have higher octane. Another challenge in 2016 is a growing trend in the inspection of trucks. These inspections verify that trucks are using the Automotive NOx Liquid Reduction Agent (ARLA) product, which is responsible for the reduction of nitrous oxides produced by new diesel engines.

CLEANTHO LEITE FILHO Business Development Director, Braskem Idesa

The past year was a very interesting and dynamic time in the downstream petro-

chemical markets, primarily due to plummeting oil prices. The petrochemical markets faced a continuously shifting scenario, as raw materials such as shale gas became readily available. This led to record low gas prices, placing many North American (NA) producers at the top of the most competitive players worldwide. The wave of new investments in light-feed crackers has been groundbreaking. The first of these new investments was Braskem Idesa’s Etileno XXI Project. The project will host a world-scale cracker capable of producing over 1 MMtpy of ethylene and identical amounts of polyethylene in three individual plants. After several years of planning and over four years in construction, the plant began operations in late December 2015. To implement this $4.5-B mega-project, Braskem Idesa selected the most capable EPC contractors, modern and efficient technologies, and built and trained a team of skilled operators. Another great challenge was to mobilize and manage a 17,000-person construction team with all its complexity, while maintaining the highest safety standards. The project was awarded the DuPont Safety & Sustainability Award for 2015, with only 0.39 accidents/million man-hours worked. As for the outlook of the polyethylene (PE) market, we at Braskem Idesa believe that the next five years will be very challenging. On one side, there will be some surplus production in our region, especially as the next large projects come onstream in 2017 and 2018. On the other side, we will benefit from Braskem’s well-established and large commercial network in Mexico, South America, Europe and the US. Through this network, we trust that existing and new customers will have a great opportunity to take advantage of our resin portfolio, logistics solutions and technical support. The global market demands highquality products. Therefore, producers must seek the newest technology, with high standards in terms of productivity, efficiency and quality. In terms of PE market trends, we continue to see an increasing demand for bimodal products as customers seek new product specifications, such as weight reduction, fewer material blends and optimized conversion rates (kg/hr). Molecular design of the bimodal HDPE resins provide a unique balance of properties that are not achievable in the

GLOBAL SPENDING TO REACH NEARLY $340 BILLION IN 2016. Find out how, where and why.

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HPI Market Data 2016 features: • Global spending in the refining, petrochemical and gas processing sectors • Capital, maintenance and operating spending broken out by region • Short-term and long-term implications of today’s low crude oil prices • An exploration of changing markets and demand within the global HPI, with discussion of emerging markets • More than 55 tables and 100 figures, including information and data collected from governments and private organizations • Editorial analysis of worldwide economic, social and political trends driving HPI activity across all sectors

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AMERICAS

September 13–14, 2016 Norris Conference Centers – CityCentre Houston, Texas

Call for Participation Now Open Submit your abstract by March 17, 2016 The second GasPro Americas (GasPro) will be held September 13–14, 2016, in Houston, Texas. We invite you to be an integral part of the discussion, and join engineering and operating management from the downstream, midstream and upstream sectors of the oil and gas industry. If you would like to participate as a speaker, please submit your abstract(s) for consideration. GasPro 2016 will focus on gas supply, procurement, purchasing, transportation, trading, distribution, operations, safety, the environment, regulatory affairs, technology development, business analysis, LNG and more. We encourage you to take advantage of this opportunity to share your knowledge and expertise with your fellow peers in the industry. Submission guidelines: Abstracts should be approximately 250 words in length and should include all authors, affiliations, pertinent contact information, and the proposed speaker (person presenting the paper). Please submit via email to [email protected] by March 17. For more information visit GasProcessingConference.com Questions? Please contact Melissa Smith, Events Director, Gulf Publishing Company, at [email protected] or +1 (713) 520-4475. GasProcessingConference.com

Specific topics to be discussed include: Petrochemicals/methanol/olefins Catalysts Small-scale and modular gas processing Plant design/revamp/grassroots Offshore/stranded gas Separation technology/NGL Field processing/gas treating Metering/custody transfer/ gas transfer Gas compression Operations/maintenance/reliability Safety/environment Pipeline infrastructure/storage Legislative and regulatory compliance (domestic international) Business and market perspectives Economics and finance Training and human capital Integration of global gas markets Project finance Project management/delivery

Organized by:

Risk mitigation LNG (outlook and exports)

Hosted by:

LNG supply chain

Industry Leaders’ Viewpoints monomodal HDPE. For example, the main advantage of bimodal vs. monomodal resins in bottles is the increase in the mechanical properties without sacrificing environmental stress crack resistance (ESCR). This can translate into weight reduction of the packaging. Besides being an economical upside, it is also a more sustainable approach once it reduces carbon dioxide emissions. Braskem Idesa began commercializing its bimodal and monomodal HDPE resins in January. They are produced by two Innovene S trains from INEOS technology, as well as a full Ziegler/ Cr product mix, with a joint capacity of 750 Mtpy. Together with the 300-Mtpy LDPE plant, we offer a broad range of resins from fractional melt flow indexes (MFIs) to higher melt indexes for injection-grade applications.

SHARI DAVIS Director of Project Management and Project Controls, Strategy Engineering and Consulting, LLC

What’s next? Moving from document- to data-driven project execution. When I was a young engineer, we

did things manually. Piping and instrument diagrams were drawn on a drafting board, and calculations were done on paper with a scientific calculator. My first project was an ethylene plant. One of the grunt tasks for young engineers was the line list. This was a very labor-intensive process that tracked hundreds of lines in the facility. Each line typically had 16 pieces of information, which included line size, service, number, piping specifi-

cation, insulation type, insulation thickness, where it is routed from, where it is routed to, what piping and instrumentation diagram (P&ID) it is on, if stress analysis is required, operating pressure, operating temperature, design pressure, design temperature, test medium and test pressure. In addition to normal operations, there could be alternate conditions. We learned very quickly to plan our work and estimate how long it would take to get everything done. We also learned about this horrible thing called rework. This is when you had to erase everything you had done because you didn’t leave enough blank rows to add a new line. Computers were just entering the industry. Our company had only two computers for all the engineers to use. Another young engineer and I created a spreadsheet in Lotus 1-2-3 to help us do the line list. My mentor quickly realized the potential. It was so much easier to add a row. We could sort the list and identify the larger lines so the bill of material for long-lead piping items could be started earlier. We added formulas to calculate the design and test pressure. We used look-up tables to check insulation thickness based on the operating temperature. Because I was a new engineer and not influenced by years of doing things a certain way, I was able to see the potential in executing projects with data instead of documents. I imagined a future where I would be sitting in an office with 10 or 15 computer screens, all generating data that would be used by other groups to develop their deliverables. So, why hasn’t this paradigm shift occurred? One reason might be the way we track progress on projects. In an ethylene plant, there are thousands of documents. These deliverables contain tens of thousands of pieces of data with no good way to track them. Most engineering companies use an earned value method that is based on progressing documents based on milestone issues. A line list with 625 lines could have 10,000 pieces of data. To make things more complicated, we don’t have all the data at the beginning of the project. It evolves over the life of the project. Project execution is slower when based on documents. We starve groups of information waiting for the document to be complete so it can be issued. To check isometrics, the piping design group needs the line size, service, number, pip-

ing specification, and insulation type and thickness. They don’t need the other information. However, they have to wait until all the rest is done so the document can be issued. Moving toward digital and digestible data generation is the future for project execution—giving project team members the ability to “pull” data as it is finalized and ready for use. There are many benefits to data-driven project execution. The most compelling benefits include: • More granularity on the project, resulting in better mobility with “just in time” release of information • Information doesn’t become stagnant, so rework is reduced • Progress reporting is more accurate, resulting in reduced project schedules. My mentor taught me an important lesson as a young engineer. If you hold up piping design, you hold up project execution. There is a great demand in the industry for projects to execute quicker. Every project is on the fast track. Data-driven execution is the answer, so groups like piping design are not held up waiting for documents.

GIOVANNI SALE Americas Region Vice President— Maire Tecnimont Group Commercial and Business Development Vice President— Tecnimont

The availability of cheap gas and associated ethane/propane natural gas liquids, along with the slowdown of China’s economic growth, are driving downstream producers to optimize their existHydrocarbon Processing | FEBRUARY 201651

Industry Leaders’ Viewpoints ing production units. This is being done through tailored intervention, as well as planning investments to monetize the strong availability of gas and the associated ethane/propane. Within this view, the main trends show a growing focus on investments in the implementation of new fertilizer and polyolefin plants, and leveraging on the best technology available in the market, with special attention to install multi-product (fertilizer) and multi-grade (polyolefin) production units to meet the worldwide demand with the necessary flexibility. It is well known that the petrochemical industry sector is counter-cyclical. However, the slowdown of the global economy is not in favor of the expected pace of investments. It is also important to highlight that the current low price of naphtha is creating a new renaissance for polyolefin producers, which are based on this semiproduct as feedstock. This is particularly true in Europe, where the existing petrochemical companies are benefitting from such a dynamic. This is also driving new strategic investments that were totally unexpected only a few years ago. Maire Tecnimont Group continues to leverage its expertise in the hydrocarbon processing value chain, both in fertilizer and petrochemical technology. We continue to serve investors for the optimization of existing plants and for the grassroots realization of new state-of-the-art production units.

MARK SCHMALFELD Global Marketing Manager— Refinery Catalysts, BASF Corp.

52FEBRUARY 2016 | HydrocarbonProcessing.com

The refining industry continues to be driven by many factors, which include the impacts of low oil prices, competition for cheaper crude supplies, capital limits, regulatory planning, and managing in a competitive environment where new capacity is creating global supply-demand imbalances. Today’s refineries must make more complex decisions as low oil prices impact operational plans, capital investments and economics. In 2016, there will be a continuous focus on catalyst technology selection, catalyst innovation and providing experienced technical services to help refineries create value. Refinery capital investments are expected to be more restrained in 2016, as firms focus on operational profits and meeting incremental demand growth. Despite lower crude prices, global gross domestic product (GDP) and fuel demand are forecasted to grow. Petroleum-based fuels remain the major supply of the fuels, as renewable fuels remain a relatively small share of the global mix. GDP growth correlates with higher fuel demand, so we also expect an increase in catalyst demand over the long term. Demand for BASF refining catalysts, such as FCC and additives, was strong in 2015. We expect this trend to continue in 2016 as we introduce new catalyst technologies and continue to develop our technical service offerings by investing in new tools and resources. Catalyst technology continues to enable refiners to push the adaptability of the FCCU, as it keeps evolving to meet today’s increasingly complex global energy requirements. This will be driven by fuel demand growth, particularly in the emerging markets; the long-term trend toward heavier feedstocks; and the global shift in product mix from gasoline to diesel as gasoline engine fuel standards are implemented. With all these drivers, FCC catalysts will continue to represent a growth market. Changing feedstocks and evolving product needs open up opportunities as customers seek to optimize their units with improved catalyst systems. The continued need for the next-generation highconversion catalysts will require building on the success of existing technology platforms. BASF continues to develop next-generation high-conversion catalysts to meet the ongoing needs for gasoline, particularly in emerging regions.

In 2016, the NA market continues to plan for a high volume of light sweet crudes (i.e., tight oil crudes). Tight oil crudes require high-activity catalysts tailored for processing these highly reactive feeds. Catalyst technology also supports NA in meeting its demand for octane, which is in greater need when processing tight oil feeds. Growing demand exists for petrochemicals, particularly in the Middle East and Asia. New, highly complex refineries with the ability to produce petrochemical feedstocks, such as propylene, are under construction. Catalyst technology continues to be improved and offered to petrochemical complexes. Asia, led by China and India, and the Middle East will be the major refinery catalyst demand growth areas in 2016. NA refineries have continued to operate at high utilization rates with highly optimized catalyst systems. The region’s refineries are exporting increased volumes of fuels to Latin America, as investments in Latin American infrastructure have been delayed. Compared to the rest of the world, Asian refineries are expected to operate at lower average utilization rates in 2016. This is due to the region’s excess capacity against 2016 forecasted demand. Incremental demand for diesel over gasoline is the longer-term trend for growth in the fuels market. Over the longer term, gasoline demand is expected to decline in NA as the Corporate Average Fuel Economy (CAFE) standards of 2025 need to be achieved. The refining industry is going through a period of dynamic changes. New refinery complexes are being built, mainly in Asia and the Middle East. This construction is driving refining capacity to exceed demand. However, over the next few years, refinery networks should balance globally as capacity aligns with demand. Refineries will continue to meet increasing compliance regulations for air and fuel quality. Environmental regulations will also continue to be phased in globally. Catalyst innovations will help refineries meet environmental compliance requirements for sulfur oxide, nitrogen oxide, carbon monoxide, particulate and fuels sulfur control. The refining industry continues to grow, with dynamic technology changes influencing the productivity and needs of the industry.

Industry Leaders’ Viewpoints JOSEPH C. GENTRY, PE Vice President of Technology, R&D and Engineering, GTC Technology US, LLC

Capital constraints will remain the primary challenge facing the downstream hydrocarbon processing industry (HPI) in 2016. Discretionary capital for economic merit is being squeezed by environmental- and compliance-related projects that are mandated to stay in business. This is unfortunate, because constraints on economic growth for spurious reasons distort the natural flow of capital and are hurtful to the overall health of the world economy. I predict there will be disproportionate media coverage on “green chemicals” via press releases, discoveries of “green routes” to some petrochemicals, and messaging about how “green production” saves money. HPI companies are quite logical and have already largely implemented projects that save them money, within their capital availability. Be wary of hyped-up opportunities supported by subsidies or incentives. My view is that all projects should be grounded in fundamental market-based economics over the long term. A trend that I see continuing is risk aversion. Many companies in the HPI severely penalize employees who make a mistake, while failing to reward their employees who make great decisions based on sound technical and economic evaluations. This leads to inertia and missed opportunities for improving profitability. Successful enterprises encourage proper understanding of technologies and markets, and give their employees the free-

dom to make decisions at the level where they are best understood. Another example of risk aversion is high-profile companies, which are paralyzed to do a project out of the fear that some controversy may erupt and cause negative publicity. I would challenge these companies to stand up for sound economics and fiduciary responsibility to their shareholders. We should be proud of our industry for bringing about cheap energy and for producing affordable goods that have lifted the economic well-being of millions of people, all while doing it safely and with environmental responsibility. On the technology side, I see two areas emerging that will gain acceptance over the near term- to medium-term: 1. Processes that convert natural gas to olefins/polyolefins, aromatics or other liquid products. Natural gas resources are more abundant than oil-based resources, but have the significant disadvantage of high transportation cost to market. 2. Advanced distillation using dividing walls, thermal coupling and multi-functionality within columns. As engineers learn about and understand these technologies more completely, they will find abundant opportunities for innovation across the industry. On the business side, I see opportunities for forward-thinking companies to gain a quick infusion of new technology, production assets, market share or branding via mergers or business acquisitions. This is a normal part of business realignment and optimization. The downstream HPI will likely remain cautious for investment based on uncertainty of oil prices and regulations. Companies are understandably unwilling to invest long-term toward a moving target. What then should we do? • Educate employees about new technologies that will improve local economics. Encourage an environment of prudent risk-taking. • Build a level of trust and empower decision-making at the lowest practical level. • Reject spending capital monies on projects that are politically correct but actually bring about the opposite outcomes of what is purported. Business focus must

remain on sound, economicallygrounded projects implemented in a responsible manner. • Spread the positive truths about our industry.

MÉRIAM CHÈBRE Deputy to the Delegate Numerical Methods and Data Processing Scientific Development Division, Total S.A.

With the digital maelstrom, refining and chemicals are on the road toward the smart plant of the future that combines micro-sensing, advanced analytics and wide-range automation. We can expect general online certification of products with reduced inventory and extended workflows toward regional hub-wide optimization and eco-park organization between complementary partners. The root of this revolution is not recent. Twenty-five years ago, statistical process control, rule-based expert systems and fuzzy logic controllers were implemented in petrochemical plants. Twenty years ago, multivariate statistical process control and neural-networks-based inferentials for soft sensing were developed in refineries. Fifteen years ago, real-time databases were deployed in petrochemical platforms, with multi-plant remote monitoring. Let us now target “more.” More accuracy is expected with our predictive models. This may include more physics embedded for a better understanding before prediction and action. Let us target “wider.” We want to go toward multi-period, multi-scale integrated optimization schemes that flow from: Hydrocarbon Processing | FEBRUARY 201653

Industry Leaders’ Viewpoints Planning → scheduling → advanced process control (APC) and operations; process units → production lines → plant → business unit hub → eco-parks Let us think “faster.” This includes efficient closed loops for fast transients, quick access to information before decisions are made, in-situ and in-transit data visualization and processing during huge high-performance computing (HPC) parallel programming calculations, and simulations for computational fluid dynamics (CFD) applications related to multi-phase turbulent flows in combustion and explosions at the lowest scale. Let us focus on dynamics. This includes master lifecycles with corrosion, catalytic deactivation and material aging. Data reconciliation (redundancy) and data assimilation (model update with data) are needed for day-by-day adaptation. Online product certification is the way to reduce intermediate storage and practice direct shipping. Let us develop uncertainties quantification and robust approaches for a better resiliency and disturbance rejection, all while focusing on minimizing product giveaways. Data-centric approaches should be developed for efficient automated workflows. Besides the rush toward data mining and machine-learning-based modeling, we need more actions on optimization, image processing and complex data fusion. Optimal solutions include combining economics with energy efficiency and environmental targets. Real-time dynamic optimization (RTDO) will be one of the great challenges in the years to come. RTDO aims at establishing an efficient bridge between planning, scheduling and production operations with APC and automation. There is a buzz on social network monitoring, the Internet of Things (IoT), mobile devices and communication exchange underground management to understand people’s feelings and expectations in a business-to-client market development. We need to escape from this buzz and flood of marketing data lakes “in the cloud” to keep working on strong scientific challenges driven by our industry. This includes heterogeneous and very complex technical data fusion that could gather numerical hyper cubes (time series, lab measurement, etc.), text docu54FEBRUARY 2016 | HydrocarbonProcessing.com

ments (expert diagnosis data) and images or movies. Particularly, semantic referential and dictionaries for extended queries could be developed with meta-data and contextual knowledge management. This could help us develop quick diagnoses while relying on expert heuristics. This data fusion, including text mining in connectivity with numerical boards, is one of the new challenges for the future. The underlying result of data fusion challenges could be to catch and master know-how and expertise for fast training with nextaugmented operator training simulators (OTS) generations.

JIM SHIPLEY Global Technical Marketing Manager, Sandvik Materials Technology

The challenges in the HPI have been varied in the last year. It is clear that the “new normal” facing the industry is a reality with a low oil price and a stable gas price. In the upstream, the development of new offshore oil projects has been curtailed due to the reduction in revenues. Conversely, the downstream sector has seen a large number of projects begin to move through design and planning on the back of low and stable feedstock prices. Gas is an increasingly attractive building block and brings interesting opportunities to reduce emissions. The increasing global realization regarding the climate threat is giving rise to new technologies and new paths to reduce emissions, all while maintaining output. There is now an increased demand, within both the upstream and downstream

sectors, for more cost-effective solutions, with a focus on both capital expenditure (CAPEX) and operational integrity. Issues such as corrosion and the cost of replacement materials are driving discussions regarding material selection that give total cost of ownership advantages and reduced operational expenditure (OPEX). Trends in the industry are clear. Energy efficiency is one major key to reduce longterm emissions and environmental impact through the reduction of equipment replacement and better lifecycle costing. Front-end design companies are now looking for material solutions that can help combat both CAPEX and OPEX issues. There is a significant increase in the interest for more corrosion-resistant and stronger duplex materials, in lieu of expensive nickel and titanium alloys. For example, the upfront CAPEX for a heat exchanger can be reduced by up to 60% by using duplex materials compared to alloys, such as alloy 625. This is made possible due to the excellent pitting corrosion resistance on par with that of common workhorse nickel alloys, such as alloy 625, as well as excellent resistance to stresscorrosion cracking in chloride-containing environments. Significantly increasing crevice corrosion resistance is vital in the reduction of failures due to under-deposit corrosion. This is an additional focus area where both nickel alloys and titanium have documented concerns. The environmental impact of continuous, and often unplanned, replacement of heat exchangers is enormous. Not only does the material have to be produced, transported and installed, but the more often the failure, the higher the impact. OPEX reductions impact this in a positive way, and the increased lifetime expectancy of equipment means both a cheaper overall solution and a significantly reduced environmental impact. Replacing low-alloyed materials, which do not give sufficient service life, with long-term, cost-efficient and environmentally sound solutions is therefore important. Not only do the material properties affect this, but the surface finish and fatigue properties are also of great interest in reducing the running costs of equipment and the risk of failure due to deposits or vibration. End of series. Part 1 of this article appeared in January.

Process Engineering and Optimization J. VAZQUEZ-ESPARRAGOZA and J. CHEN, KBR Technology, Houston, Texas

Use discrete event simulation as decision support for storage and shipping—Part 2 Over the past decades, one engineering firm has been using discrete event simulation (DES) to study shipping and storage as an integral part of project execution throughout all phases of a process facility’s design, construction and operations. The simulation quantifies and visualizes the operations prior to actual project capital commitment, generating millions of dollars in savings for clients. A successful solution optimizes lifecycle costs by balancing the capacity for material movement and storage capacity against risks, unforeseen events and the overall project schedule, as discussed in Part 1, published in January. Part 2 presents a four-step simulation-based methodology and shows a third example of the estimation of the storage volumes and shipping capacity for refinery operations in Africa and the Middle East. As in Part 1, the project background, study basis, objectives and key deliverables are discussed. Conclusions are presented, and a brief introduction of additional fields where simulation has been applied is also given. Simulation methodology. The traditional spreadsheet-based techniques and deterministic mathematics models, in general, are inadequate to handle the inherent complexity and uncertainty of the logistics systems. Instead, DES that uses statistical distributions to model the variations is an ideal tool to provide accurate solutions for correct decision-making the first time. It is also very flexible to model a system with different levels of details from the plant level down to the operations of a single pumping station, trucks or ships. A logistics study follows a four-step, simulation-based methodology, as shown in FIG. 1. Planning phase. This phase defines the study scope, modeling objectives, project objectives, decision variables, performance measures and critical uncertain factors. The project objectives specify the duration of the simulation project and the detail level of the visual display and animation. The modeling objectives state the purpose of the simulation modeling, which is usually the problem to be solved. Process mapping is applied to capture the key steps and decision points. This is the blueprint for developing the structure of a computer model. It is also necessary to identify the stakeholders to facilitate the data collection and model validation, which, in turn, enhance the quality of models and the credibility of the outcomes.

Simulation. The data to feed the simulation model are collected in this phase. Depending on the modeling level, the factors listed in Part 1 are selected for specific needs. The statistical distributions are then generated for the collected data to represent the variability in the system. The computer model for the baseline scenario is developed using a licensed DES application. Prior to applying the computer model for subsequent analysis, it is necessary to verify and validate the model. Model verification ensures that the computer program is correct in syntax, while validation is needed to guarantee a satisfactory range of accuracy. The animation model is developed for two purposes. One goal is to facilitate monitoring the flow of entities to ensure that

FIG. 1. Simulation methodology. Hydrocarbon Processing | FEBRUARY 201655

Process Engineering and Optimization Study basis and objectives. The echelon structure of the intermediate components and the final products in the study scope are shown in FIG. 3. Three grades of gasoline are produced from eight components via blending operations. Similarly, seven components are blended by two blenders to produce three grades of diesel. The blending processes for different products are simulated with different rundown rates and recipes. The study bases include: • All import/export shipping operations at the refinery marine terminal can be handled by two berths—a solids berth and a liquids berth. The liquefied petroleum gas (LPG) is restricted at the solids berth, and other products can be handled at either of the two berths. • The product tank requires one day of testing before loading onto the ships. • A predetermined refinery capacity is given in the unit of barrels per stream day. • A predetermined capacity for each blender. • The ships may arrive up to four days late. • Twenty-four hours of operations are needed for product transfer at the harbor. Among the various factors that influence the sizing of the storage capacity, three key issues must be taken into account: • The flowrate and recipes of intermediate components for producing the final products • The blend batch size, either 150 Mbbl or 300 Mbbl, for each final product FIG. 2. Three-dimensional animation for an • The uncertainty of delay in ship LNG facility. arrivals, as it is necessary to examine

the model logic is error-free. Another purpose is to visualize the model using dashboards, graphs and 2D/3D objects for the best communication with the users’ teams. FIG. 2 shows a snapshot of 3D animation for an LNG facility when a vessel is approaching the berth. Perform ‘what-if ’ analysis. What-if analysis uses the baseline model as a test bed to evaluate various alternatives. Any parameters of the decision variables, assumptions and the basic input data can be adjusted to fit the study purposes. Each scenario is run for multiple replications, using different random seeds, to obtain the performance with meaningful statistical characteristics. Identify the solutions and implement results. This phase organizes the outcome of what-if analysis and applies the techniques of statistical analysis to compare the performance among scenarios. The scenarios that yield the best financial benefits without compromising the operational performance are identified as recommendations. The final solution is then selected by the decision makers for implementation. To achieve continuous improvement, the actual performance of the solution, which may lead to model refinement and modification, is monitored and evaluated. Case study. The objective of this study was to estimate the total volume of intermediate and product tanks required, along with a confirmation of the blender rates and the maximum blend sizes for the gasoline and diesel products, in a refinery in Africa. The facility imports crude oils as raw materials and exports the refined liquid products and bulk solid byproducts.

TABLE 1. Three of 12 cases for gasoline products Case

Product

Recipe

Blend batch for Grade 1, bbl

Blend batch for Grade 2, bbl

Blend batch for Grade 3, bbl

Maximum ship delay days

Constrained capacity of final products

1

Gasoline

1

150,000

300,000

300,000

3

No

2

Gasoline

1

150,000

150,000

150,000

3

No

3

Gasoline

2

150,000

300,000

300,000

3

No

TABLE 2. Storage capacity for gasoline products and their components Gasoline and its components

Preliminary capacity by value engineering, bbl

Suggested capacity by simulation (simulation results), bbl

30,000

30,000 (29,950)

Butanes Light naphtha

150,000

150,000 (125,550)

Heavy-cut light naphtha

240,000

240,000 (184,230)

Isomerate

180,000

180,000 (165,745)

Heavy CAT naphtha

320,000

320,000 (316,701)

Reformate

360,600

360,600 (360,019)

Saturated/unsaturated LPG mix

29,000

32,000 (32,030)

Grade 1 gasoline

2 × 300,000

2 × 300,000 (455,000)

Grade 2 gasoline

3 × 300,000

1 × 300,000 (300,000)

Grade 3 gasoline

1 × 300,000

1 × 300,000 (300,000)

LPG

3 × 30,000

3 × 30,000 (77,000)

56FEBRUARY 2016 | HydrocarbonProcessing.com

Process Engineering and Optimization the system performance when changing the maximum delay time, ranging from two days to four days. Note that event times are specified by the use of probability distributions. For example, if the travel time of a ship through a channel averages 3 hr, then the model generates travel time periods for a ship following a triangular distribution as TRIA(Min, Mode, Max) or TRIA(2.4, 3.0, 3.6) hr. Other probability distributions are used for time events like mooring, bad weather and maintenance. A total of five factors—including the recipe type, the blend batch size of three grades of final product, the maximum delay days, and whether to constrain the total capacity of the final products—are identified as the independent variables for the what-if analysis. Twelve cases for the gasoline products and 16 cases for the diesel products are designed for the analysis of the tankage system. For illustrative purposes, TABLE 1 gives the description of three cases for gasoline. Analysis and results. The time-based tank levels of some of the intermediate components and the Grade 1 gasoline for one of the runs are shown in FIG. 4. By observing the variability of the tank levels during the simulation run, the minimum and maximum amounts of components and product volumes across all of the cases are obtained. These values are then used to determine the required storage volume for each component and product tank needed to maintain refinery operations. 1 2015-12-14 11:19:25 Akin to宽180高125毫米-北京石油2016-梁冬梅.pdf the previous examples, other key performance mea-

surements, including the estimation of the utilization of the berths and blenders, and the waiting time of shipping for loading, are also captured by the simulation. TABLE 2 summarizes the suggested tank sizes for gasoline products and their intermediate components (simulation figures are in blue), comparing with the preliminary design specifications proposed by a value engineering study. Overall, the

Butanes

Grade 1 gasoline

Alkylate

Light naphtha Heavy CAT naphtha Blender

Refinery

Grade 2 gasoline

HC light naphtha

Reformate

Grade 3 gasoline

Isomerate

Sat/unsat LPG mix

LPG Grade 1 diesel

Caustic treated kerosine HC kerosine LCO

SR diesel

HT diesel

HT light distillate

Shipment

Blender

Grade 2 diesel Grade 3 diesel Jet fuel

HT heavy distillate

FIG. 3. Storage topology diagram.

C

M

Y

CM

MY

CY

CMY

K

Hydrocarbon Processing | FEBRUARY 201657

Process Engineering and Optimization TABLE 3. Storage capacity for diesel products and their components Diesel and its components

Preliminary capacity by value engineering, bbl

Suggested capacity by simulation (simulation results), bbl

Caustic treated kerosine

240,400

240,400 (225,032)

Heavy-cut kerosine

240,400

240,408 (222,322)

Straight-run diesel

63,000

63,000 (57,192)

Heavy-cut diesel

340,000

340,000 (226,700)

Heavy-cut light distillate

240,400

240,400 (206,700)

Heavy-cut heavy distillate

160,300

160,300 (145,286)

Grade 1 diesel

3 × 300,000

2 × 300,000 (595,355)

Grade 2 diesel

2 × 300,000

1 × 300,000 (300,000)

Grade 3 diesel

1 × 300,000

1 × 300,000 (300,000)

Jet fuel

2 × 300,000

1 × 300,000 (300,000)

achieved substantial cost savings by identifying accurate storage capacity and minimizing the risks of oversizing.

Heavy catalytic naphtha

400,000

Level, bbl

300,000 200,000 100,000 0

0

100

200

300

400 Time, day

500

600

700

Isomerate

Level, bbl

160,000 120,000 80,000 40,000 0

0

200

300

400 Time, day

500

600

700

Grade 1 gasoline

500,000

Level, bbl

400,000 300,000 200,000 100,000 0

0

50

100

Time, day

150

200

250

FIG. 4. Time-based tank level of intermediate components and Grade 1 gasoline.

two sets of results are aligned well, except for the storage for the saturated/unsaturated LPG mix and the Grade 2 gasoline (figures in red). The tankage for the saturated/unsaturated LPG mix is recommended to be larger, while one 300-Mbbl tank is sufficient for the Grade 2 gasoline. The similar observations for the diesel products and their components are shown in TABLE 3. The tanks for Grade 1 diesel, Grade 2 diesel and jet fuel are recommended to be one unit less than the preliminary design. The simulation study effectively improved the fidelity of engineering design for a large-scale refinery. In addition, it 58FEBRUARY 2016 | HydrocarbonProcessing.com

Recommendations. Making a sound decision on the number of ships used for product transportation and the volumetric storage capacity is one of the major challenges in logistics design and management in the oil and gas industry. The problem involves intensive capital investment, an inflexible supply chain and high complexity. Moreover, numerous production and transportation risks, such as unscheduled maintenance, weather variations, traveling speed and harbor availability, require a sophisticated modeling tool capable of handling the complexity and uncertainty of the transportation of products by fleets of ocean vessels. Simulation-based studies accurately evaluate the performance of logistics operations, as well as proactively identify potential bottlenecks and improvement opportunities. Besides the shipping and storage studies, logistics simulation and traffic simulation are available to optimize the materials movements during the construction phase. Freight profiles, discrete-event models and traffic models are developed to examine the supply chain capacity of civil infrastructure to ensure that the planned freight arrivals can be accommodated in different construction phases. End of series. Part 1 of this article appeared in January. ACKNOWLEDGMENTS The authors wish to acknowledge Dr. Jeffrey Feng for his support and supervision in preparing this article, and KBR for granting permission to publish it. JAVIER VAZQUEZ-ESPARRAGOZA is a technical professional leader with the Automation and Process Technologies group at KBR. He is a registered professional engineer in Texas, and has been in the process technologies and automation area for the last 20 years. Previously, he worked as a software development engineer at Bryan Research and Engineering and spent several years in the academic field at the University of Puebla in Mexico. He holds a PhD in chemical engineering from Texas A&M University. JASON CHEN is a principal technical professional at KBR with the Automation and Process Technologies group. He has extensive experience in logistics simulation and operations management systems in the oil and gas industry. He holds a PhD in systems science from the State University of New York at Binghamton.

Process Engineering and Optimization N. LIEBERMAN, Vacuum Improvement Consulting Engineering, Metairie, Louisiana; and R. CARDOSO, Phillips 66, Westlake, Louisiana

Troubleshoot operation of a steam ejector vacuum system

system is composed of 12 steam ejectors and 12 condensers, as shown in FIG. 1. Each ejector has a dedicated surface condenser. The first-stage ejectors are close-coupled to the vacuum tower and work in parallel. They are directly connected to the tower discharging to the three respective first-stage condensers. Each first-stage ejector/condenser was designed for one third of the total design load. There are three trains, each comprising second, third and fourth stages. The vapors from the three first-stage condensers combine in a common header before going to the second-stage ejectors (one in each train). Condensed

The importance of offgas analysis. At first, an air leakage was suspected to be the cause of the high offgas rate from the fourth stage. An initial sample (shown in TABLE 1) revealed the presence of nitrogen (N2 ) and oxygen (O2 ), although Steam

Steam Steam

J = 1, 2, 3 Steam

Steam

Steam

E = 1, 2, 3

J = 4, 5, 6 “A train” E = 4, 5, 6 To seal drum

First stage Second stage Third stage Fourth stage

Steam

To seal drum Steam

Steam J = 7, 8, 9 “B train” E = 7, 8, 9 To wet gas compressor

Steam

To seal drum Steam

Equalization line

System background. The crude vacuum tower overhead

water and liquid hydrocarbons from all stages drain into a seal drum (not shown). The onset of summer and higher cooling water temperature caused the vacuum tower pressure to be unstable. The noncondensable flowrate from the last stage was above the maximum meter reading value. Noncondensable flowrate increased from baseline to maximum meter scale in five months. Tower pressure would change drastically from 10 mm Hg to approximately 30 mm Hg without an apparent reason. The possibility of an unscheduled unit shutdown was high.

Process gas

A crude vacuum unit operating properly generates high gasoil yield vs. low-value vacuum residue. Moreover, gasoil in the residue can adversely affect downstream units. Stable pressure and low pressure are important to achieving good operation, not only for recovering valuable products but also for avoiding swings that impair control systems and the meeting of product specifications. Steam ejectors are in widespread use in overhead vacuum systems. To achieve low vacuum levels, ejectors are arranged in two, three, four or more stages, with each stage comprising a steam ejector and a surface condenser. The condenser condenses steam and hydrocarbon, and cools noncondensable gases and steam to the next-stage ejectors. Components of this type of vacuum system require relatively low maintenance and are easy to put into operation. The alternative to a steam ejector is the far more complex liquid seal ring compressor. Despite being a long-established way to produce vacuum, multistage ejector condenser systems are intricate; problems can arise from process operations, changing crude slates, steam quality, mechanical problems and fouling. Lack of understanding of the operating principles makes it possible to view these systems as a “black box.” Here, a case study is presented wherein the operation of a vacuum tower—one that otherwise would have needed to be shut down—was corrected. It highlights the importance of understanding the entire vacuum system, of field observation and of the interpretation of operating vs. design data. Some basic concepts to help understand and troubleshoot a steam ejector vacuum system are presented.

Steam

Sample point J = 10, 11, 12 “C train” E = 10, 11, 12

To seal drum

FIG. 1. Vacuum tower overhead system. Hydrocarbon Processing | FEBRUARY 201659

Process Engineering and Optimization these were not in a 4:1 ratio (even accounting for the CO2 formation). The samples were taken in stainless steel cylinders, which could cause the hydrogen sulfide (H2S) to mask the presence of O2 in the offgas, as shown in Eq. 1: H2S + O2 → H2O + S0(s)

(1)

Whenever exposure to H2S can take place (e.g., while performing a pressure survey or collecting samples), appropriate personal protection equipment is required. The operator collected new offgas samples, using a plastic syringe. Gas chromatography analyses did not indicate any considerable air leakage that could contribute to the high offgas flowrate. Most of the detected N2 was calculated to come from instrument purges. A common source of seal drum offgas is residual propane and butane, either from crude leaking into a vacuum tower pumparound stream, or from poor stripping of vacuum tower feed. However, the amount of olefins in the seal drum offgas indicated that the vapor load to the ejectors was almost exclusively due to thermal cracking (high furnace coil temperature and residence time in the bottom of the tower). While collecting the samples, another important fact was noticed. Four feet of stainless steel tubing was used to connect the syringe to the process pipe (FIG. 1 indicates sample point location). Between samples, offgas cooled in the stagnant tubing. When the second sample was collected, steam condensate was drawn into the syringe, which indicated that part of the high offgas rate was due to problems with the fourth-stage condensers not being able to efficiently condense ejector motive steam. The steam ejector, demystified. An ejector is really a com-

pressor. It converts the enthalpy of motive steam to supersonic velocity through an adiabatic expansion. The low pressure conTABLE 1. Gas chromatography analyses of offgas samples Stainless steel cylinder analysis, %mol

Components Methane

Plastic syringe analysis, %mol

21

28.6

9.5/1.3

14.8/1.8

Propane/propylene

6.7/2.9

10.5/4.5

Butanes/butenes

0.5/2.5

5.5/4.1

Pentanes and heavier

3.3

2.9

N2

13.7

2.2

O2

1.3

0.5

H 2S

31.5

21.3

H2, CO and CO2

5.8

3.3

Ethane/ethylene

TABLE 2. Outlet temperature vs. water saturation temperature Gas outlet temperature, °F

1 2

Water partial pressure, mm Hg1

96 (design)

43.5

101

50.6

106

58.7

111

67.92

From steam table Higher than MDP

60FEBRUARY 2016 | HydrocarbonProcessing.com

sequently generated in the ejector suction chamber pulls the process load and the resulting mixture, still at supersonic velocity, enters the diffuser. In its converging section, velocity is converted to pressure as the cross-sectional area decreases. Past the throat, as vapor flows from sonic to subsonic, pressure is hugely increased and velocity drops to a subsonic level.1 This transition from critical flow to subcritical flow is called the “sonic boost.” The ejector is designed to work in this critical mode of operation. In the diffuser-diverging section, velocity continues to be converted into pressure as the cross-sectional area increases, even if the sonic boost is lost. This is called “velocity boost.” The steam nozzle throat is an orifice designed for critical flow; therefore, steam pressure and temperature define the flowrate through the nozzle. The throat is designed to pass a specific steam mass flow. Wet steam can limit the required steam flow through the nozzle, and accelerated droplets can erode the nozzle and/or the diffuser, leading to poor performance. The manufacturer will provide the performance curve that indicates ejector inlet pressure as a function of ejector suction gas mass load (as water equivalent in lb/hr). The same curve also indicates the design motive steam conditions (temperature and pressure), cooling water supply temperature and the ejector’s maximum discharge pressure (MDP). Ejector suction pressure will follow the operating curve (i.e., if gas load increases, then so does the suction pressure), and it should be, but is not always, independent of discharge pressure until the MDP is reached. The ejector cannot operate properly above its MDP. The ejector will typically make a surging sound. The ejector manufacturers term this improper operation “being forced out of critical flow.” The steam and gas flowing through the ejector is no longer dropping from sonic to subsonic velocity in the appropriate portion of the ejector’s diffuser. The compression ratio of the ejector will drop (for example, from six-to-one to two-to-one). Performance will break, and the ejector suction pressure will increase sharply and may be unstable. In general, all upstream ejector stages will subsequently break performance. The system in this study was designed for cooling water at 88°F and process gas outlet at 96°F (8°F approach). These conditions allow for a low design maximum discharge pressure of 67 mm Hg. However, as the bundle fouls and/or cooling water flowrate drops, the approach increases, and this results in a much higher process gas outlet temperature of 108°F to 113°F. When that happens, the vapor pressure of water becomes a major contributor to the operating pressure of the system, which will eventually lead to jet breakage in the first stage, as it exceeds its MDP of 67 mm Hg. TABLE 2 shows the relationship between process gas outlet temperature and the pressure contribution of water alone. Note that, as the temperature increases, the margin to the MDP shrinks, and any additional process load will throw the ejectors out of their stable operation curve. Typically, 5 mm Hg to 8 mm Hg is added to the condenser gas outlet pressure to estimate the ejector discharge pressure, which accounts for the pressure drop across the tube bundle. This explains why the condensers, even when in reasonable condition, would cause the vacuum to break during the hot months of the year. The previously mentioned MDP is low for an ejector on the US Gulf Coast (USGC), where the temperature of cooling water

Process Engineering and Optimization

a vacuum system, condensers and ejectors are highly interdependent and should be analyzed altogether to pinpoint the source of the malfunction. Ejector surging can be caused by excessive discharge pressure—for example, by deteriorated performance of a downstream condenser, or by an extra-system noncondensable load. Therefore, it is important to keep in mind some of the most common factors that can impact condenser performance: • Cooling water supply temperature and flowrate • Noncondensable load • Condensable load • Fouling • Drain leg (insufficient height or plugged). The progressive loss of vacuum system overhead capacity largely appears to be a function of fouling, especially in the first-stage condenser. Measured shell side ∆P was 6 mm Hg to 8 mm Hg, in agreement with what is expected for the first-stage condensers. This may indicate that the loss of heat transfer efficiency is on the water side, rather than on the process side. A cooling water survey using an ultrasonic flowmeter indicated a reduction of 25% in water flow compared to design rates for the first-stage condensers. This reduction, in addition to high cooling water supply temperature and the low design MDP, resulted in poor performance and erratic operation during the summer. The last stage of the vacuum system in FIG. 1 flows to the suction drum of a wet gas compressor, through about 1,000 ft of 4-in. piping. This line, in spite of its length, was adequately sized for the normal cracked gas flow that is reasonably dry. Flowrate had been increasing, and the high offgas rate was above the meter range (> 900 Mscfd). FIG. 2 shows trends in the offgas flowrate. As discussed previously, major air leakage was ruled out based on low N2 content. The cooling water outlet temperature from the fourth-stage condenser on the C-train (E-12 in FIG. 1) was too high (above 160°F), which would cause hardness deposits in the tubes. Cooling water flowrate was only 10% of design value. The fourth-stage condenser on the C-train was performing poorly, and most of the upstream ejector (Ejector J-12) discharge stream was exiting the condenser with minimum condensation taking place. The high gas rate was building backpressure in the long line to the wet gas compressor suction, ultimately exceeding the MDP for the fourth-stage ejectors (FIG. 2), causing the whole vacuum system to underperform and the vacuum tower to operate above design pressure. The C-train fourth-stage condenser and ejector were taken out of service. Immediately, the pressure in the discharge of the fourth stage decreased from approximately 32 psig to 18 psig. The offgas flowrate dropped from above range (> 900 Mscfd) to approximately 450 Mscfd. Note: In FIG. 1, there is an equalization line connecting the suction side of all fourth-stage ejectors. The equalization line allowed us to isolate the previously mentioned fourth stage and replace the bundle while still using the second and third stage in the C-train. The condenser’s U-tube bundle was found to be severely fouled. Approximately 10% of the U-bends were completely

Details for vacuum system condensers. Proprietary designs attempt to minimize shell-side pressure drop, eliminate the potential for tubes blanketing by noncondensable gases, achieve proper separation from condensate and offgases, and provide extra cooling for noncondensable load to the next stage. An interesting feature present in some condenser designs is the air baffle. The air or vapor baffle extends along the length of the shell and fits snugly against it. Leaf seals (FIG. 3 in red) are used to prevent leakage around the air baffle. That way, the upstream ejector discharge stream goes through the bundle be35

Fourth-stage C-train out of service

Fourth-stage discharge pressure Offgas flowrate

1,000 850

30 700 25

550

Offgas rate, Mscfd

Ejectors and condensers are interactive. When evaluating

plugged. A new bundle was installed, and the system then performed far better.

Pressure, psig

in the summer can exceed 90°F. Performance break is, therefore, not an exception, but is almost unavoidable during hot, humid days at a USGC refinery.

400 20 250 15 0

50

100

150 Days

200

250

100 300

FIG. 2. High offgas load and high discharge pressure for the fourth stage of compression.

FIG. 3. Condenser scheme showing air baffle and leaf seals. Hydrocarbon Processing | FEBRUARY 201661

Process Engineering and Optimization fore leaving the condenser vapor outlet nozzle. Without the air baffle, the inlet stream would short-cut the condenser, going directly to the condenser vapor outlet nozzle and overloading the downstream ejector. The air baffle is located directly above the gas outlet nozzle (FIG. 3 and FIG. 4). A temperature survey of the entire length of the shell side directly below the air baffle location revealed that at least five out of 12 condensers had problems related to the mechanical integrity of the leaf seals. Seal problems can be generated by poor installation of the bundle into the shell (bending the air baffle), corrosion due to wrong metallurgy of the air baffle, leaf seals being too narrow, and not providing proper sealing against the exchanger shell.2 The leak around the air baffle increases the load to be handled by the downstream ejector, and it can eventually compromise the performance of the entire vacuum system: • Hot gas leakage can occur, indirectly increasing the saturated condensable loading • The overall higher gas rate exiting the condenser may be higher than the downstream ejector capacity at the condenser original design pressure • Condenser pressure will increase, and this can be higher than the MDP of the upstream ejector. For the case described here, although the leak by itself was not responsible for performance issues, it was a contributing factor. Observing the leaf seal deficiency helps to develop the scope for the next outage. The leaf seal should be a flexible grade of 316 stainless steel (SS)—never brass or bronze.

FIG. 4. Temperature readings indicating leak around air baffle.

FIG. 5. Thermal scan indicating flooded condenser.

62FEBRUARY 2016 | HydrocarbonProcessing.com

The barometric leg (drain from condenser to seal drum) is another common problem. Height must be sufficient to avoid flooding by taking into consideration the differential pressure between the seal drum, the condenser and the liquid to be drained (density and tendency to foam). The design requires a minimum change in direction and absolutely no horizontal runs (which creates “air pockets”). The pipe configuration may have several 45° elbows due to plant layout and/or available space. These elbows increase the risk of deposits, such as salts from amines injected to neutralize hydrogen chloride, wax formation and corrosion product accumulation. Sludge that accumulates in the seal drum due to biological corrosion is also a common source of poor seal leg drainage. Good engineering practice is to construct the entire seal leg out of 316 SS and not carbon steel (CS). It is also a good practice to tape up all flanges. The A-train second-stage condenser (E-4 in FIG. 1) was found to be operating partially flooded on its shell side. FIG. 5 presents an infrared scan of the condenser shell side showing that condensate level was approximately 50%. The resulting reduction in the tube area available to condense the discharge of the upstream ejector increased the gas load to the downstream ejector. The additional load was, especially during summer, above the handling capacity, and the condenser pressure increased. The resulting pressure would exceed the upstream ejector maximum discharge pressure, and the ejector would “break performance.” Forced out of critical flow, the second-stage ejector subsequently cascaded the effect back to the first-stage system. A partially plugged barometric leg could be the source of the problem. To test this hypothesis, a hose was connected to the 2-in. block valve (with a blind flange), as shown in FIG. 6, to help drain the condenser to the seal drum. Water was used to fill the hose and push air pockets in the hose all the way to the condenser. After the line was filled with water, the condenser started draining. Flooding disappeared and first-stage ejectors stopped surging. Another common cause of poor seal leg drainage and condensate backup are holes in the seal leg. Air draw through such holes slows the drainage of water and oil from the condenser. Leaks on the seal legs are indicated by cool spots on the legs themselves. Air entering the vacuum inside the legs expands and cools. In the US state of Louisiana, the humid air will condense and visibly drip off the seal legs, indicating the exact location of a leak. If a leak is inside the seal drum, then raising the seal drum level will result in the restoration of drainage and improved condenser performance. Motive steam. Vacuum column operation can be negatively impacted by poor motive steam conditions. If the steam pressure upstream of the ejector steam chest falls below the design value, then the motive nozzle will pass less steam. A reduced steam rate to the ejector may not be enough to compress the process fluid from the ejector suction to the discharge pressure. Similarly, a high degree of superheat drops the steam density. Less steam will then pass through the motive nozzle and impact the ejector compression capacity. Conversely, motive steam pressure above the ejector design will cause excessive steam to pass through the motive nozzle, and less process fluid will be pulled through the ejector suction.1

Process Engineering and Optimization

Cooling water system fouling. The cooling water supplied to the surface condensers comes at the end of the plantwide distribution header, where minimum differential pressure exists (low supply and high return pressures) impacting the cooling water flows. Thus, fouling deposits are likely.

The first-stage condensers (E-1, E-2 and E-3) were designed for 10,000 gpm of cooling water. This cooling water cascades to the next stages, as depicted in FIG. 7. As fouling and scaling take place, the first-stage ejector will be the first to be impacted. As the cooling water flowrate drops, condenser process outlet temperature will increase. Due to the low maximum design discharge pressure, jet performance may break. In an attempt to recover performance in the first-stage ejector, the cooling water bypass valve would be partially opened (FIG. 7). Opening the bypass valve restored cooling water rates to the first-stage condenser, but starved the subsequent stages. Low cooling water velocities in the tube side further promoted scaling and tube plugging, as observed in the fourth-stage condensers. Design cooling water rates for first-stage condensers could be achieved by using the cooling water bypass valve, but, even at that rate, performance of the first stage would not be restored. Cold-side “temperature approach” (process vapor outlet minus cooling water inlet temperatures) would be an excessive 20°F. This was a clear indication that the condensers were severely impacted by poor heat transfer coefficients due to the fouling layer. To slow the rate of fouling in the condensers, N2 should be blown through the tubes twice per week, and the condensers should be back-flushed once per week.

FIG. 6. Valve used to install a drain hose parallel to the partially plugged barometric leg.

E = 1, 2, 3 Cooling water supply

First stage Second stage Third stage Fourth stage

E = 4, 5, 6 “A train” Cooling water bypass valve

E = 7, 8, 9 “B train”

Cooling water return header

The same steam header serves all 12 ejectors (FIG. 1), and the steam header conditions are controlled with a pressure-reducing valve and a temperature controller to inject steam condensate and control the superheat degree. Knowing that some condensers were fouled and that cooling water flowrate was below the design flowrate, the pressure controller setpoint was stepped down from the design value and the system was observed. Reducing steam flow to the ejectors unloads the cooling requirements of the condensers. Steam pressure was reduced by 3% stepwise. Steam pressure was optimized at 6% lower than the design pressure. No major improvement in operating conditions was observed, but unloading the condensers also led to approximately 3,500 lb/hr in steam savings. Motive steam supply lines for the system were not properly insulated, which led to condensate formation upstream of the ejector nozzles. Steam condensate not only reduces ejector compression capacity, but it can also cause erosion of the steam nozzle and diffuser throat, which ultimately will cause the ejector to not perform as expected. Steam headers should be insulated all the way to the ejector. As suggested in the literature,3 regardless of what temperature and pressure readings indicate in a steam header, it is always advisable to check steam quality as closely as possible to each ejector. By opening a bleeder valve and observing the jet, the following can indicate steam quality: • Superheated steam—jet is invisible for some distance beyond the bleed • Steam close to saturation or with slugs of water—jet becomes visible a short distance beyond the bleed, and periodic puffs of white are visible. When connections are available, a test can be executed to determine if the nozzle is damaged. It is recommended to install a pressure gauge on the inlet to the downstream condenser, on the inlet of motive steam, and on the ejector inlet nozzle. The steam valve can then be closed, reducing the pressure to approximately 70% of design. If the pressure in the inlet of the ejector decreases, then the motive steam nozzle will need replacement. However, if the pressure downstream of the ejector decreases, then it means that the condenser was unloaded, indicating a fouled condenser. As mentioned previously, the steam nozzle throat is an orifice designed for critical flow. Observing the reduction in steam usage when removing the ejector from service gives an excellent indication as to whether the ejector is consuming more or less than the design amount. The total motive steam consumption for the entire vacuum system (12 ejectors) was approximately 10% above the design value, an indication that threads on the nozzle or the extension in the steam chest may be damaged and/or the nozzle itself has eroded due to wet steam. Problems with the nozzle threaded connection can cause a considerable amount of steam to leak and bypass the nozzle. This leaking steam does not provide any compression work and, indeed, it will add to the ejector suction load, deteriorating the system performance.

E = 10, 11, 12 “C train”

FIG. 7. Schematic of the cooling water sides of the surface condensers. Hydrocarbon Processing | FEBRUARY 201663

Process Engineering and Optimization TABLE 3. Slop oil lab analysis results Samples

Sample 1

Sample 2

SimDist IBP

188°F

350°F

SimDist 5%

306°F

420°F

SimDist 10%

380°F

458°F

SimDist 20%

479°F

507°F

0.88

0.88

Specific gravity

Overall system approach. Besides mechanical problems, fouling issues and design limitations, evaluating the whole system (starting at the bottom of the crude distillation tower) can reveal additional options to reduce the load in the already-impaired ejector vacuum system. One approach to this troubleshooting is to make a process variable change and evaluate the benefits. Some of the trials conducted are outlined in the following paragraphs. Hydrocarbon carryunder from bottom of atmospheric crude distillation tower. Any light ends carryunder will put more load in the overhead vacuum system. Special samples from slop oil (collected from the seal drum) indicate the presence of low-boiling-range components (Sample 1 in TABLE 3). Stripping steam to the bottom of the atmospheric distillation tower was adjusted. There was no appreciable gain in vacuum performance, as the test was performed during winter and the vacuum system was not overloaded; however, the slop oil distillation data showed a reduction in light ends components (Sample 2 in TABLE 3). Comparing samples of the top pumparound and seal oil indicated that most of the seal oil is generated by entrainment at the top of the vacuum tower. The reason for the entrainment is unknown, although it may be contributing 10% of the load to the first-stage jets. Typically, vacuum towers with jets on top have demisters to eliminate this entrainment. The authors’ experience with such demisters is not positive—they foul, create a high pressure drop and often fail. Vacuum tower bottom. High residence time and high bottom temperature will lead to more cracking (cracking is a function of time and temperature). A reduction in the tower bottom level and tower bottom temperature using a recycled quench stream will help. As a general rule, 680°F is a good starting temperature. Sometimes, due to design limitations, the quench control valve goes wide open, and a bottom temperature target cannot be achieved. At this point, a low residence time will be important to avoid cracking. Velocity steam in vacuum tower heater. It is recommended to increase steam to the heater passes, using as a reference at least 1.5 lb of steam per bbl of vacuum heater charge. The objective is to limit the peak temperature in the heater coil and, therefore, to minimize cracking. This also contributes to the reduction in coke deposition in furnace passes. A good strategy is to inject as much steam into each pass as possible, to the limit of pass valve output. Initially, as velocity steam was increased, some improvement was observed in the vacuum system, indicating a reduction of cracked gas make. However, a further increase caused the system pressure to begin deteriorating, due to the vacuum system being overloaded with additional steam. Vacuum tower heater outlet temperature. High coil outlet temperature increases cracked gas production. At some point, a 64FEBRUARY 2016 | HydrocarbonProcessing.com

reduction in furnace outlet temperature does not provide a substantial reduction of cracked gas production, and heavy vacuum gasoil ends up in the residue. A noncondensable load that is higher than the design load can severely impair a vacuum system: as noncondensable gases increase, saturated vapors discharging from the condenser increase. The downstream ejector may not be able to cope with the additional load, which will lead to an increase in the condenser pressure.4 The ejector before the condenser may reach its MDP. As a consequence, the first-stage ejector will break operation, system operations will destabilize and the tower pressure will rise. Adjustments to the furnace outlet temperature should take place after having the use of velocity steam is maximized, as previously described. Reducing furnace outlet temperature did not provide considerable relief to the vacuum system during the trial period. Stripping steam to vacuum tower and side strippers. Stripping steam should be kept at an optimum to fulfill product specifications. Too much stripping steam may not have an influence on product quality, but it may adversely affect the vacuum system by increasing the ejector load. Takeaway. Troubleshooting steam ejector vacuum systems is a challenging activity, and the ejector-condenser interdependency adds to the complexity.5 In general, there are several possible causes for a particular performance problem. As described here, troubleshooting will require exploratory activity where a step change is made and the impact is observed. Data collection is critical for performing appropriate troubleshooting. It is not recommended to jump to early conclusions (e.g., a surging first-stage ejector may be caused by a flooded second-stage condenser). Pressure and temperature surveys are a good starting point for determining the cause of the problem, but they must be properly interpreted to be useful. Inspection records and turnaround reports should be gathered and unit operation should be discussed with operations personnel. Operational details include findings from outages, modification history, new chemicals being used and crude slate history. Finally, design data evaluation may reveal inherent system limitations. LITERATURE CITED Martin, G. R., J. R. Lines and S. W. Golden, “Understand vacuum system fundamentals,” Hydrocarbon Processing, October 1994. 2 Putman, R. E., Steam Surface Condensers, ASME Press, December 2000. 3 Unique Systems Inc., “Installation, operation, maintenance and troubleshooting of ejector systems,” Bulletin PVS-80025121-ESM. 4 Lines, J. R. and R. T. Smith, “Ejector system troubleshooting,” The International Journal of Hydrocarbon Engineering, 1997. 5 Lieberman, N. P., “Troubleshooting vacuum systems,” John Wiley & Sons, Hoboken, New Jersey. 1

NORMAN LIEBERMAN is a field troubleshooter for refinery process problems. He graduated with a degree in chemical engineering in 1964 from Cooper Union for the Advancement of Science and Art in New York. His company provides retrofit designs for refinery vacuum systems. Additionally, Mr. Lieberman has been instructing refinery troubleshooting seminars since 1983. More than 18,800 technicians and engineers have attended his 860 seminars. RODRIGO CARDOSO is a lead process engineer for the Phillips 66 Westlake Refinery. He has 10 years of experience as a process engineer and has worked as a chemical expert for the federal police in Brazil. Mr. Cardoso holds a BS degree in chemical engineering from Rio de Janeiro Federal University in Brazil and an MS degree from the French Institute of Petroleum in France.

Maintenance and Reliability A. DOKHKAN, Jordan Petroleum Refinery Co., Zarqa, Jordan

Prevent the overfilling of storage tanks Overfilling storage tanks, especially those with large inventories of toxic or flammable material, has always been a safety concern for site owners and operators. History has shown that overfilling flammable material storage tanks can have extremely serious, and sometimes fatal, consequences. Site owners are facing increased pressure from governments and insurance companies to assess and control the potential risks posed by the large inventories of hazardous materials stored onsite. When addressing overfill protection, one of the first things to consider is an automatic overfill prevention (AOP) system, as defined in API 2350.1 As shown in FIG. 1, an AOP system is a fully automated protection system comprising, in its simplest form: a level transmitter, a logic solver and an actuating valve on the filling line. The level transmitter continuously measures the level inside the tank. Once a dangerously high level is detected, the logic solver sends a signal to the valve, which then closes to prevent the overfilling of the tank. There are many within the hydrocarbon processing industry (HPI) who consider AOP systems to be the ultimate solution for the prevention of overfilling of any storage tank, but this is not always the case. Site owners are strongly advised to assess the risks posed by their stored inventories before they start planning to install these expensive automated protection systems. Consequence analysis. It can be said that risk equals con-

sequence multiplied by likelihood. Therefore, to perform an accurate benefit-cost analysis, owners and operators should be able to quantify probable loss of human life (PLL), financial loss and potential harm to the environment. They should also be able to determine the likelihood that an overfilling could occur in the first place. In quantifying the potential safety and financial losses resulting from overfilling a storage tank, several factors should be taken into consideration.2 The first factor to be considered is the nature of the substance stored. While the risks involved with storage tanks filled with abundant and non-hazardous substances (e.g., water) should not take much time to analyze, storage tanks of flammable and toxic substances should be studied very carefully. The second most important factor to consider is the size of the storage tank. Obviously, the larger the storage tank, the larger the risk. However, caution must be observed, as this is not always the case. Although larger tanks pose a great risk once overfilling occurs, smaller tanks have a lower storage

capacity and, consequently, a greater likelihood of overfilling than larger tanks. Another important factor to take into consideration is the storage tank filling rate. The overflow rate must be set equal to the assumed filling rate. If the stored substance is flammable, then the proximity of surrounding ignition sources must also be taken into consideration. While an ignition source in the immediate vicinity may result in a flash, pool or jet fire, distant ignition sources may result in far more catastrophic consequences (e.g., vapor cloud explosion). There is the probability that more substance could be released and evaporated; hence, a higher probability that the concentration of vaporizing flammable material will be within the lower explosive limit (LEL) to higher explosive limit (HEL) envelope. The effects of overfilling a storage tank can be simulated with a high degree of accuracy using commercial consequence modeling software packages, if all these factors are taken into consideration. Likelihood analysis and protection layers. Any evaluation of the likelihood of overfilling a storage tank should begin with the identification of all possible initiating events. Examples may include pumping material into an already full tank, or a stuck automatic tank gauge. After identifying all possible initiating events, all existing layers of protection should be analyzed, including automatic gauges, radar gauges, independent level alarms, AOPs, etc.3 It is important to remember that the system must satisfy four important criteria before it can be assumed to be a valid protection layer. First, the layer of protection under consideration should be dependable, meaning that it is capable on its own of preventing the unwanted event from transforming into an accident. Secondly, it should also be independent: a failure of one protection layer must not affect the effectiveness of any other protection layer. One example of this would be two level gauges sharing one sensor (e.g., a gauge float). In this example, the two gauging systems cannot be assumed to be two independent protection layers, because a failure of the float would cause both level gauges to fail. This is also called a common cause failure.4 The protection layer under consideration must also be specific. One cannot use a system implemented for a purpose other than level monitoring as a layer of protection for the prevention of overfilling. An example of this would be someone Hydrocarbon Processing | FEBRUARY 201665

Maintenance and Reliability the operator was recording data in the control room, he or she would not be able to act upon the high-level event nor prevent the tank overfilling from occurring. PFD for operator response is usually assigned a value of 0.1. However, not all operators at all sites Before investing in expensive automatic overfill are alike. If the operator complies with all four of the criteria of layers of protection, and if the fact that the protection, first conduct risk analyses of stored operator’s work does not require complex decision inventories. Look at likelihood, consequence, making is taken into account, then a PFD value of tank capacity, filling rate and fluid properties, 0.01 can be safely assumed. Obviously, the operator’s competency level particularly toxicity and flammability. should be assessed for clarity, as should tank layout and tank marking, as well as the lighting of the tank area.4 If these factors are not carefully analyzed, the probability be a part of a valid protection layer because a change in the specific gravity of the stored material might lead to an incorthat the operator will act on the wrong tank could be higher rect level calculation, mainly because the manufacturer did not than expected. In that case, the operator layer of protection intend for the pressure gauge to be used for level measurement cannot be assumed to be “dependable.” Also, the performance in the first place. of the operator has to be audited regularly to ensure that the Finally, the protection layer must be auditable and allow for PFD assumed for this layer of protection is still valid. testing and verification. If not, it cannot be proved that the assumed value of probability of failure on demand (PFD) is correct. Assigning PFD values. When all layers of protection have been identified, values for probabilities of failure on demand should be assigned to the identified layers of protection. If a Weighing operator response. Whether or not an operator plant has its own record for equipment failure rates, then this response can be considered as a valid layer of protection must should be used. Plant failure rates have many benefits over gebe considered. A number of articles, studies and books have neric failure rates: most importantly, plant equipment faces been written on this subject, and the following may shed furspecific stress factors that may not be the same as those in ther light on the necessary conditions involved in evaluating plants where generic failure rates have been collected (e.g., heat the effectiveness of operator response. and humidity). Care must be taken in choosing failure rates, Operators in different companies, organizations and indusensuring that the company has a good system for collecting and tries have different duties. The duties and responsibilities of analyzing failure rates. the operator should be studied very carefully before a deterEquipment failures can be broadly categorized into two mination is made whether or not the operator response comtypes—systematic and random—and should be analyzed by plies with the requirements of the layers of protection. For expersonnel who are familiar with reliability sciences.5 A simple ample, an operator at a site has the sole duty of monitoring the storage tank level. In this case, it would be safe to assume that example would be the installation of a general-purpose presthis layer of protection is “specific,” as the operator’s only job sure transmitter in a corrosive service. The pressure transmitis to monitor the storage tank level. At another site, an operater internals might wear prematurely, causing the transmitter tor might be responsible for monitoring the storage tank level to fail. A technician might attempt to replace the transmitter at one location, and responsible for recording the operating with one of the same type, and the new transmitter will also variables of a process unit from a control room placed someprematurely fail. This is a systematic failure. If the failure rate where else. In the second case, the operator cannot be conhad been recorded as a random failure, the pressure transmitter sidered as a “specific” layer of protection because monitoring would have a higher-than-expected failure rate. levels is not the only duty. If the level of a tank increased while An important factor that must not be overlooked is the probability that the tank under examination is actually full. This can Level transmitter be illustrated by the following example: A tank farm consists of Logic solver four tanks, some empty and some full, and an operator changes the filling over to the wrong tank. The operator might switch to an empty tank, so the probability that an overfilling will occur is not 1, but rather is the ratio of the number of full tanks to 4. If we know that only one of the tanks is always full, and we add to that the tank that was recently filled, we get a total number of two full tanks. The probability of switching over to a full tank Valve will then be 2/4 = 0.5. Not including this probability in the likelihood calculation will lead to a mistakenly high likelihood of tank overfilling. Of course, the analyst should carefully study Filling line the site’s storage tank filling policy to ensure that the probability calculated is a valid one. FIG. 1. When addressing overfill protection, one of the first things to Accurate overfilling likelihood calculations require that all consider is an automatic overfill prevention (AOP) system. possible scenarios for filling the tank under consideration are using a pressure gauge at the bottom of the tank to calculate the level of the material inside the tank. Unless explicitly stated by the manufacturer, the pressure gauge cannot be claimed to

66FEBRUARY 2016 | HydrocarbonProcessing.com

Maintenance and Reliability investigated, including, at the very least, the frequency of filling the tank and the filling flowrate. Storage tanks are usually filled at various flowrates based on day-to-day activities. With a wide range of filling rates, an operator might be confused about the filling rate on which to base its calculations. This issue can be tackled in two ways. The first option is to calculate the frequency based on the maximum theoretical flow possible. This is the most conservative approach. The other approach is to use the most typical flow, and to prepare special working procedures to be used when working on flows higher than that used for the frequency calculations. It is the author’s opinion that, in reality, the second option never works. However, if site owners choose to proceed with the second approach, they should construct strong work systems to confirm that measures are being implemented to ensure that existing layers of protection are functioning as they should. Final calculations. After both the consequences and likelihood of overfilling a storage tank have been quantified, the number of expected fatalities can be calculated. For this, the analyst must estimate the probability of personnel being present in the lethal zone. After the number of fatalities has been determined, the frequency of PLL can be calculated by multiplying the number of fatalities by the frequency of the overfilling event. The calculated PLL has to be compared with the company’s tolerable risk (TOR) criteria. If the company does not have a defined TOR, then the UK Health & Safety Executive toler-

able risk target (i.e. 1 × 10–3 for workers, and 1 × 10–4 for the public) can always be used as a reference. If the calculated PLL appears to be greater than the TOR, then the risk is not acceptable and cannot be justified, no matter the cost. However, if it proves to be below the TOR, then the risk is in the “tolerable if as low as reasonably practicable (ALARP)” region. The analyst should sum all the losses (i.e., tank cost, inventory, nearby equipment, etc.), including the monetary equivalent of human life, and use this cost in a benefit-cost analysis to determine whether or not it is worth upgrading the existing overfilling protection systems. LITERATURE CITED ANSI/API Standard 2350, “Overfill Protection for Storage Tanks in Petroleum Facilities,” 4th Ed., 2012. 2 Mannan, S., “Lees’ loss prevention in the process industries: Hazard identification, assessment and control,” Elsevier, 4th Ed., 2012. 3 Center for Chemical Process Safety (CCPS), “Layers of protection analysis: Simplified process risk assessment,” Wiley, 2001. 4 UK Health & Safety Executive, “A review of layers of protection analysis (LOPA) of overfill of fuel storage tanks,” Research report RR716, 2009. 5 “Safety integrity level selection: Systematic methods including layer of protection analysis,” BS/IEC 61511-1:2003 and ISA/ANSI-84:2004. 1

AMJAD DOKHKAN works in the Petroleum Refinery of Jordan as the section head of the refinery process unit’s development. He is also responsible for the refinery’s process safety projects and studies. Mr. Dokhkan has worked for over 12 years in oil refining processes and technical safety, and he is a certified functional safety professional (CFSP) and a certified occupational safety practitioner.

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67

InstruCalc CONTROL VALVES • FLOW ELEMENTS • RELIEF DEVICES • PROCESS DATA

New Version Available

InstruCalc 9.0 calculates the size of control valves, flow elements and relief devices and calculates fluid properties, pipe pressure loss and liquid waterhammer flow. Easy to use and accurate, it is the only sizing program you need, enabling you to: • Size more than 50 different instruments, • Calculate process data at flow conditions for 54 fluids in either mixtures or single components and 66 gases, and • Calculate the orifice size, flowrate or differential range, which enables the user to select the flow rate with optimum accuracy.

Updates and What’s New in InstruCalc Version 9.0 ENGINEERING STANDARD UPGRADES

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Control Valve Revisions: • Updated to ANSII/ISA 75.011.01-2012 • Calculation accuracy changed for critical flows • Viscosity correction factor changed • Pressure drop calculation revised to agree with Crane Technical paper No 410. • Option of Cv Units (English) or Kv units (Metric) added. • Option of either aerodynamic noise calculation by ISA 75.17 method or InstruCalc method • Calculation accuracy added (input data within acceptable limits) Relief Devices: • Pressure Relief Devices Program follows API 520 Pt 1, 9th edition dated 7/14 OPERATIONAL IMPROVEMENTS The ability to have more than one calculation open at a time has been added. Each instance of the program is framed in a different color. The user can have multiple “what if” scenarios displayed for making engineering decisions.

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Process Control and Instrumentation G. OLESZCZUK, Honeywell Advanced Solutions, Warsaw, Poland; and M. BOŻEK, PKN ORLEN S.A., Płock, Poland

Utilize APC solutions to resolve hydrocracker conversion optimization challenges process. It was also implemented to allow optimization across Improving profits and reducing costs remain priorities for multiple process unit sections. owner/operators and management. Advanced process control (APC) solutions not only meet such expectations, but also very often exceed them. APC project methodology and control engine. The key In 2013, a solutions provider implemented two APC apsoftware is responsible for optimal online control of the difplications at the largest refinery in Central Europe, operated ferent processes. Most engineering activities are conducted by PKN Orlen in Płock, Poland. Based on market conditions online and on operating units requiring complex and deep and a benefits study, PKN Orlen designated two units for pilot chemical knowledge. To implement the system, APC engiAPC applications: the hydrocracker (HCK) and fluid catalytneers must first create a model of the investigated process that ic cracking (FCC) unit. This article focuses on the implemenis built empirically and based on a series of step tests. tation of the HCK and provides details of the suite of APC The scope of these steps must be large enough to discern solutions that have helped the PKN Orlen facility to achieve the response of the process unit, yet small enough to avoid greater profits and results. any significant disturbances to the process. Once the process Maintaining its edge as one of the largest oil and gas responses to the step tests are established, the matrix of transproducers in Central Europe requires that PKN Orlen mutation functions can be identified using a design software.c continuously improve its production standards, utilize the Transmutation functions are the linear models of the investilatest technologies and undertake a production optimization gated process, visualized in a two-dimensional space.1 The size program for the whole PKN Orlen Capital Group. An APC of this space is defined by the numbers of process-controlled solution is one of the main components of this program, mainly variables, manipulated variables and disturbance variables. because of its ability to quickly improve production results and An example of the process model transmutation function mamake a clear difference to the bottom line. trix, which reflects the number of process relationships, is shown A suite of APC solutionsa was already delivering sustained in FIG. 1. Because the model is empirically obtained, it can be process performance benefits at the Płock petrochemicals customized for specific process units or particular unit sections. and refinery complex, covering everything from the basic loop to realtime optimization and all necessary maintenance tools. Using the same type of software on the control and global process optimization layer would make it easier and more efficient for operators and engineers monitoring the solutions across multiple unit sections, and would also minimize training requirements. The solution is based on a commercial productb and its associated components.c, d, e As well as providing multivariable control, the controllerb provides a unified real-time (URT) platform for future implementation of specific and customized calculations that might be required for a specific FIG. 1. The process model transmutation function matrix reflects the number of process relationships. Hydrocarbon Processing | FEBRUARY 201669

Process Control and Instrumentation Such a solution guarantees more credible results than analytical models that are often far removed from real process conditions. A controller reads the process data from the existing control system based on the earlier obtained process model and, by utilizing a range control algorithm (RCA), sends optimal data back to the control system. There are three types of the controller inputs and outputs: • Controlled variables (CVs), which are usually process values, such as qualities, flows, temperatures and pressures, that must be kept in safe and optimal ranges • Disturbance variables (DVs), which are read-only variables, such as feed quality and ambient temperature or parameters outside the local control system’s control (i.e., disturbances from other process units) • Manipulated variables (MVs), which are the values the APC sends back to the control systems, are usually represented by the list of setpoint values for proportional integral derivative (PID) controllers. FIG. 2 is a simplified scheme showing how the controller works. The range control algorithm. The heart of the controller is the RCA, which calculates and predicts CV values based on the process model. Formulation of the RCA is based on a control theory, where the predicted CV is represented as:2

ỹ = Au

(1)

where A is the process model and u is a set of MV moves. The range control formulation is defined as: minu ,y W(Au − y)

2

(2)

where W is the weighting function. The above formulation is subject to the following constraints: ROCL ≤ ∆u ≤ ROCH ΔMVs lie within the rate of change limits MVL ≤ u ≤ MVH MVs lie within high and low bounds CVL ≤ y ≤ CVH CVs lie within high and low bounds

(3) (4) (5)

The solution u is the control moves, and the solution y is the optimal CV response trajectory. This control formulation minimizes energy input to the process (by minimizing the CV response error), minimizes scope for controller instability, and guarantees an optimal response because of minimum MV movement. Additionally, a tuning parameter, a “funnel,” was implemented in the RCA to shape the optimal solution trajectory.3 The funnel feature improves noise rejection, facilitates a Profit controller

DVs

Optimization Prediction

Control (RCA)

MVs

Control system (DCS)

Process model

FIG. 2. Honeywell’s Profit Controller architecture.

70FEBRUARY 2016 | HydrocarbonProcessing.com

Real process

CVs + -

minimum-effort solution with robust gain control, determines the control speed, enhances control performance and makes tuning much easier. The RCA itself guarantees robust control and, more importantly, when it comes to achieving benefits through optimization, the RCA formulation is extended to calculate a set of MV steady-state optimal targets, such that: J=

∑

ai × MViSS +

∑

bi ×CV jSS +

i=1,..# MVs

∑

(

i=1,..# MVs

j=1,..#CVs

)

2

c i × MViSS − MViT +

∑

(

d 2j × CV jSS −CV jT

j=1,..#CVs

)

2

(6)

where constants a and b are defined by APC engineers and process engineers or unit managers for product value optimization, and coefficients c and d are also defined by operation staff and are responsible for pushing the process to a defined “ideal operation point.” In reality, coefficients a, b, c and d are set during APC tuning to define the optimization objective targets. This optimization formula is then implemented in the RCA. Thus, a new RCA formulation with steady-state solution uSS for MV moves looks as follows:

(

)

⎡ y ⎤ ⎤ ⎡ Ad ⎤ minu ,y ⎡⎣ W Wo ⎦× ⎣ S ⎦×u – ⎣ uSS ⎦

2

(7)

The objective is to push the steady-state MV values with minimum effort closer to an optimum as defined by uSS. Ad specifies the process dynamics; S is a summation matrix; and Wo is a tuning weight to adjust the optimization speed and determinate how dominant the controller and optimization parts of the controller are. Once the model is built using the software tool, a multivariable controller can be generated and implemented in the existing control system. Operators and engineers at the unit control room use an online windows graphical user interfacef to control the process with the controller. This provides convenient access to review the recent work status of the implemented APC controllers and allows different privilege levels and access for different users. To predict the laboratory analysis in most APC projects in real time, inferentials (artificial analyzers) are designed. For the HCK unit, more than 10 inferentials were designed using sensor softwaree that is compatible with all main distributed control systems (DCSs) available on the market, and the software is located on the server computer. The server computer with APC software communicates with the existing control system [usually a DCS, but it can also be a programmable logic controller (PLC) or Scada system] via Ethernet connection using the open platform communications (OPC) interface. APC application challenges on the HCK unit. The HCK unit is one of the most complex units at the Płock refinery. It uses a catalytic process with specialized catalysts in two reactors to convert high-boiling-range material into diesel, jet fuel and lighter products. During this process, significant aromatic saturation and isomerization occur, in addition to the cracking. These reactions also take place in the presence of a recycle gas with a high hydrogen (H2 ) content. Effluent from the cracking reactor is cooled, and liquid products are separated from vapors.

Process Control and Instrumentation The vapor stream is then compressed and recycled to the reactors. The liquids are sent to the fractionation section, where various products are recovered. In the HCK unit (FIG. 3), fresh feed is routed from the vacuum unit, or from a combination of the vacuum unit and the storage tanks. The HCK’s valuable products range begins with heavy diesel and ends at light naphtha.

• Minimizing residue by minimizing light fraction content (final boiling point below 360°C) • Minimizing column pressure, oxygen (O2 ) in heater flue gases and fuel gas to heaters • Stabilizing MF column operation • Maximizing light naphtha flow • Stabilizing the naphtha splitter operation.

Objectives and constraints. The HCK unit’s potential caReactor constraints. Most of APC goals at the HCK unit are pacity is higher than 400 t/hr of fresh feedstock from the vacsubjected to some process unit constraints, with the most difuum unit: vacuum oil, atmospheric oil and, optionally, diesel ficult constraints on the reactors section coming from reactor oil from hydrodesulfurization of vacuum residue. The boilcatalyst behaviors and H2 heater limitations: ing range of the feed is 330°C to 557°C. Unit performance is, • The catalyst deactivation was very high (almost EOR) therefore, strongly dependent on the catalytic cycle. The HCK at the HCK unit during the project execution, distinguishes two phases of catalyst life: the start of run (SOR) which made the APC project even more complicated. variant and the end of run (EOR) variant, which differ in yields • The air coolers on the heat exchangers sometimes did and operating characteristics of the HCK plant. not fully balance the heat, which limited throughput The primary objective of the hydrocracker reactor advanced maximization. control was to provide safe and stable operation within unit • The H2 heater often had limitations on the tube skin constraints. The secondary objectives included conversion/ temperatures. inventory control, bed profile control and feed maximization. Controllers were used for online control and economic optiFractionation constraints. Meanwhile, the most important mization. The solution was dynamically integrated with other constraints on the fractionation section were due to product HCK sections, including parallel reactor trains and the product specification requirements: fractionator by using an optimizer technology.d • When running in diesel mode, the jet product was limited by initial boiling point (IBP), final/end boiling point The following general goals for the APC application were set: (EBP) and flash point. • Throughput increase • When running in jet mode, additional constraints • Conversion stabilization and maximization within surfaced: the naphthalene, asphalt and resins content in constraints heavy products; the light diesel product is limited by 90% • Reduction of standard deviation in the weighted average distillation, IBP and cold filter plugging point (CFPP); bed temperature (WABT) and conversion heavy diesel 95% distillation constraint is valid throughout • Middle distillates yield maximization through the whole year, while CFPP is a limit only during the winter. conversion improvement • Sulfur content is an important limit in summer, especially • Cost-effective energy optimization when light and heavy diesel products are combined. º Reactor temperatures reduction (while stabilizing • When the ambient temperature is very high, HCK conversion) operators have problems with cooling the top of º Main fractionator heaters’ outlet temperature reduction º Steam use reduction. Among these general tasks, specific objecLight naphtha Offgas tives were defined for the APC application: • Maintaining reactor bed temperatures Reactor 1 Reactor 2 Debutanizer Naphtha • Maintaining heater skin wall splitter temperatures Heavy naphtha • Maintaining consistent-quality Fresh M Deethanizer property values on the main fractionator (MF), with yields dependent on feed quality LPG • Controlling debutanizer temperature Jet fuel within constraints and product quality, and naphtha splitter HP top product quality Light diesel LP separator • Minimizing the H2-to-feed ratio separator VGO feed • Keeping ∆ temperature between Heavy diesel reactor beds close to zero Stripper column • Maintaining proper wall temperatures Main column on the H2 heater Bottom • Maximizing jet draw, light diesel draw and heavy diesel draw FIG. 3. A process overview of a hydrocracking unit. • Minimizing heavy gasoline flow Hydrocarbon Processing | FEBRUARY 201671

Process Control and Instrumentation the main fractionator column, which determines the heavy-naphtha final boiling point (FBP). • Minimum pumpdown flows are often required in the fractionator column to maintain the proper column circulation. As shown in FIG. 3, the main constraints for light end products of the stripper column were due to debutanizer column operation, where C5 content in LPG should not exceed 0.5%, and bottom C4 in naphtha should be below 7.8%. On the naphtha splitter column, the C7 content in light gasoline specification was 3% maximum. The FBP for the heavy gasoline product (180°C) was also constrained together with ∆P on an offgas vessel, which caused problems during very hot days. Based on the objectives above and the unit constraints, six multivariable predictive controllers were designed for the HCK unit—one for each of the hyrocracking reactors, and separate controllers for the following: the stripper column; the main fractionator column together with a heater; the debutanizer column; and the naphtha splitter column. Conversion control via optimizer. Conversion at the HCK

was calculated based on feed to the unit and flow of the hydrocarbon residue from the MF column, shown here: CONV = 1–

Residue flow from MF Feed to the unit

100%

Theoretically, this simple formula is correct; however, it often provides inadequate results: • The hydrocarbon cracking conversion process takes place on reactor beds, so product flows from the MF column (in this case, residue flow) might render the results of the above equation inaccurate, as they depend

FIG. 4. An APC in the DCS architecture.

Profit optimizer

Profit controller

Profit controller

Profit controller

SPs of many controllers

SPs of many controllers

SPs of many controllers

FIG. 5. Cascade APC structure of the controller with optimizer.

72FEBRUARY 2016 | HydrocarbonProcessing.com

on current MF operation conditions, not solely on catalyst cracking on reactors. • In this case, residue flow on the MF column was controlled in cascade with the column’s bottom level controller. This solution made conversion calculation very noisy due to level fluctuations at the bottom of the column. • The response on MF draws has a big delay relative to the time for hydrocracking reactions on the reactor beds—a time lag of up to 5 hr or longer. The first and the second points force APC to control variables, on which APC did not previously have a direct impact. It is very difficult to define the real conversion profile—the calculation requires a complicated nonlinear differential equation solver that must work in real time with an inadequate analytically evaluated model. In reality, by controlling conversion, the controller was not controlling the real conversion but the simplified formula (above) based on the real-time data provided from the DCS. Hydrocracker inferential. Inferentials were integral to the HCK APC project. Using historical data from lab samples and key process parameters, the inferentials were designed and implemented for the most important process quality parameters. These inferentials predicted the following product qualities: • Nitrogen (N2 ) content after the first reactor • Unstabilized gasoline, 90% distillation • Heavy naphtha, 95% distillation • Jet, 95% distillation • Jet, flashpoint • Jet, naphthalene content • Jet, aromatics content • CFPP of light diesel • Light diesel, 95% distillation • Heavy diesel, 90% distillation • Hydrocracker residue distillation, below 360°C • C5 content in liquefied petroleum gas (LPG) • Light naphtha, 95% distillation. Each inferential requires a few days of bias updating. The bias update calculation is based on laboratory data, and it continually updates the relevant inferential equation. This procedure makes artificial inferential calculation very reliable and a close proxy for actual lab samples. APC solution and results. The hardware solution (FIG. 4) for the HCK unit contains the APC server computer connected to the existing DCS through an APP-node computer, which serves as the OPC server. During the project execution, a number of additional features to help operators maintain the APC solution were delivered: • On the DCS side, all PID loops (used as MVs) were given a special indicator on the operator graphics to show if the particular loops are in remote cascade mode with the controller. • For safety reasons, an emergency shutdown button has been configured in the DCS on the DCS stations. The button ensures that the APC stops immediately after the operator enables it. • For lab sample bias updates, an additional graphical interface was created.

Process Control and Instrumentation

Modeling inferentials. This higher conversion from the APC application still needed to be transformed into yield increase by optimal separation. Product separation mainly takes place in the HCK main fractionation column. It was, therefore, necessary to get sharp cutpoints based on high-quality inferentials. Among the many possible ways of modeling inferentials in the software (including ordinary least square, partial least square and dynamic sub-space methods), the weighted least square (WLS) method was chosen to model the main quality properties. In the WLS method, soft-sensor models are based on robust regression, where they are desensitized to outliers in the data. While the robust regression models require a nonlinear solution, the final models in WLS are, in fact, linear.6 Despite the fact that linear models were used for all inferentials, a very good match with the real lab data was achieved. FIG. 7 shows some examples of the main product quality prosperities predicted by inferential modelinge against laboratory analysis over three months of unit operation from March to the end of May 2015. As can be seen, even during disturbances in operations that took place at the end of April 2015, the inferentials were able to predict lab values quite accurately.

The automatic bias update mechanism for all inferentials was also configured for the HCK unit. All lab samples were fetched directly from the laboratory information management system (LIMS) via a specially customized function block created in the universal runtime (URT) platform and presented on DCS graphics with time/data stamps. Instead of updating bias values for inferentials manually, operators accept new laboratory samples using DCS dedicated graphics. This solution improves data entry and increases accuracy of online laboratory samples prediction. With the implementation of controller and inferentials on the HCK fractionation sections, diesel yields were increased by more than 0.8%, while conversion stayed at the high 3% improved level. Results for diesel yield improvement based on real operation data are shown in FIG. 8 and TABLE 2. The APC at HCK units work like a process autopilot, boosting safety while maximizing yields of valuable products. As a result of the implementation on the HCK unit, PKN Orlen conservatively estimates that it has achieved increased profits of at least $2 MM/yr. Results were calculated and checked using real process data and standard benefit calculation methods.7 The return on investment (ROI) for the project was less than a few months. AKNOWLEDGMENTS The authors would like to express their thanks to PKN Orlen for analyzing operational data of post-APC samples and for its permission to publish the data. Also, they thank all operators and other PKN Orlen staff at HCK units for fruitful cooperation during the implementation of both APC projects. NOTES Honeywell Process Solutions’ Profit Suite portfolio. b The Profit Controllers, previously called robust multivariable predictive control technology (RMPCT)—Honeywell Process Solutions’ algorithm for APC and a

TABLE 1. HCK unit conversion pre- and post-APC application Conversion Base case, without APC

65.55%

Test run, with APC

68.51%

TABLE 2. HCK unit diesel yield pre- and post-APC application Diesel yield Base case, without APC

45.30%

Test run, with APC

46.16%

74 72

+ 2.96%

Conversion 2013

70 Conversion, %

The APC process solution had to fulfill all the process objectives and handle all unit constraints listed above. To achieve this, controllers were designed to work in different operation modes. Depending on current unit objectives, the APC solution can maximize jet production, diesel production or olefins yield. To automatically switch between the most frequently used production modes, a special DCS point and operator switch was implemented and visualized as a faceplate on the DCS graphic. To overcome the conversion obstacles, it was decided (as in similar APC projects4) to use an optimizer, another software tool from the portfolio. A cascade approach allows the optimizer to take over the task of optimization across multiple sections. It reuses the controller models to provide steady-state and dynamic optimization across multiple process sections. Moreover, the optimizer can be used for many units—the entire plant can work under one or more optimizers. FIG. 5 illustrates the hierarchical connection between the optimizer and the controllers. Three controllers were designed to work under one optimizer. Two controllers were responsible for optimization and control of the hydrocracking reactors, and one APC controller was designed for controlling and optimizing the main fractionator column.5 The built-in optimizer in the slave profit controllers was configured for reactor product value optimization, while H2 quench flows and product flows were adjusted to maintain conversion and unit throughput. Disturbance rejection was applied for bed temperature control stability to account for the exothermic and highly interactive nature of the hydrocracker operation. Controlled variables in the optimizer included: reactor conversion, WABT, reactor profiles (or bed temperatures), H2 quench valves, H2 make up and H2/hydrocarbon ratios. Optimization coefficients (mentioned in the technical description of RCA) were assigned for conversion at very high values to maximize the conversion within unit constraints. This approach, using the controllers with the optimizer, increased the average cracking conversion compared to the pre-APC period by almost 3%, as shown in FIG. 6 and TABLE 1.

68 66 64 62

Conversion 2012

60

FIG. 6. Conversion improvement at the HCK unit after implementation of the APC. Hydrocarbon Processing | FEBRUARY 201673

Process Control and Instrumentation Jet gasoline flash point inferential vs. lab analysis

60

Distilation of light diesel, 90%

Jet gasoline flashpoint

55 50 45 40 Jet FP inferential Lab samples results

35

Light diesel D90; inferential vs. lab analysis

Inferential D90% light diesel Lab samples results

20-Feb. 25-Feb. 2-Mar. 7-Mar. 12-Mar. 17-Mar. 22-Mar. 27-Mar. 1-April 6-April 11-April 16-April 21-April 26-April 1-May 6-May 11-May 16-May 21-May 26-May 31-May 5-June 10-June

25-Feb. 2-Mar. 7-Mar. 12-Mar. 17-Mar. 22-Mar. 27-Mar. 1-April 6-April 11-April 16-April 21-April 26-April 1-May 6-May 11-May 16-May 21-May 26-May 31-May 5-June 10-June

30

340 330 320 310 300 290 280 270 260 250 240

Time

Time

Distilation of heavy naphtha, 95%

165

Heavy naphta D95; inferential vs. lab analysis HN D95% inferential Lab samples results

380 Distilation of heavy diesel, 90 %

170

160 155 150 145 140

Heavy diesel D90; inferential vs. lab analysis

370 360 350 340 330

Inferential D90% heavy diesel Lab samples results

320

20-Feb. 25-Feb. 2-Mar. 7-Mar. 12-Mar. 17-Mar. 22-Mar. 27-Mar. 1-April 6-April 11-April 16-April 21-April 26-April 1-May 6-May 11-May 16-May 21-May 26-May 31-May 5-June 10-June

20-Feb. 25-Feb. 2-Mar. 7-Mar. 12-Mar. 17-Mar. 22-Mar. 27-Mar. 1-April 6-April 11-April 16-April 21-April 26-April 1-May 6-May 11-May 16-May 21-May 26-May 31-May 5-June 10-June

135

Time

Time

FIG. 7. Inferentials prediction vs. real laboratory results for some quality properties at the HCK unit.

Jet light diesel and heavy diesel yields, %

50 49 48

LITERATURE CITED Qin, S. J. and T. A. Badgwell, “A survey of industrial model predictive control technology,” Control Engineering Practice 11, 2003. 2 MacArthur, J. W., “RMPCT: A new robust approach to multivariable predictive control for the process industries,” Honeywell Inc. Industrial Automation Control, internal documentation. 3 Lu, J., “Challenging control problems and emerging technologies in enterprise optimization,” IFAC (International Federation of Automatic Control) Symposium on Dynamics and Control Process Systems, 2001. 4 Mastrogiacomo, M., M. Piccolo and L. Johnson, “Hydrocracker and hydrogen production optimization using Profit Optimizer,” Industry Solutions for a Changing World Conference—User Group, 2002. 5 Oleszczuk G. and M. Dylewska, “Advanced process control in FCC and hydrocracking units,” PTQ magazine, 2Q 2015. 6 Honeywell Profit Suite documentation—Profit Sensor Pro User Guide. 7 Martin, G. D., L. E. Turpin and R. P. Cline, “Estimating control function benefits,” Hydrocarbon Processing, June 1991, p. 68–73. 1

+ 0.86%

47 46 45 44 43 42 41

Without APC With APC Linear, with APC Linear, without APC

FIG. 8. Improvement in diesel yield on the HCK unit after APC implementation. local optimization. c The Profit Design Studio—Honeywell Process Solutions’ MS Windows-based APC desktop for developing and offline testing of Profit Suite APC and APCrelated applications. d The Profit Optimiser—Allows cost-effective, multi-unit optimization, sitting on top of the Profit Controller with both steady-state and dynamic optimization. For some plants (e.g., ethylene), this technology has been used for plant-wide optimization with much lower implementation and maintenance costs than traditional real-time optimization (RTO). e The Honeywell Profit Sensor Pro (PSP)/Lab Update—Honeywell Process Solutions’ inferential modeling for soft sensors with lab feedback, fully integrated with Profit Design Studio. The inferential models developed can be used as inputs in a multivariable or other control scheme. It also features static pressure control (SPC) as an option for smart lab feedback, removing lab noise and outliers. f Profit Suite Operation Station (PSOS)—Honeywell Process Solutions’ online Windows-based graphical operator interface for Profit Suite applications.

74FEBRUARY 2016 | HydrocarbonProcessing.com

GRZEGORZ OLESZCZUK has worked in control and optimization industrial processes for 15 years, with more than eight years at Honeywell as an advanced solutions operation leader. He has implemented several APC and OTS solutions across Europe and North Africa. Dr. Oleszczuk gained his PhD in automation and dynamics at Old Dominion University in Virginia, and an MSc degree in chemical engineering and automation control at Warsaw University of Technology in Poland. He specializes in process dynamics modeling. MAREK BOŻEK is a manager with long experience in production process management. An active participant in many investment and effectiveness programs realized in refineries, he is a former senior process engineer of the FCC and PrimeG+ unit. Mr. Bożek is the manager of the APC department and is directly responsible for the implementation and maintenance of advanced process control systems in the PKN Orlen refinery.

Process Control and Instrumentation M. MARSHALL, Michael Marshall LLC, Findlay, Ohio

Enhance PSM design with metrics-driven best practices This study identifies the attributes and benefits of a data- and metricsdriven management system focused on the process safety design integrity, reliability and control of process plant flares and pressure relief systems. This process safety management (PSM) system approach focuses on the four key business drivers of risk, regulatory, operations and profits, and involves several distinct business methods involving people, processes and tools/technology. At the center of the management system is the unique design and implementation of metrics and key performance indicators (KPIs) created from data that is lifted and aggregated from an enterprise asset management platform. The current regulatory climate. The

highly publicized incidents at BP Texas City, Texas in 2005; Tesoro Anacortes, Washington in 2010; and Chevron Richmond, California in 2012, occurred not because of a singular failure of equipment, instrumentation, facility siting, operator, procedures, communication, supervision or training, but rather a failure of a combination of all those things—i.e., a management system failure. The BP, Tesoro and Chevron incidents are now driving the reexamination of the PSM rule by the US regulatory community. The US Chemical Safety Board (CSB) has taken notice that US oil and gas industry losses are the highest among any industrial sector, as well as the fact that the US refining industry accident rate is 3 to 4 times higher than in Europe. The PSM rule and its allegedly “lessrigorous regulatory framework” are quickly falling out of favor with regulators. As such, the attributes of the “safety case” and as low as reasonably practical (ALARP) regulatory regime currently

in use throughout the UK, Australia and Norway are now being advocated by the CSB. More notable is California’s proposed regulation for inherently safer design (ISD), an initiative that was endorsed by then-CSB chairman Dr. Rafael Moure-Eraso, who suggested that other states do the same. ISD has been hotly debated for years and would require that risk be reduced to the greatest extent possible with the selection and implementation of changes in chemistry and/or a change to process variables—e.g., the reduction in pressure, temperature, flows, etc. Unmistakably, this would take the petrochemical industry and its PSM approach from performance-based to prescriptive.

Before opting to prescriptively rewrite the PSM rule, it is suggested that a focused metrics-driven management system approach is more sensible, productive and achievable in the short term. Such an approach also embodies the core principles of the PSM rule and is consistent with the findings and recommendations of the 2007 Baker Panel Report (TABLE 1). It would seem that the Baker Report is prompting a revisit to the PSM rule for intent and direction, as well as for the proper administration of PSM— the effective application of a management systems approach to continuously improving our process safety environment and culture. The authors of the

TABLE 1. 2007 Baker Panel focus areas and opportunities for improvement 1.  Process safety management systems a. Process risk assessment and analysis b. Compliance with internal process safety standards c. Implementation of engineering good practices—Engineering design practices and associated training are in place and translate industry RAGAGEP into specific “how to” design guidance and application standards d. Process safety knowledge and competence e. Effectiveness of corporate process safety management system—Management systems are effective and successful in preventing accidents. 2. Performance evaluation, corrective action and corporate oversight a. Measuring process safety performance b. Incident and near-miss investigations c. Process safety audits d. Correction of identified process safety deficiencies—Repeat findings are addressed suggesting that “true root causes” are not being identified and corrected e. Effective use of findings from operating experiences, process hazard analyses, audits, near misses and incident investigations to improve operations and systems—Performance data and indicators are effectively used to drive continuous improvement in process safety and risk management systems (e.g., the risk of major incident relative to LOPC data) f. Adequate management and corporate oversight. 3. Corporate safety culture—Any one or all of the following management system elements might be scrutinized in the event of an incident relative to the opportunities noted above: a. Effectiveness of process safety leadership b. Adequacy of employee involvement and empowerment c. Adequacy of resources and positioning of process safety capabilities d. Effectiveness of incorporation of process safety into management decision-making e. Common, unifying process safety culture. Hydrocarbon Processing | FEBRUARY 201675

Process Control and Instrumentation PSM rule took great pains to make it a performance-based standard for a reason (prescriptive is inherently inferior), so it should not be abandoned now. Revisiting PSM, management systems and continuous improvement.

With the promulgation of the PSM Standard 29 CFR 1910.119, the US Occupational Safety and Health Administration (OSHA) mandated that a management system comprising several well-defined elements be established “for preventing or minimizing the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals.” The process safety information (PSI) element of the PSM rule states, “The employer shall document that equipment complies with recognized and generally accepted good engineering practices (RAGAGEP),” with specific reference given to “relief system design and design basis.” Although OSHA does not explicitly use the term “continuously improving” in its regulatory standards, it uses equivalent terms such as “accurate, complete, clear and ongoing,” as in the Appendix C compliance guidelines of 29 CFR 1910.119, which uses the term “complete and accurate” in lieu of “continually improving.” Likewise, for the mechanical integrity element of 29 CFR 1910.119, OSHA uses the term “ongoing” to describe the expectation to continually improve. Recent incidents and enforcement actions demonstrate OSHA’s expectation for operating plants to maintain a continually improving PSM system. In 2007, OSHA initiated its National Emphasis Program (NEP), a special enforcement initiative specific to refineries and chemical plants. Of the citations issued, many involved missing, inaccurate and incomplete process safety information, as well as outdated relief system studies. A management system for flare and relief systems.

Flare and relief system design compliances are also assessed annually in ever-increasing detail for participants of OSHA’s Voluntary Protection Program (VPP). The environmental enforcement aspect to flare

operation and systems management continues to be relevant. Notwithstanding social responsibility, it is just good business to develop a management system that not only enhances safety and environmental protection, but also augments asset protection. Safety and environmental stewardship are of paramount importance, but asset protection, business continuity and public image also have vital significance in any business environment. Knowing what data to capture and display is essential to proper metrics development and analysis, and the ensuing derivation of KPIs. FIG. 1 illustrates the who, what, when, where and how of doing just that with a focused, metrics-driven flare and overpressure management system (FOMS). Associated FOMS benefits. It goes

without saying that flare and relief system design and operation have come under intense scrutiny by OSHA. With the US Environmental Protection Agency (EPA) now getting into the act, it would seem that regulators are looking for a new “3% inlet pressure drop (IPD)” soft spot, and have found it in flare system operation and management. The vast majority of gas flaring is associated with plant upset, poor operation or imbalance, and, as such, is unplanned and subject to regulatory penalty. The EPA is now aggressively mandating and enforcing flare management plans (FMPs) and flare gas recovery systems, just as OSHA enforced relief-system pressure relief analyses (PRAs) and the 3% IPD rule.

It has become clear that this doublebarrel surge via OSHA and the EPA has arrived and is progressing rapidly. It may seem that the industry is under assault, but the ultimate truth is that process safety just makes good business sense. When considering a performance improvement program in this highly regulated process safety environment, four key business drivers should be considered: risk, regulatory, operations and profits. Building a focused flare and relief systems management process around those four drivers involves a unique management system structure of people, processes and tools/technology. Central to the growth and continuous improvement of those three elements will be the proper design and implementation of metrics and KPIs. The institutionalization of KPIs and the subsequent reporting and action planning process will drive the continuity and sustainability of the plan-do-check-act rudiments of this management system approach.

Sustainability through KPIs. The PSM standard is exceptional in its vision, design and implementation, but it could have been made better by the inclusion of metrics and KPIs. It is often said, “If it can’t be measured, it can’t be managed,” and this is likely a reason why so many PSM programs have failed to grow and measure up to industry best practices and OSHA expectations. KPIs are critical to a properly designed management system in that they institutionalize processes and drive accountability, providing continuity and sustainability. An effective KPI system and data mining process takes into consideration business drivers, success factors, targets, improvement actions and performance measures. However, knowing which metrics should be funneled into KPIs is the challenge. It would now seem that API 754 was written only to gauge the “high-level” effectiveness of PSM programs. The opportunity still remains for further development of focused metrics that further drive performance improvement in areas like flare FIG. 1. Capturing and displaying the correct data are essential to and relief system design and proper metrics development and analysis. operation, among others. Cor-

76FEBRUARY 2016 | HydrocarbonProcessing.com

Process Control and Instrumentation respondingly, the CSB has characterized the shortcomings of API 754 as follows: • Tier 1 and 2 numbers are lagging indicators and thus of limited usefulness as performance indicators. • The statistical power of small numbers of Tier 1 and 2 events is insufficient to detect effect. • Tier 3 and 4 events are leading indicators that are reflective of process failures, yet they are not publicly reported and utilized for industry trend analysis and benchmarking comparisons. • Employee participation was insufficient in the development process and thereby lacking in a broad-based consensus. Industry can be even more critical and innovative by utilizing historical operations, reliability and maintenance data in analytical tools and performance metrics to create a competitive environment for improving plant reliability and profitability. The word “competitive” should be stressed so this plan-do-check-act process will drive itself and grow by fostering a healthy and productive incentive among stakeholders for continuous improvement in reliability, profitability and, most importantly, process safety.

points, metrics flood and confusion can set in and negatively impact the problemsolving process. Proper development, implementation and management of metrics and KPIs should involve many of the same concepts utilized in alarm rationalization and management—it is more of an art form than many realize, requiring critical thinking and strategic design aptitude that draw on a frontline-to-exec level of appreciation for what “good” looks like. This is what the FOMS developers had in mind for a management process focused on flare and relief systems. Too often, the process of data gathering and metrics reporting is more about presentation than substance and lacks real problem solving and process optimization potential. The metrics and KPIs of an FOMS are specifically designed for

Management system design and implementation. Again, PSM was con-

ceived out of a management system mentality of a plan-do-check-act cycle with continuous improvement at its core. The focused, metrics-driven management system of FOMS follows this same model and function, illustrated in FIG. 2. In application, it begins with a four-phase development process: Where are we now? Where do we want to go? How are we going to get there? Phase 1: Where are we now? • Identify and engage process owners and stakeholders

TABLE 2. The process of data gathering and metrics reporting should solve real problems and address process optimization potential. Risk

Where is the risk? How should it be managed?

Regulatory

What are the compliance needs? Where is the most vulnerability?

Operations

How can operational health be measured? How can safety systems be optimized?

Profits

What are the economic impacts of flaring? What are the flare limits on operations?

Continuous improvement

How can sustainability be ensured? Define who, what, when, where and how.

Refining the development of KPIs.

The idea is to tap into the data-rich potential of an enterprise asset management (EAM) system. From this data and informational structure, the 20% of data that 80% of operators, engineers, managers and execs want to see is extracted, with the challenge being identifying that 20% of key information. Beyond that, further consideration is necessary for the more refined development of KPIs, which then provide the need-to-know requirements of stakeholders at a “dashboard” level of awareness. What so many KPIs fail to do is drill down deeply enough to facilitate the identification of basic and root causal factors associated with problem solving for optimal performance. There can be too many of these focused metrics, and the pitfalls are similar to usability problems associated with multiple alarms sounding during a process unit upset, commonly referred to as “alarm flood.” Just as with too many alarms, poorly designed alarms and improperly set alarm

problem-solving performance improvement issues at the basic and root cause levels, and they are built around the business drivers of risk, regulatory, operations and profits (TABLE 2).

• Industry benchmarking • Costs and budgets • Culture and involvement • Risk tolerance • Governance • Compliance

Act

Flare and overpressure management system

Plan Tradeoffs and costs Assess progress relative to standards Drivers, goals PSM and RMP and strategies RAGAGEP VPP Leadership and vision

Risk Regulatory Operations Profits

Form team Baseline and gap analysis (SWOT) Redesign work processes

• Pressure relief analysis (PRA) • PHA • LOPA (Philosophy apps, f/N) • PSI and document control • Best practices and procedures • Training

Resource allocation, tools and technology

Do

Review performance targets

Automation tools and software Metrics, KPIs and Implement new work reports processes and procedures Roles and responsibilities Root cause analysis

• Auditing and certification • One-stop ePSD portal • Incident investigation • Emergency response and planning • Lessons learned

• Management of change • Health check monitoring • Risk profiling and mapping • Debottleneck and optimize • Flare management, minimize • Mechanical integrity (RBI)

Check

FIG. 2. The FOMS follows the plan-do-check-act cycle. Hydrocarbon Processing | FEBRUARY 201677

Process Control and Instrumentation

FIG. 3. Inverting the hierarchical pyramid and involving personnel at all levels are keys to understanding and leveraging the nuances of company culture.

º A changing PSM and PRA landscape º BP, Tesoro and Chevron incidents are driving reexamination of PSM rule º US refining accidents are three to four times that of Europe º Safety case and inherently safer design/technology (ISD) are gaining favor with regulators • Compile available documents and information • Flowchart current processes, tasks and procedures º PRA methods and processes are now mature º PRAs giving way to enhanced auditing, mini-PRA tune-ups and management of change (MOC) processes º Are more processes needed to ensure PRA integrity? º Intense regulatory scrutiny remains: risk, regulatory, operations and profit drivers • Identify current tools and technology º PRA science and technology are still evolving º There is little in the way of PRA-specific management systems tools/information technology (IT) º There is a lot of IT structure in need of management system content and integration • Understand strengths, weaknesses, opportunities and threats (SWOT) in existing processes. Phase 2: Where do we want to go? • Engage process owners and 78FEBRUARY 2016 | HydrocarbonProcessing.com

stakeholders for vision, objectives and value drivers º Business focused without putting safety second º Team environment, but competitive º Problem solving º Communities of practice and pride º Knowledge managers, not tribal º Bottom-up, top-down, inverted pyramid with “closest to the work” mentality º Measurements, accountability and rewards • Baseline processes and perform gap analysis • Evaluate gaps and tradeoffs (costs) • Redesign processes and functionalities º Think like an operator, manager, regulator º Metrics and reporting, KPIs º Ongoing gap analyses, data centric º Expert systems to automate º Integrate with existing systems, customizable º Process optimization and profits º Better manage and control change º Enable regulatory compliance; safety case and ISD º Cross-organization integration and collaboration º Focus on operations workforce º Standardization and consistency • Specify tool and technology needs º Workflows º Protocols and practices º Portals and links to data and systems º Data repositories º Search engines and links º Dashboards, scorecards, forums º Executive dashboards º Document management º Training and more training, e.g., computer-based º Enterprise discoverability and sharing º Design to drive sustainability • Develop project plan and prioritize. Phase 3: How are we going to get there? • Identify needs and objectives º Define “good” or “where we want to go,” and plan a path forward º Critical focus on management systems design and

implementation, people, processes, tools/technology º Strategic focus on gaps, soft spots and critical systems within operations, maintenance and engineering organizations, corporate º Content, the 20% of data that 80% of stakeholders want to see (strategic and customizable KPIs, data maps, scorecards, dashboards, reports, data portals, alerts, analyses and trends) º Design to involve only new processes and tools, not new labor • Develop strategic purpose º Maintain a business perspective on everything, including process safety º Tightly integrate strategy and tactics with business processes to be self-sustaining º Ensure that organization and systems are designed to enable execution of business processes º Showcase new philosophy to inspire personnel at all levels º Design for employee involvement and buy-in at all levels, and make it competitive º Integrate with existing assets, programs and systems º Get KPIs in the hands of those closest to the work, i.e., those most able to affect change º Connect enterprise performance measurement with budgets, reviews and bonuses º Make everyone an ambassador, especially regulators º Design metrics to be what operators, managers and executives want º Adapt and make compatible with outsourcing applications of IT and engineering services • Establish team leadership and governance º Understanding and leveraging nuances of culture is vital º Plant environment (operations, maintenance, engineering, corporate) º Cost/safety prioritization, RAGAGEP benchmarking º Address internal competitiveness and silos º Integrate with RBI and PSM

Process Control and Instrumentation offerings, leveraging IT and maximizing synergies º Get regulators on board, such as local and state OSHA, EPA º Communicate to and involve everyone at all levels, and invert the hierarchical pyramid (FIG. 3) • Perform root cause analysis • Design metrics, KPIs, reports, automation tools º Design to drive sustainability (training, auditing, certification, profits) º Integrate with existing IT structure and software, synergies º Provide for enterprise discoverability and sharing ❒ Leverage EAM platform and integrate with PRAs ❒ Asset integrity management systems ❒ Continuous emissions monitoring systems (CEMSs) ❒ PSM suite of software ❒ Digital control systems ❒ Process instrumentation º Remember that IT and software prowess need content in cohesive processes, an FOMS º New/improved software solutions, business methods and Internet innovations • Initiate training programs • Implement transition plan, pilot and then rollout º Compatible with third-party applications, software and systems º Leverage synergies/overlaps with PSM, equipment inspection and reliability programs, e.g., RBI API 580/581, especially damage mechanisms (API 572) and mechanisms contributing to the loss of primary containment (LOPC) º Flare/relief system specific programs for mechanical integrity, MOC, incident investigation, procedures, PSI and other PSM elements. Phase 4: How do we improve, grow and keep going? • Implement and validate redesigned process • Initiate ongoing metrics and management systems • Monitor, evaluate and report on new processes • Review targets and performance

• Audit and adjust for continuity, sustainability and growth. A close second. A close second to an FOMS, however, would be a focused, metrics-driven management system approach addressing mechanisms contributing to LOPC. LOPC is preventable, and equipment reliability relative to process safety is by far the leading risk opportunity and ongoing business concern facing the oil and gas industry today. The same personnel, processes and tools/ technology (software and EAM) structure and methods employed in an FOMS can be easily adapted for an LOPC-focused initiative. This strategic initiative also involves the same business drivers of risk, regulatory, operations and profits. Industry can also be much more critical and innovative in responding to LOPC incidents, data and metrics with enhancements to mechanical integrity proficiencies relative to inspection, maintenance, design and overall systems management. Historical operations, reliability and maintenance data can be better utilized and managed with analytical tools and performance metrics to determine needs and risk exposure, provide direction and address opportunistic reliability issues. A refining-specific incident and loss database, as well as an optimization methodology (utilizing RCFA) that quantifies the economic impact (dollars in lost profit opportunity) of equipment anomalies, LOPC incidents and upset/malfunction operating conditions, has been developed and put into practice. This approach includes a much more critical focus on inherently challenging API 754 process safety event (PSE) LOPC metrics relative to damage mechanisms; operating envelopes; and consequences of deviation, procedures, design and training. MICHAEL MARSHALL has over 33 years of experience working in the refining and petrochemical industry. While working first with Chevron for 10 years and then retiring from Marathon Petroleum Co. after 23 years, he progressed through various in-plant and corporate refining facility and project engineering, operations, maintenance and equipment inspection/reliability managerial positions. His areas of expertise include risk-based equipment inspection and mechanical design relative to the loss of primary containment damage mechanisms, safety systems and overpressure protection. Mr. Marshall holds a BS degree in civil engineering from Purdue University and is a registered professional engineer (PE) in the state of Indiana. Select 157 at www.HydrocarbonProcessing.com/RS

2016

August 2–3, 2016 Norris Conference Centers – CityCentre Houston, Texas

Final Call for Participation Call for Abstracts Extended

Gulf Publishing Company, publisher of Hydrocarbon Processing and Gas Processing, is pleased to announce that the fourth annual GTL Technology Forum will be held in Houston, Texas on August 2–3, 2016. If you would like to participate as a speaker, we invite you to submit an abstract for consideration by our advisory board. This year’s program will focus on economics of scale and the dynamics of GTL in a low-cost environment.

Suggested topics and areas of interest include: • GTL: Fischer-Tropsch • GTL: MTG/methanol • GTL products: fuels, lubes, specialty products, etc. • Economics, properties, performance, etc. • Floating GTL • Financing of GTL projects by owners, equity, banks • Permitting issues (requirements, thresholds, timing, etc.) • Waste heat recovery • Maximizing wax and chemicals production • Upstream and downstream integration • SynGas generation (SMRs, ATRs) • And more. For a full list, visit GTLTechForum.com

Don’t miss this unique opportunity to share your knowledge and expertise with your peers in the industry. Submission Deadline: March 4, 2016. Abstracts should be approximately 250 words in length and should include all authors, affiliations, pertinent contact information, and the proposed speaker (person presenting the paper). Please submit via e-mail to [email protected]. Speaker/Sponsor/Exhibitor Inquiries: Please contact Melissa Smith, Events Director, Gulf Publishing Company, at [email protected] or +1 (713) 520-4475.

GTLTechForum.com

ADRIENNE BLUME, EXECUTIVE EDITOR [email protected]

Innovations Design software reduces risk, boosts efficiency of brownfield projects In a market with reduced capital investment budgets, revamps and upgrades are becoming increasingly prevalent to extend asset service life. The ability to execute brownfield projects rapidly, efficiently and at low risk is essential to both engineering, procurement and construction (EPC) companies and to their owner-operator (OO) clients. The latest version of AVEVA Everything3D (AVEVA E3D) integrates a number of new features (FIG. 1) that offer EPC companies a valuable edge when bidding for these projects, and also enable OOs to achieve greater return on investment at lower risk. AVEVA E3D reenvisions laser data integration by incorporating technologies such as HyperBubble (a photorealistic rendering of laser scans), Laser in Draw, and Design in Context. By integrating HyperBubble data into the 3D design environment, designers can take accurate measurements between any points in the entire scanned asset. They can also align new designs with existing objects and perform clash checks between designed objects and the point cloud. AVEVA E3D is said to allow for the easy application of lean principles to brownfield projects. Point cloud demolition and re-scan registration capabilities enable the concept of the Trusted Living Pointcloud. Used in conjunction with the 3D model, the pointcloud provides a valuable resource for throughlife asset management. The use of 3D laser scanning for accurate and detailed site survey is now widely established. It is claimed to be quicker, cheaper and more efficient than traditional surveying techniques, since large areas can be accurately scanned in a short time. It is possible to reference laser data when creating a new design, but AVEVA E3D makes laser data directly usable within its own 3D design environment.

The AVEVA E3D 2.1 Laser in Draw capability means that it is now possible to use the laser data for both 2D and 3D deliverables. The as-built design and the new design can be combined on the same drawing, which saves time and cost, and makes construction drawings more easily understood by the onsite team. AVEVA has also pioneered a cloud deployment of AVEVA E3D to offer its customers reduced infrastructure costs and the ability to flex license call-off in response to project workload fluctuations.

FIG. 1. The 3D plant design model is created and modified using discipline-specific applications optimized for efficient modeling.

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Research advances clean diesel production for future industrial use Researchers from Katholieke Universiteit (KU) Leuven in Belgium and Utrecht University in the Netherlands have discovered a new approach to the production of fuels. The new method reportedly can be used to produce much cleaner diesel and can quickly be scaled up for industrial use. The production of fuel involves the use of catalysts. These substances trigger the chemical reactions that convert raw material into fuel. In the case of diesel, small catalyst granules are added to the raw material to sufficiently change the molecules of the raw material to produce usable fuel. Catalysts can have one or more chemical functions. The catalyst that was used in the university study has two functions, represented by two different materials: a metal (platinum) and a solid-state acid. During the production process for diesel, the molecules bounce between the metal and the acid. Each time a molecule comes into contact with one of the materials, it changes. At the end of the process, the molecules are ready to be used for diesel fuel. The assumption has always been that the metal and the solid-state acid in the catalyst should be as close together as possible; this would speed up the pro-

duction process by helping the molecules bounce more quickly. Professor Johan Martens (KU Leuven) and Professor Krijn de Jong (Utrecht University) have now discovered that this assumption is incorrect. If the functions within a catalyst are nanometers apart, then the process yields better molecules for cleaner fuel. The new technique can optimize several molecules in diesel. Cars that are driven by this clean diesel would emit far fewer particulates and CO2. The researchers believe that their method can be scaled up for industrial use with relative ease, enabling the new diesel to be used in cars in 5–10 years. Select 2 at www.HydrocarbonProcessing.com/RS

Control system boosts cyber security and processing performance As concern with cyber threats to refineries continues to grow, traditional control system vendors are responding by adding cost and complexity to their legacy technology. The Bedrock universal control system from Bedrock Automation is said to offer refineries increased performance, processing power, redundancy, scalability, cyber security protection and cost efficiency. Featuring a patented architecture with a pin-less, electromagnetic backplane (FIG. 2) and embedded cyber security, Bedrock addresses virtually all control applications with fewer than a Hydrocarbon Processing | FEBRUARY 2016 81

Innovations dozen part numbers—reducing cyber attack vectors; cutting lifecycle costs; and simplifying engineering, commissioning and maintenance. Reinventing control systems. A commitment to functional design is a core tenet of the system that delivers input/output (I/O), power and communications across the pin-less electromagnetic backplane, with a parallel architecture that supports rapid scan times regardless of I/O count. The removal of I/O pins improves reliabil-

FIG. 2. The real-time operating system delivers safety and multi-layered cyber security.

ity and increases cyber security while forming a galvanic isolation barrier for every I/O channel. This backplane also allows installation of I/O modules in any orientation and location for flexibility in I/O and cable management. Secure I/O modules use layers of advanced technology to deliver softwaredefined I/O for universal analog, discrete, Ethernet and Fieldbus signal types. A secure power module is functionally and physically coupled to the backplane to deliver single- and dual-redundant cyber secure power for the control system. A secure universal controller is powerful enough to run virtually every application, independent of size or control task: discrete, batch, continuous or multivariable control from one device that supports as few as 10, to as many as thousands, of I/O points. Separate programmable logic controllers (PLCs) and distributed control systems (DCSs) are no longer required. Layers of protection. Replacing pins with an electromagnetic backplane is a

key layer of cyber security protection that Bedrock Automation has implemented. Additional cyber security layers include: • A real-time operating system (RTOS) with what is claimed to be the highest safety and security rating of any available RTOS • Cyber secure microcontrollers with encrypted keys embedded in all system modules, including the controller, power supply and I/O • All modules encased in antitamper metal that is impenetrable without metal cutting tools • Authentication extending throughout the supply chain, including third-party software and applications. Adding many layers of protection to a conventional DCS, SCADA RTU, PAC or PLC would add cost and complexity, and degrade performance. However, these layers have been built into the Bedrock design, offering more immediate security and increased protection. Select 3 at www.HydrocarbonProcessing.com/RS

HPIRPC.com

Register Early + Save 15%

7–8 June 2016 | Milan Marriott Hotel | Milan, Italy

Join us for the 7th Annual IRPC as we explore “Innovation in the Downstream” Gulf Publishing Company and Hydrocarbon Processing are pleased to announce that the 2016 International Refining and Petrochemical Conference (IRPC) will be held 7–8 June in Milan, Italy. In its seventh year, the 2016 conference and exhibition will provide a high-level technical forum in which key players in the global petrochemical and refinery sector will meet to share knowledge and learn about best practices and the latest advancements in this developing sector of the oil and gas industry. The theme for this year’s conference is “Innovation in the Downstream.” The 2016 program will be put together by an esteemed advisory board, and will cover refining/petrochemical integration, licensing technology, maintenance and reliability (including preventative maintenance, the Internet of Things (IoT) and predictive maintenance,) energy policy, heavy oil, emerging technologies, plant design and more. The preliminary agenda will be announced soon. Stay tuned to HPIRPC.com for more information. For Sponsorship/ Exhibit/General Inquiries: Contact Melissa Smith, Events Director, +1 (713) 520-4475 or [email protected]

82FEBRUARY 2016 | HydrocarbonProcessing.com

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Company Website

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Events—Petchem..................................... 67 Marketplace............................................. 83 HPI Market Data 2016..............................50A Software..................................................68 John Zink Company .....................................17 (61) www.info.hotims.com/61384-61

KBR............................................................48 (97) www.info.hotims.com/61384-97

Bete Fog Nozzle........................................... 27 (73)

Kelvion Holding GmbH...................................2 (79)

CB&I............................................................ 22 (58)

Man Diesel & Turbo...................................... 47 (100)

cippe.......................................................... 57 Dyna-Therm.................................................16 (154)

Merichem Company...................................... 11 (84)

www.info.hotims.com/61384-73

www.info.hotims.com/61384-58

www.info.hotims.com/61384-154

Gulf Publishing Company Events—ECF............................................. 87 Events—GasPro......................................50B Events—GTL.............................................80 Events—IRPC........................................... 82

www.info.hotims.com/61384-79 www.info.hotims.com/61384-100 www.info.hotims.com/61384-84

Merichem Company.....................................40 (88) www.info.hotims.com/61384-88

Paharpur Cooling Towers, Ltd.......................20 (99) www.info.hotims.com/61384-99

Pentair.........................................................12 (152) www.info.hotims.com/61384-152

Company Website

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Plymouth Tube Co....................................... 79 (157) www.info.hotims.com/61384-157

Rezel Catalysts Corp.......................................5 (65) www.info.hotims.com/61384-65

Saint-Gobain NorPro....................................13 (91) www.info.hotims.com/61384-91

Shell Global Solutions International BV......... 24 (92) www.info.hotims.com/61384-92

Spraying Systems Co.....................................18 (67) www.info.hotims.com/61384-67

Tensar International Corporation...................10 (151) www.info.hotims.com/61384-151

Troostwijk Auktionen................................... 39 (155) www.info.hotims.com/61384-155

Veolia Water Technologies........................... 33 (72) www.info.hotims.com/61384-72

Wood Group Mustang....................................6 (78) www.info.hotims.com/61384-78

Zwick Valves................................................ 67 (158) www.info.hotims.com/61384-158

ZymeFlow Decon Technology........................15 (93) www.info.hotims.com/61384-93

This Index and procedure for securing additional information is provided as a service to Hydrocarbon Processing advertisers and a convenience to our readers. Gulf Publishing Company is not responsible for omissions or errors.

Bret Ronk, Vice President Downstream and Midstream Phone/Fax: +1 (713) 520-4421 E-mail: [email protected] www.HydrocarbonProcessing.com SALES OFFICES—NORTH AMERICA IL, LA, MO, OK, TX Josh Mayer Phone: +1 (972) 816-6745, Fax: +1 (972) 767-4442 E-mail: [email protected] AK, AL, AR, AZ, CA, CO, FL, GA, HI, IA, ID, IN, KS, KY, MI, MN, MS, MT, ND, NE, NM, NV, OR, SD, TN, TX, UT, WA, WI, WY, WESTERN CANADA Ryan Akbar Phone/Fax: +1 (713) 520-4449 Mobile: +1 (832) 691-6053 E-mail: [email protected] CT, DC, DE, MA, MD, ME, NC, NH, NJ, NY, OH, PA, RI, SC, VA, VT, WV, EASTERN CANADA Merrie Lynch Phone: +1 (617) 357-8190, Fax: +1 (617) 357-8194 Mobile: +1 (617) 594-4943 E-mail: [email protected] CLASSIFIED SALES Gerry Mayer Phone: +1 (972) 816-3534, Fax: +1 (972) 767-4442 E-mail: [email protected] DATA PRODUCTS J’Nette Davis-Nichols Phone/Fax: +1 (713) 520-4426 E-mail: [email protected]

84 FEBRUARY 2016 | HydrocarbonProcessing.com

SALES OFFICES—EUROPE FRANCE, GREECE, NORTH AFRICA, MIDDLE EAST, SPAIN, PORTUGAL, SOUTHERN BELGIUM, LUXEMBOURG, SWITZERLAND, GERMANY, AUSTRIA, TURKEY Catherine Watkins Phone: +33 (0) 1 30 47 92 51 Fax: +33 (0) 1 30 47 92 40 E-mail: [email protected] Jim Watkins Phone: +33 (0) 1 30 47 92 51 Fax: +33 (0) 1 30 47 92 40 Cell: +33 (0) 6 76 35 11 52 [email protected] ITALY, EASTERN EUROPE Fabio Potestá Mediapoint & Communications SRL Phone: +39 (010) 570-4948 Fax: +39 (010) 553-0088 E-mail: [email protected] RUSSIA/FSU Lilia Fedotova Anik International & Co. Ltd. Phone: +7 (495) 628-10-333 E-mail: [email protected] UNITED KINGDOM/SCANDINAVIA, NORTHERN BELGIUM, THE NETHERLANDS Michael Brown Phone: +44 161 440 0854 Mobile: +44 79866 34646 E-mail: [email protected]

SALES OFFICES—OTHER AREAS CHINA—Hong Kong Iris Yuen Phone: +86 13802701367 (China) Phone: +852 69185500 (Hong Kong) E-mail: [email protected] BRAZIL—Rio de Janeiro Marco Antonio Monteiro Mobile: +55 21 99616-4347 Fax: +55 21 2240-5077 E-mail: [email protected] INDIA Bret Ronk Phone/Fax: +1 (713) 520-4421 E-mail: [email protected] INDONESIA, MALAYSIA, SINGAPORE, THAILAND, AUSTRALIA—Perth Peggy Thay Publicitas Singapore Pte Ltd Phone: +65 6836-2272, Fax: +65 6634-5231 E-mail: [email protected] JAPAN—Tokyo Yoshinori Ikeda Pacific Business Inc. Phone: +81 (3) 3661-6138, Fax: +81 (3) 3661-6139 E-mail: [email protected] KOREA Young-Seoh Chinn JES Media, Inc. Phone: +82 (2) 481-3411/3, Fax: +82 (2) 481-3414 E-mail: [email protected] REPRINTS Rhonda Brown, Foster Printing Service Phone: +1 (866) 879-9144 ext. 194 E-mail: [email protected]

ALISSA LEETON, CONTRIBUTING EDITOR [email protected]

Events FEBRUARY ARC Industry Forum, Feb. 8–11, Renaissance Orlando at SeaWorld, Orlando, Florida P: +1 (781) 471-1175 [email protected] www.arcweb.com/events/ arc-industry-forum-orlando Society of Plastics Engineers (SPE) South Texas Section, Feb. 21–24, International Polyolefins Conference 2016, Hilton Houston North, Houston, Texas P: +1 (713) 829-9226 [email protected] www.spe-stx.org/conference.php IHS Energy CERAWEEK, Feb. 22–26, Hilton Americas, Houston, Texas P: +1 (800) 447-2273 ceraweek.com/2016/

MARCH Energy Construction Forum, March 1–2, Gulf Publishing Company Events, Moody Gardens Convention Center, Galveston, Texas EnergyConstructionForum.com (See box for contact information) Plastic & Rubber Vietnam, March 1–3, Saigon Exhibition and Conference Center (SECC), Ho Chi Minh City, Vietnam P: +65 6233-6638 www.plasticsvietnam.com/en/theexhibition/general-infomation/ Corrosion 2016, March 6–10, Vancouver Convention Centre, Vancouver, British Columbia, Canada P: +1 (800) 797-6223 [email protected] www.nacecorrosion.org/ 3rd World Elastomer Summit, March 9–10, Dusseldorf, Germany P: +48 61 646 7025 [email protected] www.wplgroup.com GLOBALCON Conference and Expo, March 9–10, Hynes Convention Center, Boston, Massachusetts P: +1 (770) 279-4392 www.globalconevent.com/

AFPM Annual Meeting, March 13–15, Hilton, San Francisco, California (See box for contact information) API Spring Committee on Petroleum Measurement Standards Meeting, March 14–18, Hyatt Regency Dallas at Reunion, Dallas, Texas (See box for contact information) CAPE VI, 6th African Petroleum Congress and Exhibition, March 15–17, International Conference Centre, Abuja-Federal Republic of Nigeria P: +44 0-207-700-4949 [email protected] cape-africa.com/ AFPM International Petrochemical Conference, March 20–22, Sheraton Dallas Hotel, Dallas, Texas (See box for contact information) Offshore Technology Conference (OTC) Asia, March 22–25, Kuala Lumpur Convention Center, Kuala Lumpur, Malaysia P: +60 3-2182-3000 [email protected] 2016.otcasia.org/

JUNE

LNG 18, April 11–15, Perth, Western Australia P: +61 2 9265 0700 [email protected] www.lng18.org/index.php Plant Management Institute 2016, April 18–21, Morial Convention Center, New Orleans, Louisiana P: +1 (713) 343-1880 www.electricpowerexpo.com/ SynGas 2016, April 18–21, Tulsa Marriott Southern Hills, Tulsa, Oklahoma P: +1 (225) 922-5000 www.syngasassociation.com International Aboveground Storage Tank Conference and Trade Show, April 20–22, Rosen Shingle Creek Hotel, Orlando, Florida P: +1 (800) 827-3515 [email protected] www.NISTM.org

MAY

APRIL

Offshore Technology Conference (OTC), May 2–5, NRG Park, Houston, Texas P: +1 (972) 952-9494 2016.otcnet.org/

Tube Dusseldorf, April 4–8, Fair ground Dusseldorf, Dusseldorf, Germany P: +49 0-211-45-6001 [email protected] www.tube-tradefair.com/

4th Annual Canada LNG Export Conference and Exhibition, May 10–12, Vancouver, British Columbia, Canada P: +44 (0) 203 772 6022 www.canadalngexport.com/

CCPS 12th Global Congress on Process Safety, April 10–13, Hilton Americas and George R. Brown Convention Center, Houston, Texas P: +1 646-495-1371 [email protected] www.aiche.org/ccps/conferences/ global-congress-on-processsafety/2016

Managing Aging Plants Conference and Expo Japan 2016, May 31–June 1, International Conference Hall (Kokusai Kaigijo), Waseda University in Tokyo P: +31-575-789-260 [email protected] www.plantenmei.com

GPA Convention, April 10–13, Hilton New Orleans Riverside, New Orleans, Louisiana gpaconvention.org/ Kuwait Oil and Gas, April 11–12, Jumeirah Messilah Beach Hotel, Kuwait P: +44 20-7978-0029 [email protected] www.cwckuwait.com/

AFPM Reliability and Maintenance Conference, May 24–27, San Antonio, Texas (See box for contact information) International Liquid Terminal Associate (ILTA), May 23–25, 36th Annual International Operating Conference and Trade Show, George R. Brown Convention Center, Houston, Texas P: 703-875-2011 www.ilta.org

ASME Turbo Expo, June 13–17, COEX Convention and Exhibition Center, Seoul, South Korea P: 82-2-6000 1122 [email protected] www.coex.co.kr/eng Global Petroleum Show, June 7–9, Stampede Park, Calgary, Alberta, Canada P: 403-209-3555 [email protected] www.globalpetroleumshow.com

JULY ARC Industry Forum 2016 India, July 7–8, Le Meridien Bangalore, Bangalore, Kamataka, India P: +91 80 2554 7114 [email protected] www.arcweb.com/events/arcindustry-forum-india ARC Industry Forum 2016 Japan, July 12, KFC Hall, Sumida-ku, Tokyo, Japan P: +81-42 991 1685 [email protected] www.arcweb.com/events/ arc-industry-forum-japan

AUGUST ONS 2016, Aug. 29–Sept. 1, Stavanger, Norway P: +47-51-84-90-40 [email protected] www.ons.no/2016/ Hydrocarbon Processing/ Gulf Publishing Company Events P: +1 (713) 520-4475 [email protected] [email protected] American Fuel & Petrochemical Manufacturers (AFPM) P: +1 (202) 457-0480 [email protected] www.afpm.org/Conferences American Petroleum Institute (API) P: +1 (202) 682-8195 [email protected] www.api.org

Hydrocarbon Processing | FEBRUARY 2016 85

MIKE RHODES, MANAGING EDITOR [email protected]

People

Smaller-scale gas-toliquids (GTL) specialist Velocys Plc has named David Pummell as chief executive officer (CEO). Mr. Pummell joins Velocys from ACAL Energy Ltd., a private equity-backed fuel cell technology company, where he was CEO. Prior to this, he was CEO of MAPS Technology Ltd., before becoming CEO of Ceres Power Group plc. He began his career at BP as a chemical engineer and held a number of executive positions across the downstream business during his 22-year tenure. Marathon Petroleum Corp. (MPC) has made changes to the company’s senior management structure. Donald C. Templin, executive vice president of supply, transportation and marketing, has been named president of MPLX LP, a fee-based, growth-oriented master limited partnership (MLP) formed by MPC in 2012. Mr. Templin will remain an executive vice president of MPC. Pamela K. M. Beall, MPC’s senior vice president of corporate planning, government and public affairs, will become executive vice president of corporate planning and strategy at MPLX. She will report to Mr. Templin. David L. Whikehart, director of product supply and optimization, has been named vice president of corporate planning, government and public affairs, succeeding Ms. Beall.

The Fluid Sealing Association (FSA) has named Carl Jones to its board of directors. He currently serves as the global product specialist for Packing Fibers Sealant Technologies at materials technology company W.L. Gore & Associates. As a long-standing member of the FSA, Mr. Jones is the technical committee chair for the compression packing division. He has 30 years of experience in the fluid sealing industry, including experience in applications engineering, territory and capital project sales, business development, strategic project marketing, and regional and global product management with profit and loss responsibilities. Founded in 1933, the FSA is an international trade association, and member companies are involved in the production and marketing of fluid sealing devices. Erik Olsson has assumed his duties as the president of the management consulting business group and as a member of the group executive committee of Pöyry PLC. He will report to Martin à Porta, the president and CEO of Pöyry PLC. Previously, Mr. Olsson served as the senior vice president of the company’s business development group. He has succeeded Jarkko Sairanen, who has left the company, in these positions.

86 FEBRUARY 2016 | HydrocarbonProcessing.com

Ross Glendinning has been appointed as senior vice president of the service division of Alfa Laval Inc. His responsibilities include leading parts sales, reconditioning services, field services and technical support activities, as well as driving consistent growth and developing new sales opportunities for the company’s service business in the US. Mr. Glendinning joined Alfa Laval in 1982 as a marine engineer for the military products group. He has held positions in regional and national service, global business development, as well as capital equipment marketing and sales management. He was most recently responsible for Alfa Laval’s services for the industrial process markets. Mr. Glendinning is based at the Alfa Laval facility in Warminster, Pennsylvania. The supervisory board at Poland’s dominant gas firm PGNiG has called former economy minister Piotr Wozniak to assume the duties of acting CEO for the state-run company. He will replace CEO Mariusz Zawisza. Two deputy chairmen, Zbigniew Skrzypkiewicz and Jaroslaw Bauc, Poland’s former finance minister, have also left the supervisory board. The changes at PGNiG are part of the wider reshuffle in state-run companies after the recent presidential and general elections.

The Sasol Ltd. board of directors has appointed Bongani Nqwababa and Stephen Russell Cornell as joint presidents and CEOs of the company, with effect from July 2016. Mr. Nqwababa, who served previously as non-executive director, is currently the chief financial officer (CFO) and a member of the board of directors and the group executive committee. Mr. Cornell is currently the executive vice president of international operations, and a member of the group executive committee. He is responsible for Sasol’s global operations outside Southern Africa, as well as for fulfilling his role of executive sponsor for the Lake Charles Chemicals Project in Louisiana in the US. The board also appointed Paul Victor as CFO and executive director, following his current role as senior vice president of financial control services and acting CFO. Bert Lederer will retire from Teknor Apex Co. after 40 years with the company. He had been working for Olin Corp. as PVC compounds product manager at a PVC resin plant in Massachusetts when he joined Teknor in 1975. He earned an engineering degree from Tufts University and an MBA degree from Boston University before beginning his professional career.

Darren W. Woods has been elected president of Exxon Mobil Corp. and a member of the board of directors. He joined Exxon Co. Intl. in 1992 as a planning analyst and has since held a number of assignments, including as vice president of supply and transportation, and director of refining for Europe, Africa and the Middle East for ExxonMobil Refining & Supply Co. In 2012, Mr. Woods was appointed as president of ExxonMobil Refining & Supply Co. and as a vice president of the corporation. He also served as vice president of ExxonMobil Chemical Co. and as the manager of investor relations for Exxon Mobil Corp. Rex W. Tillerson will continue in his position of chairman of the board and CEO of the corporation. City Technology, a part of Honeywell, has made two appointments. Marco Di Nubila has been named as global marketing leader, where his primary focus will be further developing opportunities presented by new and intelligent sensing technologies, industrial edge devices and the Internet of Things (IoT). Theresa Berry will join the company as product manager, where her primary focus will be managing the development of key new product innovations. She recently served as product manager for sensors for Tyco Fire Protection Products.

MARCH 1–2, 2016

Moody Gardens Convention Center Galveston, Texas EnergyConstructionForum.com

North America’s Leading Energy Construction Expo + Forum

Join us at this Must Attend Event for Energy Construction Professionals With $500 Billion + in North American Energy Construction projects announced, you can’t afford to miss this opportunity to stay abreast of the latest opportunities and solutions that will help you deliver capital projects successfully and safely! Presently, Hydrocarbon Processing’s Construction Boxscore Database is tracking nearly $350B in active projects in the US with another $150B in projects elsewhere in North America. As investments continue to rise, a number of opportunities and challenges are presented. The second annual Energy Construction Forum (ECF) will address the specific needs of the midstream and downstream energy construction industry. The conference program will explore:

Featuring Keynote:

STEPHEN MULVA Director

• The critical factors that support project success + how to avoid project failures • Project execution risk and how it can be abated in this environment • The major causes of cost overrun in megaprojects • The implications of low oil prices on North American crude price differentials + the impact on refiners and refining investments • How to boost project compliance + efficiency

Hosted by:

• and much more

Esteemed Speakers Include Major Project Leaders and Industry Experts from: • Sasol

• Wood Mackenzie

• CLMA

• Pathfinder LLC

• Wood Group Mustang

• Endeavor Management

• JV Driver Group

• IHI E&C

• S & B Engineers and Constructors, Ltd

• Construction Boxscore Database

Register online: EnergyConstructionForum.com For questions or to register offline, please contact Megan Roiz, Events Program Manager at [email protected] or +1 (713) 520-4402. Sponsored by:

GEMAIN Earned Value Management System

Organized by:

Your objectives in focus Make the most of today’s and tomorrow’s challenges with leading-edge solutions from Axens - Clean and alternative fuel technologies - Petrochemicals - Energy efficiency - High performance catalysts & adsorbents - Revamps

Single source technology and service provider ISO 9001 – ISO 14001 – OHSAS 18001 www.axens.net Select 53 at www.HydrocarbonProcessing.com/RS

Technology and Business Information for the Global Gas Processing Industry

GasProcessingNews.com | JANUARY/FEBRUARY 2016

PIPELINES, TERMINALS

AND STORAGE EMISSIONS COMPLIANCE Automate data integration to meet GHG regulations for gas gathering lines

PLANT DESIGN

Meet design challenges for knockout drums with advanced simulation tools

TOP GAS PROCESSORS IN NORTH AMERICA Processors continue to consolidate amid contract renegotiations

Special Supplement to

CONTENTS

EDITORIAL COMMENT In the US, LNG export terminal operators are gearing up to send liquefied natural gas to world markets. As of the time of writing, Cheniere Energy was due to ship out its first tanker of liquefied Texas shale gas by early March. A flurry of other terminals is scheduled to follow suit. The US exports will contribute to a predicted tripling of global LNG supply ADRIENNE BLUME, by 2020 amid a wave of new production Editor from the US, Australia, and Asia-Pacific. The new suppliers are highly visible entities, with their multibillion-dollar liquefaction projects that will source natural gas from shale formations, coal seams and conventional gas deposits. But where will the gas go once it is liquefied? Many of the US export projects had focused on Asia as a destination market when gas prices were high and demand was raging. However, with the slowing of demand from Asia and the worldwide dive in commodities prices, exporters’ attention has now shifted to Europe. Europe’s energy security comes largely from diversity of supply, particularly in light of its repeated disagreements with major gas supplier Russia. However, Europe has also been serving as a dumping ground for re-exports of Australian LNG cargoes from Asia, indicating that Europe will continue to be oversupplied with gas through 2016. Luckily for US exporters, Europe has both the import infrastructure and trading clout to absorb most of the additional supplies. GP

www.GasProcessingNews.com

P. O. Box 2608 Houston, Texas 77252-2608, USA Phone: +1 (713) 529-4301 Fax: +1 (713) 520-4433 [email protected]

PUBLISHER

Bret Ronk [email protected]

EDITORIAL

Editor Adrienne Blume Editor/Associate Publisher, Hydrocarbon Processing Lee Nichols

MAGAZINE PRODUCTION

Vice President, Production Manager, Editorial Production Artist/Illustrator Senior Graphic Designer Manager, Advertising Production

Sheryl Stone Angela Bathe Dietrich David Weeks Amanda McLendon-Bass Cheryl Willis

ADVERTISING SALES See Sales Offices, page 34.

Copyright © 2016 by Gulf Publishing Company. All rights reserved.

EUROMONEY INSTITUTIONAL INVESTOR PLC Chairman: Andrew Rashbass Directors: Sir Patrick Sergeant, The Viscount Rothermere, Christopher Fordham (managing director), Neil Osborn, John Botts, Colin Jones, Diane Alfano, Jane Wilkinson, Martin Morgan, David Pritchard, Bashar AL-Rehany, Andrew Ballingal, Tristan Hillgarth Part of Euromoney Institutional Investor PLC. Other energy group titles include: Hydrocarbon Processing, World Oil and Petroleum Economist

GasProcessingNews.com | JANUARY/FEBRUARY 2016

29

SPECIAL REPORT: PIPELINES, TERMINALS AND STORAGE Meet Subpart W emissions compliance with automated data integration

13

H. Qin

Minimize evaporation losses by calculating boiloff gas in LPG storage tanks

17

S. Shiva Shamekhi and N. Ashouri

PLANT DESIGN Ef�iciently design and operate vertical gas/liquid separators

21

J. Valappil and P. Diwakar

TOP GAS PROCESSORS IN NORTH AMERICA 29

North America’s top gas processors consolidate in 2015 J. Stell

DEPARTMENTS Gas Processing News .......................................................... 4 US Industry Metrics ............................................................. 8 New in Gas Processing Technology ................................ 33

COLUMNS Boxscore Construction Analysis ........................................ 9 Turkmenistan looks to expand influence in EU gas market

Executive Q&A Viewpoint ..................................................11 CEO forecasts ‘next decade’ of LNG industry President/CEO Vice President, Downstream and Midstream Vice President Vice President, Production Business Finance Manager

John Royall Bret Ronk Ron Higgins Sheryl Stone Pamela Harvey

Cover Image: NextDecade LLC’s Rio Grande LNG project in Texas will include six trains. Each train will have a nameplate capacity of 4.5 MMtpy, for a full buildout scenario of 27 MMtpy.

GAS PROCESSING NEWS A. BLUME, Editor

Modularized offering for smaller-scale LNG

Kiewit Energy Co. and Air Products have agreed to collaborate on small-scale LNG projects in North America to meet growing demand for LNG production. The collaboration provides customers with easy availability and rapid response for the design, construction and commissioning of projects. The modularized design and technology offered by Kiewit Energy and Air Products can be used on projects that produce up to 500 Mgpd of LNG. Through a unified approach, Kiewit Energy is responsible for project management, overall engineering and design, construction and commissioning, while Air Products leads the design and supply of the liquefaction equipment. This collaborative approach helps ensure that projects meet cost and schedule requirements. Kiewit Energy and Air Products entered into a formal agreement to solidify the alliance in October 2015. At present, the two companies are working together on an LNG export terminal and a peakshaving facility in the US.

Ichthys field gets safety systems The Ichthys field was the largest discovery of hydrocarbon liquids in Australia in more than 40 years, and the Ichthys LNG project ranks among the largest energy projects in the world. Operated by INPEX, the Ichthys LNG project includes some of the world’s biggest offshore facilities, massive onshore processing facilities near Darwin in Australia’s Northern Territory, and an 890-km pipeline to unite them. HIMA was selected by the Ichthys JV to supply safety instrumented systems (SISs) and the fire and gas system (FGS). The Ichthys LNG project consists of an onshore LNG plant; a central processing facility; and a floating production, storage and offloading vessel. The total order value is the largest that HIMA has ever received for a single project. Once operational, the Ichthys LNG project is expected to produce 8.9 MMt of LNG and 1.6 MMtpy of LPG, along with approximately 100 MMbpd of condensate, at peak. The SISs and FGS are supplied using HIMax, the first safety system designed to provide uninterrupted system operation throughout the entire life of the plant, while maximizing plant availability, productivity and safety. SISs and FGS using the HIMax safety system hardware meet the requirements in accordance with AS/ IEC 62061 and IEC 61326-3-1 (DIS). The high-integrity pressure protection systems (HIPPSs) rely on a Planar4 system, which meets the highest safety standards and can be used up to Safety Integrity Level (SIL) 4, in accordance with IEC 61508. Onshore and offshore facilities and the pipeline are connected to around 25,000 safety input/output points, allocated in approximately 430 cabinets distributed via HIMA safeethernet technology, where applicable. Besides the SIS/FGS/HIPPS, the HIMA scope of supply includes delivery of the pre-final-investmentdecision system development and standard application design and testing. The cybersecurity and network management with related hardware installation, the addressable fire system for the living quarters with the related detectors, and the network management system for the SIS/FGS network complete the deliverables. The HIMA hardware and firmware provided are certified up to SIL 3, according to AS/IEC 61508. HIMA will use the principles of AS/IEC 61511 in designing and testing the SISs and FGS. The functional safety management (FSM) plan will be used to manage all stages of the design, implementation and manufacturing processes.

Gas turbine market forecast at $100 B Worldwide installations of new gas turbines will average 74,000 MW/yr over the next five years, according to a report by McIlvaine Co. The system sales revenue will be $75 B/yr. GE, Siemens and other turbine vendors will generate revenues of $20 B/yr for the turbine equipment. Worldwide installed gas turbine capacity is 1.5 MM MW. Purchases of repair parts consumables and upgrades at existing power plants is expected to average $30 B/yr. Part of this investment will be a result of greenhouse gas initiatives. The least expensive way to reduce carbon footprint is to make the existing gas turbine more efficient. Adding the steam cycle makes the biggest difference, but there are other options available. Inlet filter replacement for existing units is seen at more than $500 MM/yr. Another $460 MM/yr will be spent for SCR systems and catalyst. Additionally, McIlvaine Co. expects the market for replacement parts for pumps and valves to be significant.

Automation for Finland’s first LNG import terminal Honeywell will provide its Experion Process Knowledge System (PKS) automation controls and tank gauging systems for Finland’s first LNG import terminal to efficiently supply natural gas to marine vessels and industrial facilities in Finland, helping replace other fuels that have higher emissions. The cleaner-burning natural gas will help these vessels and facilities meet emissions regulations in the Baltic and Nordic seas. Additionally, Honeywell’s Enterprise Buildings Integrator (EBI) will connect and power comfort, safety and security systems within the terminal itself, creating a productive environment for workers. With tight integration between Experion PKS and EBI, operators will have one interface to access and manage all process and facility technology, which improves sitewide visibility and efficiency. The Pori LNG terminal will have a capacity of 30,000 m3 and will be completed in the second half of 2016. Honeywell’s tank-gauging systems will be used on tanks provided through Spanish engineering company FCC Industrial e Infraestructuras Energéticas SAU.

4 JANUARY/FEBRUARY 2016 | GasProcessingNews.com

BG takes equity in Aphrodite discovery

BG Group has secured a 35% holding in Block 12 offshore Cyprus, which includes the Aphrodite gas discovery. This upstream position provides a potential source of gas to Egypt, where BG Group holds equity in the two-train LNG export facility at Idku, as well as LNG offtake rights to lift 3.6 MMtpy. Operated by Noble Energy, the Aphrodite gas discovery is located approximately 170 km south of Limassol. Completion of the transaction is subject to regulatory approvals and closing conditions.

GAS PROCESSING NEWS A. BLUME, Editor

GE signs expanded contract with Cheniere GE Oil & Gas has signed a $610-MM agreement with Corpus Christi Liquefaction LLC, a subsidiary of Cheniere Energy Inc., to provide spare parts and planned inspections, maintenance services and around-the-clock technical support for the gas turbines and refrigerant compressors on the first two LNG trains under construction at Cheniere’s LNG export facility in Corpus Christi, Texas. Each train will have six gas turbines and is expected to have nominal capacity to produce up to 4.5 metric MMtpy of LNG. The contract—the second for both companies—serves as a model for large infrastructure projects in terms of efficiency, cost savings and facility reliability. Construction of GE equipment onsite will start in January 2017, with LNG production scheduled to commence as early as 2018. The new contract, which covers 20+ years, incorporates all major maintenance for the LNG trains, including parts, repairs and field services. In addition, GE will provide a resident technical support team at Cheniere’s facility to assist with all aspects of maintenance of GE equipment and include a remote monitoring system for the equipment. Cheniere will benefit from access to OEM parts and repairs, plus technical expertise of GE field engineers and technology—all of which will ensure optimal reliability. GE Oil & Gas and Cheniere also have announced a similar, $1-B maintenance agreement for the Sabine Pass facility in December 2014. Cheniere is developing the liquefaction project in Corpus Christi with anticipated aggregate capacity of up to 22.5 MMtpy over five trains. The IEA forecasts global demand to reaccelerate and grow at an average rate of 2% through 2020, with an average annual increase of 10% projected throughout the rest of the decade. Demand for European LNG imports is projected to roughly double in that time period.

Brazilian pipeline center tests pigging The Brazilian Pipeline Technology Center (CTDUT), located in Rio de Janeiro near the Duque de Caxias Refinery, was chosen by Shell in Houston, Texas, to develop tests and research on pipeline pigging. Shell’s engineers are trying to develop reliable mathematical models for bypass pig operations for cleaning pipelines under single-phase (water) and two-phase (water and air) flow. The work began about two years ago in Houston when Shell, in a partnership with a local company, developed a special “capsule” sensor that is attached to the pig body and that records pressure and temperature data on board. In addition, Shell acquired a Rosen Technologies pipeline data logger to record pressure, differential pressure (upstream and downstream of the pig), temperature and data from a navigation system for the local coordinates, while the pig travels along the pipeline. These devices permit the diagnosis of internal conditions. According to a CTDUT research engineer, the main challenge of the process is to discover the best combination of the pig disks and the orifice diameters for controlling the flowrate through the bypass. The disk diameters are usually a little larger than the inside diameter of the pipeline, which basically controls the wax rate of cleaning. On the other hand, the control of the flowrate through the bypass is critical since it has an important role on the resulting force that pushes the pig through the pipeline. Therefore, choosing the right cross-sectional area of the bypass orifices is critical to achieving a good result. Too much bypass may cause the pig to stall, while not enough bypass may cause wax (or other solids) to plug the line. Since the installation is flexible in its general configuration, a 2.5-m transparent section was installed by Shell so that its tests could be analyzed and filmed during the pig passage. In the two-month period, more than 200 tests were made. At present, CTDUT is in the process of installing a new control and automation system for this loop, which will allow the complete automatic control of conditions, such as pressures, temperature, flowrate and pig-position monitoring along the entire pipeline. This will also allow for the preparation of quick reports and the analysis of large data sets generated by the system sensors.

6 JANUARY/FEBRUARY 2016 | GasProcessingNews.com

Qatar to supply additional LNG to India RasGas Company Ltd. of Qatar and Petronet LNG Ltd. of India have entered into a binding salesand-purchase agreement (SPA) for the supply of an additional 1 MMtpy of LNG to India. Deliveries will begin in 2016 to four Indian entities: Indian Oil Corp. Ltd., Bharat Petroleum Corp. Ltd., GAIL (India) Ltd. and Gujarat State Petroleum Corp. RasGas and Petronet LNG have also entered into a binding agreement to adjust some aspects of their existing long-term LNG SPA of 7.5 MMtpy, signed by the parties in 1999, which laid the foundation for the LNG business in India. Such adjustments will protect and preserve the overall value of the contract. As per the agreement, LNG volumes that were not taken by Petronet from RasGas during 2015 will be taken and paid for by Petronet during the remaining term of the SPA, maintaining its current level of oil indexation with the oil index more closely reflecting the prevailing oil prices. RasGas is a main supplier of LNG to India and has been supplying Petronet since 2004.

First gas flows from Corrib field in Ireland

Natural gas has started to flow from Shell’s Corrib gas field, marking an important milestone for Ireland and for Shell’s upstream operations. Located 83 km off Ireland’s northwest coast in water depths of almost 350 m, the Corrib gas field lies approximately 3,000 m below the seabed. At peak annual output, the Corrib gas field is expected to produce around 260 MMscfd of gas, or 45 Mboed. Corrib has the potential to meet up to 60% of Ireland’s gas needs. Six wells have been drilled at the Corrib field, with gas transported to the Bellanaboy Bridge Gas Terminal in northwest Mayo through a 20-in. pipeline. The gas is processed at Bellanaboy before it is transferred into the Gas Networks Ireland (GNI) network, which delivers it to Irish gas consumers. The Corrib project is a JV between Shell E&P Ireland Ltd. (45%), Statoil Exploration Ireland Ltd. (36.5%) and Vermilion Energy Ireland Ltd. (18.5%). Shell E&P Ireland Ltd. is the project’s operator.

Golar gets financing for FSRU Golar LNG Ltd. has received an underwritten financing commitment for the newbuild FSRU Golar Tundra. China Merchants Bank Leasing will fund the vessel on a charter-free basis, based on its current cost of up to $216 MM. The facility also provides for Golar Tundra’s eventual sale to Golar LNG Partners LP. On the charter-free basis, the facility will finance a minimum of $50 MM more than the final delivery payment to the shipyard, thereby releasing the additional cash to Golar. As part of the financing commitment, China Merchants Bank Leasing will provide a parallel facility to refinance the Golar-owned FSRU Golar Eskimo. Upon drawdown, this new facility will refinance the vessel’s $156 MM debt and provide approximately $100 MM of additional financing.

GLOBAL SPENDING TO REACH NEARLY $340 BILLION IN 2016. Find out how, where and why.

HPI Market Data 2016 is the hydrocarbon processing industry’s most trusted forecast of capital, maintenance and operating expenditures for the petrochemical, refining and natural gas/LNG industries. Produced annually by the editors of Hydrocarbon Processing and the Construction Boxscore Database, and featuring data provided by governments and private organizations, this comprehensive resource provides comprehensive and top-level insight into HPI market trends, spending and activity.

HPI Market Data 2016 features: • Global spending in the refining, petrochemical and gas processing sectors • Capital, maintenance and operating spending broken out by region • Short-term and long-term implications of today’s low crude oil prices • An exploration of changing markets and demand within the global HPI, with discussion of emerging markets • More than 55 tables and 100 figures, including information and data collected from governments and private organizations • Editorial analysis of worldwide economic, social and political trends driving HPI activity across all sectors

Highlights include: • The HPI’s capital, maintenance and operating budget for 2016 and a year-over-year comparison against 2015 • Expanded section on global construction and investment • Impact of current crude oil prices on global project spending • How refineries will be designed to handle unconventional feedstocks, such as NGLs, bitumen, heavy oil, and shale

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HPI MARKET DATA 2016

US INDUSTRY METRICS

A. BLUME, Managing Editor

US natural gas spot prices at Henry Hub and NGL spot prices at Mont Belvieu, $/MMBtu 25

July 2015

Oct. 2015

3 Monthly price (Henry Hub) 12-month price avg. Production

20 0

D J F M A M J J A S O N D J F M A M J J A S O N D 2013 2014 2015

2 1 0

Gas prices, $/Mcf

4

40

120

5

April 2015

5

60

US natural gas plant field production of NGL, LPG, ethane/ethylene and propane/propylene, Mbpd

10

0 Jan. 2015

6

80

US gas plant field production, Mbpd

$/MMBtu

15

7

Production equals US marketed production, wet gas. Source: EIA.

Natural gasoline Isobutane Butane NGPL composite Propane Ethane Natural gas spot prices (Henry Hub)

20

US gas production (Bcfd) and prices ($/Mcf) 100 Production, Bcfd

In the US, Henry Hub natural gas spot prices continued their extended decline through the turn of 2016, but were seen picking back up slightly in early January as residential and commercial gas consumption increased with the onset of lower temperatures in some regions. Despite the colder weather in parts of the US, storage withdrawals were lower on the year as of early January, keeping inventories well-maintained. Spot prices for NGL dropped sharply in early January as production of NGL remained strong. As of October 2016, production of NGL, LPG, ethane/ ethylene and propane/propylene had reached new highs. GP

Jan. 2016

100 80 LPG NGL Ethane/ethylene Propane/propylene

60 40 20

Oct.- Nov.- Dec.- Jan.- Feb.- Mar.- April- May- June- July- Aug.- Sept.- Oct.2014 2014 2014 2015 2015 2015 2015 2015 2015 2015 2015 2015 2015 Source: US EIA

Source: US EIA

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BOXSCORE CONSTRUCTION ANALYSIS

Turkmenistan looks to expand influence in EU gas market EUGENE GERDEN, Contributing Writer

Turkmenistan, located in Central Asia on the Caspian Sea, plans to significantly increase its presence in the global gas market. The country has the fourth-largest natural gas reserves in the world; however, to date, its presence in the global gas industry has been limited. This situation may change in the coming years, as the country has already started to create conditions for a significant increase in gas exports. New pipelines to offer wider export reach. According to Turkmenistan’s Ministry of Oil and Mineral Resources, the country recently completed construction of the 1,000-km East-West gas pipeline (FIG. 1). The new gas pipeline connects the country’s main gas fields into a single gas transportation system and significantly increases its export capacity. In addition, it would become part of the pipeline system for deliveries of Turkmen gas to Europe. The official launch of the new East-West pipeline in December 2015 is expected to help Turkmenistan provide additional guarantees for stable exports of its gas to global markets. According to an official spokesperson of the Turkmen Ministry of Oil and Mineral Resources, the construction of the East-West pipeline will allow Turkmenistan to pump up to 30 Bcm of gas from the country’s largest gas fields, located in the eastern part of the country, to states bordering the Caspian Sea on the west. According to the original plan, the new pipeline was to become part of the Nabucco project; however, due to its suspension, the Turkmen government decided to complete construction of the pipeline with its own resources. At present, Caspian states continue development of infrastructure for exports of Caspian gas to Europe. Part of this involves the expansion of the South Caucasus gas pipeline, as well as the ongoing construction of the Trans-Anatolian Pipeline (TANAP) and the Trans-Adriatic Pipeline (TAP). By 2020, these pipelines will be able to carry large volumes of gas, primarily from Azerbaijan and Turkmenistan, with the aim of further exports to the EU. According to recent statements by Maroš Šefčovič, vice president of the European Commission for the European Energy Union, the EU expects to receive Turkmen gas by 2019. The EU has long planned to diversify its gas supplies and reduce its energy dependence on Russia. At present, the European Commission is considering Turkmenistan and Azerbaijan as potential partners for the launch of regular gas supplies to the EU. According to Mikhail Korchemkin, head of research firm East European Gas Analysis, Russia has become an unreliable gas supply partner to the EU in recent years, and the management

of Gazprom has threatened to significantly reduce gas exports to the EU, in favor of sending them to Asia-Pacific countries. Prior to 1997, Russia was the only buyer of Turkmen gas, and supplies took place through the Russian Central Asia–Center (CAC) pipeline. However, several years later, the Turkmen government was able to launch the first Turkmen-Iranian pipeline, with annual gas capacity of 8 Bcmy, and, in 2010, another pipeline to Iran was established with a capacity of 12.5 Bcmy. In 2009, Turkmenistan started sales of its gas to China, as a result of the signing of a 30-year contract for 30 Bcmy of gas through the Central Asia–China pipeline system. This system, which takes gas from Kazakhstan to China and also has a leg into Turkmenistan through Uzbekistan, was completed in 2010. By 2030, the government of Turkmenistan plans to increase gas production to 230 Bcm. Further development of the country’s large Galkynysh gas field and planned development of another 30 gas fields, as per statements from Ashirguly Begliev, chairman of Turkmengaz, will help meet this goal. According to plans of the Turkmen government, gas production at the Galkynysh field is expected to reach 93 Bcmy by 2016, and total gas exports from the country should reach 180 Bcm by 2018. As part of these targets, Turkmengaz has started preparations for the expansion of the D section of the Turkmenistan–China pipeline, which will raise that section’s total capacity to approximately 30 Bcmy of gas. Analysts believe that Turkmenistan has a good chance of implementing these plans, taking into account the country’s huge gas reserves. According to data from the British consultKazakhstan Uzbekistan

Shatlyk

Turkmenistan East-West pipeline route

Caspian Sea

Ashgabat Belek

Iran Afghanistan FIG. 1. Turkmengaz’s East-West pipeline route from Shatlyk to Belek. Gas Processing | JANUARY/FEBRUARY 20169

BOXSCORE CONSTRUCTION ANALYSIS

FIG. 2. The official launch of the construction of the TAPI pipeline.

Kazakhstan Kyrgyzstan Caspian Sea

Turkmenistan

Uzbekistan

Tajikistan

Ashgabat

China

Farkhor Kabul

Afghanistan Iran

Kandahar

Islamabad

India

Pakistan New Delhi

FIG. 3. Planned route of the TAPI pipeline.

ing firm Gaffney, Cline and Associates, Turkmenistan’s total gas reserves are estimated at 27.4 Tcm. In 2014, the total volume of natural gas produced in Turkmenistan amounted to more than 76 Bcm, of which 45 Bcm were exported abroad. China remains the main buyer of Turkmen gas; however, according to Turkmen government plans, this situation will change in the near future, amid EU attempts to significantly reduce dependence on Russian gas. In the meantime, analysts believe that Turkmen gas shipments to Europe will result in tightening market competition, although this will not be associated with any radical changes in the market. Turkmenistan is in need of new markets for its gas. In 2015, Russia imported only 4 Bcm of Turkmen gas, and no information is available on Russia’s plan to purchase gas from Turkmenistan in 2016. Turkmenistan has now pinned its hopes on the Turkmenistan-Afghanistan-Pakistan-India (TAPI) gas pipeline, which broke ground on December 13, 2015 (FIG. 2). This pipeline would bring Turkmen gas to the vast and promising markets of Pakistan, India and Southeast Asia over the long term (FIG. 3). However, implementation of these plans may encounter some difficulties, the most important of which is an ongoing conflict between Turkmenistan and Azerbaijan for the ownership of a number of gas fields on the Caspian shelf. The two sides continue to discuss the legal status of the Kapaz field, which is one of the largest gas fields on the Caspian shelf. Azerbaijan has already started development of the field, despite fierce protests from Turkmenistan. Planned LNG projects will supply EU. At the same time as it aspires to boost its traditional natural gas exports, Turkmeni10JANUARY/FEBRUARY 2016 | GasProcessingNews.com

stan hopes to increase LNG exports abroad, including to EU countries. These plans include building an LNG terminal at the Caspian Sea for transport of Turkmen LNG by sea to Lithuania and other countries. The possibility of LNG exports from Turkmenistan has been confirmed by Algirdas Butkevičius, prime minister of Lithuania. The government of Lithuania has already conducted talks for the project with the Turkmen government. It is possible that the LNG terminal could be completed by 2018. The supplies would be sent through the territories of Azerbaijan and Georgia to the Romanian seaport of Constanta, and then transported by LNG tankers throughout Europe. Turkmenistan already operates two LNG terminals, both of which source gas from the country’s Naip and Bagaja gas fields. In 2009, the country completed construction of the first Turkmen marine LNG terminal on the coast of the Caspian Sea at the port of Kiyanly. Its design capacity is 200 metric Mtpy of LNG, with the possibility of a significant increase over the next several years. According to the Turkmen government’s plans, by 2030, the volume of LNG production in the country should increase by up to 3 metric MMt. This increase will be achieved through the construction of new LNG plants in other parts of the country. Implementation of these plans will take place as part of the official state program to develop the domestic oil and gas industry through 2030. To date, among the major importers of Turkmen LNG are such countries as Iran, Afghanistan and Japan; however, the geography of supplies should significantly expand during the next several years, according to the government’s vision. Sergey Pikin, director of the Russian Energy Development Fund, commented on Turkmenistan’s energy development plans: “Despite the fact that LNG infrastructure is more expensive than pipelines, one of the main advantages of LNG, compared to traditional gas, is the possibility of its supplies without any territorial restrictions and limitations. In the case of building necessary infrastructure, Turkmenistan will be able to supply gas to those countries that can offer higher prices for its gas, and, in particular, the EU states. The Turkmen government is aware of this and no longer plans to focus on the supplies of traditional gas to China and Russia, as it did in the past.” While simultaneously catering to gas-hungry EU nations, Turkmenistan aims to create conditions to attract Western investors to produce gas within its territory. To date, Italy’s eni has expressed interest in developing Caspian Sea blocks. The company plans to explore the 19th and 20th blocks of the Turkmenistan shelf, with the volume of reserves pegged at more than 500 MMt of oil and 630 Bcm of natural gas. According to sources in the Turkmen government, negotiations are underway with other Western investors for the development of additional blocks. GP EUGENE GERDEN is an international contributing writer specializing in the global oil refining and gas industry. He has been published in a number of prominent industry titles.

EXECUTIVE Q&A VIEWPOINT

CEO forecasts ‘next decade’ of LNG industry

KATHLEEN EISBRENNER, Founder, Chairman and Chief Executive, NextDecade LLC

KATHLEEN EISBRENNER is founder, chairman and chief executive of NextDecade LLC, a company positioned to create innovative opportunities in the US and international natural gas industry. Previously, Ms. Eisbrenner served as executive vice president for Royal Dutch Shell, where she was responsible for Shell’s global LNG strategy and LNG trading business. Prior to Shell, Ms. Eisbrenner served as the chief executive and founder of Excelerate Energy, an LNG importer and marketer. At present, she is a member of the US National Petroleum Council and the American Bureau of Shipping. Ms. Eisbrenner has also served as a board member of Chesapeake Energy Corp. She holds a BS degree in civil engineering from the University of Notre Dame in Indiana, and resides in Texas.

During the past decade, strong economic growth in the Asia-Pacific region—particularly China, Japan and India—has stimulated increased energy demand. In this decade, from 2010– 2020, natural gas is gaining on coal’s market share as a preferred form of energy. The world is seeking clean, abundant and economic power sources. During the next decade, between 2020 and 2030, the US is anticipated to satisfy its own gas requirements with the emergence of game-changing domestic gas reserves. These supplies will enable the nation to compete with top LNG-exporting countries, such as Qatar and Australia, throughout the global gas markets. Energy companies have proposed a plethora of new LNG projects to export gas from the US, to take advantage of world markets that are eager for low-cost fuel. Of these jump-starters, NextDecade is well positioned to create, develop and operate two significant LNG facilities to serve various international markets. GP talks with Kathleen Eisbrenner, founder, chairman and chief executive of NextDecade LLC, about the company’s formation, project statuses and envisioned future in the LNG market. GP. How was NextDecade formed, and why?

Eisbrenner. I’ve been in the natural gas business for almost 34 years. About half of that experience was spent in traditional natural gas, and the other half in LNG. I’ve worked with both big companies and also entrepreneurial startups, and I’ve enjoyed both. Before I formed NextDecade, I started a firm called Excelerate Energy, which has been extraordinarily successful in developing natural gas floating, storage and regasification units (FSRUs) around the world, from conception to full operations. Then, I was recruited by Royal Dutch Shell to run Shell’s LNG business from The

Netherlands, which I did for about three years. Although Shell is a great company and I learned a lot from the experience, I was eager to work again at a smaller entity where I could have a greater impact. The reason I formed NextDecade was to develop an organization that incorporated the best practices of large oil companies with the best practices of the successful entrepreneurial companies. That’s the basis for our company culture, and it’s a lot of fun. GP. What is your outlook for the current LNG market?

Eisbrenner. Despite what has been occasionally reported, we have found very robust appetite for incremental LNG consumption on a long-term basis all around the world. In fact, we’ve recently signed tentative, non-binding agreements to deliver about 24 MMtpy of LNG. GP. Do you believe that the volatile oil and gas prices will affect that outlook?

Eisbrenner. Both oil and natural gas prices are recently at historic low levels. That impacts the economics of projects that are based on oil prices, but it also impacts demand from a positive standpoint. With oil prices so low, the cost of delivering LNG around the world is also quite reasonable. If anything, we see demand pushing upward as a result. GP. How does this affect your specific projects?

Eisbrenner. Our projects in North America are based on a Henry Hub index, or netback. As of early December 2015, Henry Hub was about $1.80/MMBtu, which is also a very low level. So, although commodity prices overall are quite low, because we are a Henry Hub-based project, our economics have stayed quite robust and interesting for deliveries to Europe, Asia and Latin America. Gas Processing | JANUARY/FEBRUARY 201611

EXECUTIVE Q&A VIEWPOINT GP. What effect might low oil prices have on gas feedstock for your projects if drillers lay down rigs in oil developments, which would subsequently reduce the amount of produced associated gas?

Eisbrenner. We are carefully monitoring the industry to better anticipate what lies ahead in 2016—from the combination of low oil and gas prices to the potential likelihood of the writedown of reserves for many of the independent oil companies, especially in light of the past 12 months of low commodity prices. There might well be a pullback in production, which would have an impact on pricing. I would say, though, that it’s fascinating to dig into shale economics. Although shale plays are known to have significant decline rates associated with production, there is also an almost infinite tail of production associated with the wells that are drilled horizontally for the production of oil and gas. I think the aggregation of all of these tails—some of which could last as long as 60 years, a significant duration—will support production, even if there is a pullback in oil drilling. Yet, if there is a pullback in the production of natural gas as a result of either oil or gas drilling, then prices will increase. For example, the Eagle Ford shale play is profitable at between $3.50/ MMBtu and $4/MMBtu, just for dry gas production, and there is plenty of gas there. So the question is whether it will be produced as production gas or associated gas. We’ll have to see how it plays out this year. GP. What is the plan for your Rio Grande project near the Mexico border of Brownsville, Texas?

Eisbrenner. In the Rio Grande project, we are permitting for six trains with a nameplate capacity of 4.5 MMtpy each. With a full buildout scenario, that’s 27 MMtpy. Our initial final investment decision is dependent on the first two of those six trains with 9 MMtpy. That’s about 400 Bcfy of feed gas. Given the changes to the natural gas infrastructure in the US, that gas can come from anywhere. Of course, we are very focused on Eagle Ford and Texas production, because that makes the most logical sense. However, due to the amaz-

ing abundance of gas in the Marcellus and Utica areas in the Northeast, and the increasing trend of reversing pipeline flows from former supply areas, it’s an amazing phenomenon. At this point in time, we are not targeting any one specific area for feed gas. Rather, we are prepared to take advantage of the flexibility of the US gas grid, which has the capability to deliver from multiple points. We expect the Rio Grande project to be completed by year-end 2020. GP. Do you have a pipeline project associated with that?

Eisbrenner. Yes. The Rio Bravo Pipeline that we are building to supply that gas will be 140 mi long and will run from the Agua Dolce market hub area to our site near Brownsville, Texas. It will interconnect with up to nine interstate and intrastate pipelines. That will create the liquidity for us to be able to pick and choose the most economical gas supply. GP. What do you plan for your Pelican Island project near Galveston, Texas?

Eisbrenner. This is a smaller project. We plan to start with two trains at Pelican Island of 4.5 MMtpy each. For Pelican, our feed gas pipeline will begin at Katy, Texas. From there, we can connect with at least 10 interstate and intrastate pipelines. With both of these projects, we are looking to build in the flexibility to source gas from any production basin. The timeline for this one will follow Rio Grande, depending on market demand. We expect this to begin 12–24 months after Rio Grande. GP. Do you have target markets lined up for the LNG exports?

Eisbrenner. At this point, we haven’t announced any firm commitments, but we have nine specific contracts out for review among seven various countries, so it’s quite diverse. Regardless of where we eventually end up exporting to, additional LNG supply will benefit the US and global economies significantly. GP. Since your Brownsville project will be so close to the border, do you foresee Mexico as a marketer or a supplier?

Eisbrenner. We are definitely looking at that. Our Rio Grande permit,

12JANUARY/FEBRUARY 2016 | GasProcessingNews.com

which is currently under consideration by the Federal Energy Regulatory Commission, contemplates two 42-in. gas pipelines in parallel easements from Agua Dolce down to Brownsville. That can accommodate a heck of a lot of gas. In fact, it would satisfy our current buildout plan of 27 MMtpy. We are watching what is happening with Mexico from both perspectives. We could have the opportunity to pipe gas to Mexico, and, with the newly proposed drilling programs there, we see the potential for Mexico to start producing supply gas. Mexico could need additional imports, but it might also become an exporter of gas or, more specifically, LNG. A lot of people don’t realize that the same geology of the Eagle Ford is also there, across the border. Now that the economic incentives are in place, and Mexico has recently gained the constitutional ability to solicit interest in drilling in Mexico, they could be producing as much as the Eagle Ford, dependent on commodity prices. NextDecade was created and is positioned to be flexible within the entire gas supply-to-market chain, and we find that exciting. We’re looking forward to working through our projects, from greenfield to LNG deliveries, over the next few years. GP. Where do you see NextDecade in five years?

Eisbrenner. In 2010, a little more than five years ago, I founded NextDecade with the goal of becoming the leader of the second wave of LNG from the US. Five years from now, I believe we will have achieved that goal. NextDecade will have shipped its first cargoes from Rio Grande LNG and we will be in the process of getting ready to bring additional projects online. While there may still be a lot to do to get there, I am confident that we can accomplish this through our commitment to excellent customer service, the communities in which we operate, and most importantly to the safety and reliability of our projects, supported by our industryleading partners. Beyond this, I expect several other exciting projects to be progressing, both in the US and around the world. I personally cannot wait to see where the next decade will take us. GP

SPECIAL REPORT: PIPELINES, TERMINALS AND STORAGE

Meet Subpart W emissions compliance with automated data integration H. QIN, Wood Group Mustang, Houston, Texas

On October 30, 2009, the US Environmental Protection Agency (EPA) published the Mandatory Reporting of Greenhouse Gases Rule (referred to as 40 CFR Part 98), which requires reporting of greenhouse gas (GHG) data and other relevant information from large sources and suppliers in the US. To meet this compliance requirement, reporters/business owners must report true, accurate and complete GHG emissions to the best of their knowledge (according to GHG CFR §98.4 authorization and responsibilities of the designated representative). Calculation methodology is specified in the rule, which makes the quality of the input data critical in ensuring the ultimate reporting quality. This GHG reporting rule requires an unprecedented amount of data input from oil and natural gas producers. The environmental groups in each organization charged with collecting, calculating and reporting the emissions data are overwhelmed by the task. As an example of volume collected, one ongoing project has estimated 1.2 MM data points for a reporting entity with approximately 9,000 well sites, averaging about 130 data elements per well site. The data required for the GHG natural gas production has been estimated to be approximately two orders of magnitude more than any previous EPA required report. According to recent EPA public GHG emissions data, there are more than 500 onshore facilities in the US conducting production, processing, transmission and distribution activities. A facility can contain hundreds or thousands of well pads and their equipment in a single hydrocarbon basin (per 40 CFR §98.238). The onshore segment is the largest contributor of facilities, with the necessary reporting criteria of emissions greater than 25,000 metric tons of carbon dioxide equivalent (CO2e). Among the prominent components of the GHG reporting program is Subpart W, dealing with the CO2-equivalent emissions from the producing wellhead through transmission, storage and distribution mains. The initial Subpart W reporting excluded gas gathering lines and boosting stations prior to the gas processing phase. These systems move natural gas from the well to either larger gathering pipeline systems or to natural gas processing facilities. The EPA plans to issue amended rules that are due to take effect by January 1, 2016 for calculating, monitoring and reporting emissions for these additional sources, with 2017 as the first reporting data year. More than just volume. More challenging than the sheer volume of data is the fact that much of the information is normally

tracked by separate functional groups for different purposes. Data sources include: • Equipment inventory data, such as information on the number of wells and their associated equipment (e.g., engines, compressors and separators) and their attributes (e.g., horsepower) • Production data, such as gas and condensate production by well • Operational and activity data, including all well operating-related information, such as well operating hours, engine run hours, well venting for liquids unloading, gas pressure and gas analysis by well • Other non-system data, including well flowback events with hydraulic fracture, workover activities without hydraulic fracture, horizon and formation information, etc. Most of these data are hosted in different formats and systems. In addition, these data do not share the same terminology due to their intended functionalities. Environmental groups within the organization must resolve how to make different data sets talk in a common language. Prior to initiation of the GHG reporting rule, there had not been a pressing need to thread the data to make a united and congruent delineation about assets at the well level. Rule section §98.237 states that records must be retained. Among the required records is one explaining how company records, engineering estimation or best available information are used to calculate each applicable parameter under this subpart. This requirement stipulates that business owners/ reporters must provide a consistent and systemic approach to make assumptions when data discrepancies or gaps exist. This specifically addresses the importance of data quality assurance (QA) and quality control (QC) in collection, integration and reporting. How to comply. To comply with EPA regulations, particularly with Subpart W, natural gas producers have turned to a centralized data warehouse. This solution automates data collection, integration and quality assurance. It first requires integration of available data from multiple function groups with different terms and reporting formats. Once accomplished, it is necessary to find a unique identifier to make data from multiple systems communicate in a common language. According to the case study implemented for an ongoing project of a major producer, 80% of the labor time has been spent on data collection, integration and data QA/QC. Gas Processing | JANUARY/FEBRUARY 201613

SPECIAL REPORT: PIPELINES, TERMINALS AND STORAGE the structure where all data QA/QC and emissions calculations can be performed on the common data platform. These actions lay the foundation for the subsequent 1. Data process of data QA. collection Data integration involves four steps. The GHG common global 80% first step assesses which data fields need to data model Reduction in be integrated, and identifies the primary labor hours due fields. This requires mastery of the rule to automation 2b. Find 2c. Identify 2. Data 2a. Data 2d. Aggregate requirements and detailed analysis of availcommon relationships integration assessment and integrate identifier and hierarchy able data, their applicable ranges and their limitations. Some data may be the direct input of the emissions calculation, and some 3d. Take 3e. Review 3a. Scan data 3b. Evaluate conservative before and after may be indirect input data. The second step using logic materiality 3. Data action comparison quality finds the common identifier that connects Major assurance data pieces from different systems. The 3f. Send data 3c. Request 3g. Export owners issue common identifier could be embedded in responsible cleansed data reports with data owners for emissions a data field or even in additional mapping, continuous data to fix data calculation for improvement but this is the most essential step. The third step recognizes hierarchical or non-hierarchical relationships between data 4. Report 4a. Calculate 4b. File report points. For example, equipment covered by filing and End emissions in eGGRT feedback the reporting data requirements, such as pneumatic pumps, engines, compressors, FIG. 1. Workflow diagram of GHG reporting preparation. etc., can be mapped hierarchically to the well head at the well site, while the enginedriven compressor to its engine is a typical horizontal, or non-hiNon-system Equipment Production Operational data inventory data and activity data erarchical, relationship. Once the relationship is established, the data aggregation and integration become easy. The fourth and final step is the actual process of data aggregation of all annual gas production, activity and equipment organized by each well. GHG Quality assurance (data QA/QC). The quality assurance common global process is perhaps the most significant action, tying directly data model back to the CFR §98.4 mandate. It ensures that the reporter meets the compliance requirement that the report is true, acWellhead curate and complete. This process can be the largest and most critical time investment of all the processes in preparing the report when the following criteria are met: Controller Separator Compressor Engine ..... • Two or more disparate data systems are involved and were not designed for environmental reporting • Two or more geographic assets are involved, with more than 1,000 wells in total to report • There is no standard guideline pertaining to the data FIG. 2. Equipment relationship within the GHG data model. tracking in either system • Rigorous data entry is lacking in either data system. FIG. 1 shows a workflow for GHG reporting preparation. It All of these factors lead to incomplete, inconsistent and disalso demonstrates the four-stage process when data collection, crepant information. data integration and data QA/QC are automated. The highest level of QA/QC requires a unique skill set. Data collection. The main objective of this process stage Combining upstream engineering knowledge and data analysis is to identify sources that could provide data required by the skills in the data validation of an ongoing project has proven to GHG reporting rule. It is not uncommon for these data sources be a high-yield exercise. Leveraging what data has been inteto be from completely disparate systems. However, the focus at grated from previous processes, a series of business logics was this step is to make sure data from these systems can be bridged developed to perform data analyses and data validation. These into a centralized database. In the example shown in Level 1 of logics are compiled in the format of database scripts within the the diagram, it is labeled “GHG common data model” for furcommon data model to perform several functions: ther aggregation and integration. More detailed assessment of • Check individual system for duplicates, missing key which data fields are necessary to integrate will be conducted in information or discrepancies within its own dataset the next stage, data integration. • Cross-check well list between equipment inventory, Data integration. The role of data integration is to select activity and production data systems all relevant parameters/information and rearrange them into Start

Equipment inventory

Production data

Operational and activity data

14JANUARY/FEBRUARY 2016 | GasProcessingNews.com

Non-system data

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SPECIAL REPORT: PIPELINES, TERMINALS AND STORAGE • Cross-check well and equipment operating status between equipment inventory, activity and production data systems • Cross-check equipment count based on their relationships with one another. In the project mentioned earlier, environmental personnel can easily perform data QA/QC and generate a validated dataset that is ready for GHG emission calculation, along with a feedback report of violations, to send to data owners. Report filing and feedback. The final stage uses the output from the previous QA/QC process, submits the report to the EPA after emissions calculation, and sends the data issue report to data owners for review and correction. This process takes the remaining 20% effort of the full reporting preparation. The project mentioned earlier focused on automating the 80% effort. The efficiency that automation provides to the environmental personnel is significant. Processes that once required six weeks of labor have dropped to one or two hours of labor for this large gas producer with 1.2 MM data points. In addition, it provides a comprehensive and transparent methodology to answer the requirement of rule section CFR §98.237 that records must be kept to explain how best available information or engineering estimates are used to calculate emissions. Benefits extend beyond the GHG reporting rule for Subpart W production. This applies to the imminent Subpart W for gas gathering. More importantly, with the feedback reports of data issues to data owners, it creates a closed loop to drive for more

consistent and accurate data for environmental reporting and for other business-related analysis. The long-term benefits deserve to be noted. Recommendations. The EPA has continued to increase its emissions data requirements and number of regulations. Additionally, they are scrutinizing submitted data for consistency, with a focus on validation. As noted in the case of a major US producer, the solution involved the automation of data collection. Quality assurance is a key component of the solution, coupling a skill set of upstream engineering knowledge with a modular database system design, systems integration and data analysis expertise. The systematic approach and consistent QA/QC methodology aligns data with EPA reporting requirements, helping ensure regulatory requirements. The ultimate solution dramatically reduces labor time and increases efficiency. Data is reusable for other federal and state agencies, avoiding unnecessary duplication of effort. Additionally, the data accuracy allows the environmental staff to further analyze operating data for maximizing production while minimizing air emissions. GP HONG QIN has more than 15 years of experience in the software and professional services industry. She has held leadership roles in multiple air emissions projects, including recent work focused on developing advanced GHG solutions. Ms. Qin is a civil engineering graduate of the Harbin Institute of Technology in China and holds a master’s degree in industrial engineering from the University of Houston in Texas. She is a certified PMP member of the Project Management Institute.

10–11 May 2016

Dusit Thani Lakeview - Cairo EMGasConference.com

Save the Date The fourth annual Eastern Mediterranean Gas Conference (EMGC) takes place in Cairo on 10–11 May 2016. The conference provides attendees with the latest information on the region's developing natural gas industry, and the ability to gain entry to new regional markets and seek potential new business partners. Sessions will include: • The state of the Eastern Mediterranean—Licensing rounds and tenders • The Eastern Mediterranean’s resource potential • Resource development updates • Accelerated development—Pros and cons • Infrastructure • Investment and monetization • Hydrocarbons and public policy—Understanding the regulatory environment’s effect on the region’s resources • The impact and future of the new energy resource on the Global Market— The Eastern Mediterranean as a gas hub For agenda updates stay tuned to EMGasConference.com Questions about speaking/sponsoring/exhibiting: Contact Melissa Smith, Events Director at +1 (713) 520-4475 or [email protected]

16JANUARY/FEBRUARY 2016 | GasProcessingNews.com

SPECIAL REPORT: PIPELINES, TERMINALS AND STORAGE

Minimize evaporation losses by calculating boiloff gas in LPG storage tanks S. SHIVA SHAMEKHI and N. ASHOURI, Faradast Energy Falat Co., Tehran, Iran

Liquefied petroleum gas (LPG) is stored and transported in tanks as a cryogenic liquid, at a temperature below its boiling point near atmospheric pressure. Due to heat entering the cryogenic tank during storage and transportation, a portion of the LPG continuously evaporates, creating a gas called boiloff gas (BOG). BOG causes evaporation losses in the LPG supply chain over time. It is imperative to minimize vaporization and displacement losses due to the economic and safety problems that can result from such losses. The amount of BOG depends on the design and operating conditions of LPG plants. In the LPG supply chain, BOG can be reliquefied or sent to the flare and burned. The evaluation of BOG in a storage tank in all operating scenarios is important for the correct selection and design of a BOG compressor. Different sources exist for the generation of BOG. These sources include heat leaks from ambient air around the storage tank, heat ingress due to the dissipation of pumping power inside the tanks, heat leaks from pipelines, flash vapor generated by liquid rundown and displaced vapor from the tank due to liquid filling (known as the piston effect). In this study, boundary conditions and parameters have been implemented to accurately estimate the amount of BOG that evaporates at the C3 and C4 refrigeration and loading facilities at the Bandar Abbas gas condensate refinery in Iran. Study outline. The produced propane and butane from propane/butane splitter units are cooled down in the propane/ butane refrigeration unit via open-cycle refrigeration, and then run down to the associated refrigerated tanks and stored at atmospheric pressure before being exported to overseas markets via propane/butane carrier ships. As shown in FIG. 1, butane rundown is subcooled at the required temperature level in two exchangers in series, both utilizing propane. The chilled butane is then sent to the storage tanks. Propane is divided into two streams. One stream flows to the first exchanger and is flashed, and the other stream is sent to the high-pressure C3 suction drums and then flashed in the second exchanger. Liquid propane from the suction drum is utilized in the second exchanger, and relevant flashed vapor is sent to medium-pressure C3 suction drums and then to the low-pressure C3 suction drums. Liquid propane flashes to lower pressure levels in mediumand low-pressure suction drums before being pumped to refrigerated storage tanks. Propane vapors result from the rundown

product pressure reduction, and flashes at the different pressure levels are compressed in two parallel, three-stage centrifugal compressors, before being condensed in a C3 air cooler and a C3 compressor condenser. Liquid propane is collected in a C3 accumulator and flashed again to the high-pressure suction drum to restart the cycle. Boiloff vapors from propane tanks are sent to the low-pressure suction drums and then to the first compressor stage. No vapors develop from butane tanks due to the subcooling of the stored liquid product. Two tanks each are used for C3 and C4 storage. Since the boiloff calculation method can be used for both types of storage tanks, calculations are described for only one of the C3 storage tanks. Operating modes. To load propane and butane to the ship, it is necessary to cool down the pipelines at the lowest possible temperature, with the aim of reducing BOG production during the entrance to the ship compartments. Three steps are needed: preloading, loading and holding. Pre-loading includes two parts—the initial phase and the final phase—to achieve cooling of the pipeline with low flowrates and appropriate pipeline temperature, respectively. As a general rule, each tank follows three steps during normal operation: • Filling mode: The tank receives the product from the process unit at rundown flowrates. During the filling mode, it is necessary to prepare the tank for ship loading; in project documentation, this operation is called preloading. • Emptying mode: When the ship is ready to receive the products (i.e., when the pipeline is at proper temperature, parcels are at proper temperature, loading arms are connected, etc.), then it is possible to transfer the product from tank to ship. This operation is called loading.1 • Holding mode: The tank is full of product and ready for ship loading, but the ship has not yet arrived or is not ready for loading. This operation is called holding. To load propane to the ship, it is necessary to cool down the two pipelines at the lowest possible temperature, with the aim of reducing BOG production when products enter the ship compartments. Therefore, some days before the carrier ship arrives, circulation from the storage tank to the jetty and back to the tank is started. This process is applied when the pipelines are in equilibrium with the external temperature. Gas Processing | JANUARY/FEBRUARY 201617

SPECIAL REPORT: PIPELINES, TERMINALS AND STORAGE 4. Vapor displacement due to liquid inlet in the tank 5. Rapid variation of barometric pressure. Total BOG flowrate can be calculated with Eq. 1:

The preloading mode is the most critical operating mode from the point of view of BOG production, due to the great quantity of hot fluid trapped in the pipeline. For this reason, it is necessary to avoid a too-rapid displacement of the fluid to prevent abnormal overdesign of the BOG compressor. One of the major sources of boiloff production in liquefied gas handling is rollover, which can result in a boiloff rate several times greater than normal, causing rapid over pressurization while venting a considerable quantity of vapors to atmosphere. When the liquid layer adjacent to a liquid surface becomes denser than the layers beneath due to boiloff of lighter fractions from the tank, stratification develops and causes rollover due to rapid mixing as a result of density inversion. An effective solution is the mixing of the liquid in the tanks. For this purpose, two circulating pumps are placed inside the tank: one is always circulating the liquid and the other is used for cooling the transfer line.

BOGTotal = BOGTank + BOGTransferLine + BOGLoadingSystem + BOGElectricalMotor + BOGATM + BOGCirculationSystem + (1) BOGVaporDisplacement + BOGCompensationEffect Note: The contribution of BOG due to rapid atmospheric pressure variation is not considered, and is negligible when compared to the other contributions. Also, the compensation effect due to outflow of liquid from the tank is not considered. BOG is calculated utilizing simulation software. The thermophysical properties of propane are collected in TABLE 1. Required information for the calculation of BOG is presented in TABLE 2. Calculations for the contribution to BOG by heat absorbed in tanks are shown in Eqs. 2 and 3.

Calculation methods. BOG evaluation in all operating scenarios of the tank is important for the correct definition of the flowrates to the BOG compressors. BOG is produced under the following conditions: 1. Heat absorbed from ambient air by refrigerated storage tanks 2. Heat absorbed from ambient air by lines (rundown lines, pipelines) 3. Heat produced by the operation of pumps (loading, circulation, rundown)

BOG =

K V 0.1% = 24

VT =

D2 H= 4

31

581.2 24 31 4

21,737 28.8

= 526.4

Kg h

= 21,737

(2) (3)

Heat ingress by storage tank is equal in the three cases of holding, preloading and loading. Equations for the contribution to BOG by the transfer system are shown in Eqs. 4–9. C4 Loading pipeline

C4 From tank

C4 Return pipeline

C4 From jetty

Quench makeup supply line Quench makeup return line T quench in P quench in

BOG

Q C3 return line

C3 Return pipeline

Ambient Q transfer line C3 Transfer T Fluid in P Fluid in line

C3 Air cooler/ compressor C4 Return line

C3 Loading pipeline Q C3 loading line Ambient

C3 BOG compressor Transfer fluid in HP

LP Q Tank

Storage tank

C4 From bl. MP C3 /C4 exchanger

HP

HP C3 Suction drum

BOG compressor

MP

MP MP C3 Suction drum

C4 To storage tank

C3 From bl.

FIG. 1. Propane refrigeration BOG production.

18JANUARY/FEBRUARY 2016 | GasProcessingNews.com

LP

T Fluid suction P Fluid suction

Quench Return makeup pipeline fluid in fluid in Vapor displacement due to pumping in

T Tank Compensation effect due to pumping in C3 Storage tank

LP C3 Suction drum

T Fluid suction P Fluid suction Transfer pump

T loading P loading T Circ. out P Circ. out

C

P

Ambient

C3 Quench C3 Loading Q tank pump pump

C4 From jetty C3 From jetty

SPECIAL REPORT: PIPELINES, TERMINALS AND STORAGE

BOG =

(4)

WTransfer

Transfer line

Component

∆H Transfer pump ∆H Transfer line = Fluid ∆P liq.

∆H Transfer pump = 100

P=

(6) (7)

(8)

1.05 Latent heat

(10)

2

QL = 1 h0r0 Nu =

(11) (12)

Ts)

(T

h0D = 0.3 Kf

1

(13)

1 2 4 3

1

Re 282,000

5 8

(14)

Calculations for the contribution to BOG by the circulation system are shown in Eqs. 15–20. BOG = =

Circulation

WCirculation

(15)

∆H Circulation pump ∆H Circulation line Fluid

∆H Circulation pump = 100

43

Density, kg/m

581.5

3

0.086

TABLE 2. Required information for boiloff rate calculation Value Propane Density, kg/m

581.5

Storage tank operation pressure, barg

0.06

Storage tank height, m

28.8

3

Storage tank diameter, m

31

Inlet of ship operating pressure, barg

2.5

External heat from sun exposure, %

0.1

Ambient temperature, °C

42/47

Rundown pressure, barg

0.06

Rundown temperature, °C

–42

Latent heat, kj/kg

398

Vapor pressure, barg

13.31

Wind velocity, m/s

13.5

Air thermal conductivity, W/mk

0.027

Air viscosity, kg/m/s

1.9 × 10–5 1,005

Insulation thickness for loading line, mm

89

Insulation thickness for return line, mm

102

Insulation thermal conductivity

1 Re 0.5 Pr 3

0.4 Pr

Flowrate, m /h

Specific heat of ambient air, J/kg/K

– Ti

r0 ln ri Kins 0.62

17

Major consumption

D air air

2 l

40

Pressure, barg

(9)

Cpair µair 1005 1.9 10 5 Pr = = = 0.71 Kf 0.027 U

Temperature, °C

Viscosity, cp

where: Q Normal = 21.3 m3/h Q Max = 67.5 m3/h Head = 88.2 m η = 0.68 (ηShaft 0.75 × ηMotor 0.9) ΔP = SG × ΔH The ΔH transfer line is calculated by HYSYS. BOG pertaining to lines (circulation, loading and transfer line) can be calculated manually using Eqs. 10–14.2

Re =

1

3

5.03 1 = 1.28 581 0.68

BOG of line = 3.6 QL

Propane Liquid fraction

1

H 0.581 88.2 SG = = 5.03 bar 10.2 10.2

H Transfer pump = 100

Streams

(5)

Kp Ap WTransfer

∆H Transfer line = 3.6

TABLE 1. Physical properties of C3 and C4 as refrigeration feed

∆P liq.

1

0.038

Length of loading line from tank to jetty, km

23

Diameter of loading line from tank to jetty, in.

20

Length of circulation line from jetty to tank, km

23

Diameter of circulation line from jetty to tank, in.

20

∆H Circulation line = 3.6 3.6

Kp Ap r line = WCirculation

Kp Ap WTransfer H

SG

0.581 339 =19.3 bar 10.2

(19)

19.3 581

(20)

(16)

P =

(17)

H Transfer pump = 100

10.2

=

(18)

1 = 5.3 0.68

Gas Processing | JANUARY/FEBRUARY 201619

SPECIAL REPORT: PIPELINES, TERMINALS AND STORAGE

TABLE 3. Results of BOG calculation during operating modes Bog

Electrical motor

Tank

Transfer line

Circulation system

Loading system

Loading pump

Circulation pump

Vapor displacement

Initial phase

525.9

289.4

1,599.75

52,734.4

–

498

333.9

Final phase

525.9

213.6

1,571.15

30,986.8

869.1

332

222.5

Loading

525.9

–

1,559.9

142.7

869.1

332

109

Holding

525.9

141.1

1,506.55

–

–

332

107.6

Mode Preloading

where: Q Normal = 225 m3/h Head = 339 m η = 0.63 (ηShaft 0.7 × ηMotor 0.9) Calculations for the contribution to BOG by the loading system are shown in Eqs. 21–26. BOG = =

Loading

WLoading

(21)

∆H Loading pump ∆H Loading line Fluid ∆P liq.

∆H Loading pump = 100 ∆H Loading line = 3.6 P =

1

Kp Ap WLoading

(22) (23) (24)

H SG 0.581 365.5 = = 21 bar 10.2 10.2

(25)

21 1 = 5.02 581 0.68

(26)

H Transfer pump = 100

where: Q Loading = 1,250 m3/h Head = 365.5 m η = 0.72 (ηShaft 0.8 × ηMotor 0.9) Calculations for the contribution to BOG by electric motors are shown in Eqs. 27–28. Q BOG = Electrical motor (27) λ Fluid ⎡ 1 ⎤ Q Electrical motor = 3,600 × Power × ⎢1− ⎥ (28) ⎣ η ⎦ where: Power of loading pump = 904.3 kw Power of circulation pump = 172.7 kw. The calculation for the contribution to BOG by vapor displacement is shown in Eq. 29. BOGVAP = Rundown × ρVap

(29)

Rundown flowrate definitions include: • The normal flowrate is 21.3 m3/h on the transfer pump when the system is in holding mode 20JANUARY/FEBRUARY 2016 | GasProcessingNews.com

• The maximum pump flowrate is 67.5 m3/h for the transfer pump when the system is in preloading mode (initial phase) • ρ is determined by the simulator and is derived from flashing before entrance to the storage tanks. The results for the different operating modes experienced by storage tanks are shown in TABLE 3. Takeaway. The calculations described represent a simple approach for engineers to estimate produced BOG ratio in cryogenic systems for LPG and LNG. The BOG ratio can be calculated manually or with the use of a process simulator. GP ACKNOWLEDGMENT The author thanks the board of directors and the process division of Faradast Energy Falat Co., the general contractor of Bandar Abbas Gas condensation refinery, for its support. λ α η W Kp Ap H Kt Vt ρ Kf Kins

NOMENCLATURE Latent heat Vapor fraction Pump shaft efficiency Mass flow Average heat flux through the pipe, W/m2 Piping external surface area, including insulation, m2 Enthalpy Vaporization coefficient, considered equal to 0.001 for C3/C4 Geometrical volume of tank, m3 Density Thermal conductivity of ambient air, W/km Thermal conductivity of insulation, W/km

LITERATURE CITED Chen, C. C., “Fine-tune refrigerated LPG loading line operation,” Hydrocarbon Processing, August 2005. 2 Wordu, A. A. and B. Peterside, “Estimation of boiloff gas from refrigerated vessels in liquefied natural gas plant,” International Journal of Engineering and Technology, Vol. 3, No. 1, January 2013. 3 Adom, E., et al. “Modelling of boiloff gas in LNG tanks: A case study,” International Journal of Engineering and Technology, Vol. 2, No. 4, 2010, pp. 292–296. 1

S. SHIVA SHAMEKHI is a process engineer in the process engineering department of Faradast Energy Falat Co. She is working on a mega-size project for a gas condensation refinery in Tehran, Iran. She holds BSc and MSc degrees from Amirkabir University of Technology in Iran. Her areas of specialization include basic design of refrigeration plants and detailed design of gas and petrochemical plants. She can be reached at [email protected] or [email protected]. N. ASHOURI is the process lead engineer in the process engineering department of Faradast Energy Falat Co. He is working on a mega-size project for the Bandar Abbas gas condensate refinery in Iran. He has 16 years of experience in the design of oil and gas refineries. Mr. Ashouri holds an MSC degree in process engineering from the Iran University of Technology. He can be reached at [email protected].

PLANT DESIGN

Efficiently design and operate vertical gas/liquid separators

P. DIWAKAR and J. VALAPPIL, Bechtel Oil, Gas and Chemicals Inc., Houston, Texas

Gas/liquid separators, or knockout drums, are used to eliminate liquid droplets from incoming multiphase flows and prevent liquid carryover to downstream compressors and rotating equipment. Liquid in any quantity is a safety concern, since droplets may cause erosion damage in blades and corrosion in other downstream equipment, especially in the presence of water. The mechanisms governing the separation of liquids and solids from gas include gravity, inertia, shear and turbulence. Most separators use a combination of these mechanisms. The most important principles in a liquid-gas separator are to ensure that: 1. Smaller droplets are not formed due to droplet shearing or impingement, which would make it more difficult for a mist-eliminator device to coalesce and separate it from the gas 2. The velocity of the gas carrying the droplets and particulates is low enough as it approaches the misteliminator device, as governed by the K factor 3. The superficial velocity is uniform over the entire area of the mist-eliminator device, with the peak velocity not more than 10% above the mean velocity. The importance of the removal of liquids, particulates and heavies is emphasized by the number of separation stages required before the feed gas reaches a compressor in the process diagram shown in FIG. 1. The dryer inlet filter separator may take a higher liquid load and separate liquids of the order of 10 µ and higher. A filter coalescer as the next stage is capable of separating droplets in the submicron range. Dehydrators made of beds of semi-permeable absorbent can remove almost all liquid hydrocarbons or water. The sizing of each of the components of a knockout drum is not trivial, and advanced simulation tools must be used to ensure that the device operates as designed. In this article, design guidelines for different separator sections—starting with the upstream piping—are discussed. Validation and post-processing figures come from computational fluid dynamics (CFD) combined with 1D calculations and empirical correlations. Inlet and upstream piping requirements. FIGS. 2 and 3 show examples of liquid/gas separators. The multiphase flow, which consists of gas and liquid, such as water and hydrocarbon from upstream, enters the vessel through the inlet nozzle. The upstream flow regime is typically governed by the incoming mass flowrate; piping configuration such as bends, elbows, vertical or horizontal pipe; mass or volume fraction of liquid or solid in gas; and inlet momentum.

Taitel-Dukler flow maps for horizontal piping, and Hewitt and Roberts flow for vertical pipes, may be used to determine the flow regime of the incoming flow. Inlet piping should be sized so that the multiphase flow is in the stratified wavy regime to minimize the amount of dispersed liquid in the gas flow, and to separate the bulk of the liquid entering the knockout drum. The mist fraction of liquid increases while the maximum droplet size decreases. The increase can be quite substantial if the flow regime moves into the annular-dispersed phase.

FIG. 1. Process schematic showing several liquid separation stages.

Gas exhaust

Gas/liquid in Mist eliminator

Anti-climb ring

V-type diffuser HHLL FIG. 2. Dryer inlet separator and filter coalescers. Gas Processing | JANUARY/FEBRUARY 201621

PLANT DESIGN

FIG. 3. Vertical and horizontal filter coalescers. 10

1.0E+04 Annular-dispersed liquid

Bubble 1

1.0E+03

1.0E+02

Slug (intermittent)

Stratified wavy

0.01

1.0E+01

1.0E+00 1.0E03

0.1

T or F

K

Case 1

Stratified smooth 1.0E02

1.0E01

1.0E+ 00

X

1.0E+ 01

1.0E+ 02

1.0E+ 03

0.001 1.0E+ 04

FIG. 4. Taitel and Dukler maps for two-phase flow regime and various flow regimes in vessel and piping.

FIG. 5. Uneven incoming flow due to bends.

The sizing requirements are governed by the kinetic energy, or the inlet momentum. The higher the energy of the gas flow, 22JANUARY/FEBRUARY 2016 | GasProcessingNews.com

the higher the velocity and the higher the tendency for larger droplets to be carried against gravity toward the demisting device. For vane-type inlet devices, approximately 6,000 kg/ms2 are allowed, since the velocities are lowered and distributed as the flow passes through the vanes. For other inlet devices that may induce shear and shatter droplets, the momentum should be approximately 1,500 kg/ms2. Bends and elbows in the upstream piping play a significant role in droplet shattering due to the impingement creating smaller droplets that are more difficult to separate, since they are easily carried by the gas stream. Further centrifugal forces (due to flow turning at right angles) and swirl (due to rotational momentum) may force liquid to one side of the vessel, placing an uneven distribution of liquid into the vessel and going up to the demisting device. These forces can produce localized flooding, which leads to larger liquid carryover at the outlet of the knockout drums. The maldistribution in the flow field into the vessel is shown in FIGS. 5 and 6. This situation may also lead to more liquid stripped from the liquid-free surface if liquid is present in the vessel. A diameter of at least 10 in. to 15 in. of straight piping upstream is recommended for the flow to fully develop on approaching the vessel. Anti-swirl devices and turning vanes may be placed upstream to even out the flow entering the vessel.

PLANT DESIGN Inlet diffuser device selection. Inlet devices are equally important in determining the amount of liquid and droplet size carried to the demisting device. Some of the most common types of inlet devices are shown in FIG. 7. The main function of the inlet device is to improve the separation of bulk liquid from the gas and decrease the load on the demister. A properly sized inlet device should reduce the feed gas momentum and ensure a uniform distribution at the mist eliminator entry, as well as eliminate local overloading or flooding. Inlet conditions are determined according to properties of the incoming media: • Physical properties of gas, such as density and viscosity, determined by operating pressure and gas composition • Liquid-phase properties, including viscosity, density and surface tension • Droplet-size distribution of the liquid phase • Gas-to-liquid ratio. The requirements of the separation operation are determined according to: • The separation efficiency related to mist, slug, solid, etc. • Turndown ratio • Allowable pressure drop • Sizing constraints. Other than these slotted T-type distributors, tangential inlet, cyclone type, dual vanes and multi-vanes are used. In general, the inverted half-pipe, sparger or V-shaped distributors are not recommended, mainly due to liquid re-entrainment concerns. Waves formed due to gas impingement on the free surface may lead to smaller droplet formation, and these droplets may be stripped from the waves and carried toward the mist eliminator. Flooding is a condition where the mist eliminator is choked with liquid and leads to higher-pressure droplets and large carryover of liquid at the outlet. The Hinze1 criteria is used to determine the maximum stable droplet size and whether shearing at the inlet device will produce small droplets that will pose more challenge to demisting operations, as shown in Eq. 1: 3

2

⎛ ρ ⎞– 5 – Dmax = 0.725⎜ c ⎟ ε 5 ⎝ σ ⎠

through a force balance equating capillary pressure in the droplet to the dynamic pressure, as shown in Eq. 2:

FIG. 6. Swirling flow due to elbows in upstream piping.

(1)

where: ρc = Gas density (continuous phase) σ = Surface tension between liquid and gas ε = Turbulent dissipation rate obtained from a CFD FIG. 7. Common types of inlet devices. calculation using standard turbulence models, as shown in FIG. 8. The calculation of a relatively larger droplet size will show that shearing of droplets at the inlet device is not at a level to create smaller droplets that will impart an extra load on the demisting device. The smallest droplets or bubbles that can be created by dynamic forces in a shear flow are equally important to determine the level of liquid entrainment into the separator. The Weber number criteria by Kouba2 may be used for this purpose. These criteria are derived FIG. 8. Turbulent dissipation rate obtained from a CFD calculation using standard turbulence models. Gas Processing | JANUARY/FEBRUARY 201623

PLANT DESIGN

⎛ ρ V 2 D ⎞ Wemin = ⎜ c c min ⎟ = 8 ⎝ σg ⎠

(2)

Water droplet flow, kg/s

0.040

HC droplet flow

0.030 0.020 0.020 0.000

Weight fraction less than droplet size

1.00 0.80 0.60 0.40 0.20 0.00

2 4 8 16 32 64 128 256 512 Droplet size (microns) log scale 512, 1.00 128, 0.88 256, 0.96

0.030 0.020

64, 0.76 32, 0.60 HC droplet fraction 16, 0.40 8, 0.24 4, 0.12 2, 0.04 0 100 200 300 400 500 600 Droplet size, microns

Water droplet

0.010 0.000

1.00 0.80 0.60 0.40 0.20 0.00

Weight fraction less than droplet size

HC droplet flow, kg/s

where: Vc = Velocity of continuous phase g = Gravitational constant. Most systems are designed and tested for water/air systems. For liquid hydrocarbon with much lower density, viscosity and surface tension, appropriate derating must be done, and the smallest droplet size calculated may be 7 to 10 times

2 10 20 40 80 160 320 6401,280 Droplet size (microns) log scale

1280, 1.00 320, 0.88 640, 0.96 160, 0.76 80, 0.60 Water droplet 40, 0.40 fraction 20, 0.24 10, 0.12 5, 0.04 0 200 400 600 800 1,000 1,200 1,400 Droplet size, microns

FIG. 9. Differences between hydrocarbon and water droplet size distributions.

Gas Liquid

smaller than water. Therefore, hydrocarbon will govern the design of both inlet diameters and all internals in the vessel. To obtain an accurate estimate of the liquid loading at the entry of a demisting device, multiphase CFD calculations are performed. A less time-consuming steady-state approach is to use a Lagrangian-Eulerian model, using droplets as discretephase massless particles in the gas phase dispersed in a lognormal distribution, using largest and smallest droplet sizes calculated from Eqs. 1 and 2. This is Gaussian distribution of the Log(n). A Rosin-Rammler distribution may be used only if there are solid particles for solid-gas or solid-liquid separation equipment. FIG. 9 shows the difference between hydrocarbon and water droplet size distributions. The demisting device must be appropriately sized to take the entire load of liquid coming into the vessel. The sizing must be conservative and help minimize liquid carryover to the outlet of the vessel. Criteria for droplet shear at free surface and re-entrainment. High-velocity gas over the surface of a liquid creates

waves. Liquid droplets are sheared from the free surface and carried away by the gas stream. Most of the droplets are likely to end up at the mist eliminator unless the droplets are heavy enough to drop back down into the gravity section of the knockout drum. A schematic of a gas shear is shown in FIG. 10. The Kelvin-Helmholtz (KH) criteria can be used to calculate the sensitivity of the liquid-free surface and gas shear based on the surface tension and densities of the two media. For elevated gas speeds over liquid pools, if the flow is turbulent and the film Reynolds number exceeds 10,000, then re-entrainment will take place if gas velocity exceeds the following criteria by three to four times (Eq. 3): 1

Roll wave Gas Liquid Wave undercut FIG. 10. Droplet shearing from liquid-free surface.

Vc =

2× (ρ1σg ) 2 ρg

(3)

where: ρ1 = Liquid density σ = Surface tension g = Gravitational constant ρg = Gas density Vc = Critical gas velocity for the onset of KH waves. If liquid droplets are formed at the tips of the waves, then the minimum size of the droplets (dmin) can be calculated using Eq. 4: dmin =

FIG. 11. Comparison of typical gas velocities produced at the free surface for a vane-type inlet distributor and a sparger.

24JANUARY/FEBRUARY 2016 | GasProcessingNews.com

13σ 2 ρ g Vmax

(4)

FIG. 11 compares typical gas velocities produced at the free surface for a vanetype inlet distributor and a sparger. An inlet distributor that reduces and distributes flow, and that also reduces KH waves, should be selected. A height of at least 300 mm from a high-high liquid level (HHLL) to the bottom of the inlet

PLANT DESIGN distributor is recommended by the Gas Processors and Suppliers Association. The Steen Wallis criteria3 is also used to calculate the critical velocity Vc , as shown in Eq. 5: Vc =C

σ µg

ρ1 ρg

(5)

where: C = Constant in the range of 1.8E-4 to 2.46E-4 μg = Gas viscosity. It is possible to observe how high the re-entrained droplets created by wave shear from the free surface will travel by injecting droplets from the free surface at the vertical upward velocity computed using CFD. FIG. 12 shows larger-size droplets traveling a short distance before falling back. If the gas velocities observed or calculated exceed either of these two criteria, then it is recommended that a wire mesh pad be placed below the inlet flow device to prevent re-entrant droplet from being carried off by the gas stream, or the HHLL from being lowered by the increasing tangent-to-tangent height of the vessel. Sizing the gravity section. The separation efficiency of the gravity section is calculated from the droplet force balance. Separation is governed by Stokes’ law, which states that the droplets dispersed in a continuous phase will settle if the downwardacting force of gravity is greater than the sum of drag around the assumed spherical droplet and greater than buoyancy, due to thermal gradients (if present). This law is valid only for Reynolds numbers from 0.1 to 0.3. Unless the K factors are extremely low, it is very likely that there will be no liquid separation in this section. The basic equation for terminal settling velocity, Vt , is given in Eq. 7: Vt =

where: D = µ = ρl = ρg =

g D2 ⎛ ρ1 −ρ g ⎞ ⎜ ⎟ 18 ⎝ µ ⎠

Droplet diameter, ft Gas viscosity, lb/ft/s Liquid density Continuous phase density.

FIG. 12. Liquid droplet re-entrainment from free surface not carried due to lower velocities.

In most vessels, especially slug catchers where designs are based purely on gravity separation, the diameter of the vessel and the height of the gravity section should be determined while keeping K factors to a minimum. The Souders-Brown k-factor is given in Eq. 8:

(

⎛ ρ −ρ 1 g Vmax = K ⎜⎜ ρ g ⎝

) ⎞⎟

(8)

⎟ ⎠

where Vmax = Maximum velocity. A properly sized gravity section is typically the height of one vessel diameter, and allows the flow to redistribute and even out the distribution at the mist eliminator entry. The flow fields at the mist eliminator entry for an undersized gravity section, and for one of sufficient height, are shown in FIG. 13. Vertical cross-section vectors are shown in FIG. 14. Mist eliminator considerations. A mist eliminator may con-

tain several of the following elements: • A vane pack made up of corrugated plates with or without pockets (pocketed vanes) to collect larger liquid droplets • A wire mesh demister consisting of a wire mesh of intertwined wires with high surface density and high void fraction to collect smaller droplets

(7) FIG. 13. Flow fields at mist eliminator entry for an undersized gravity section (left), and one of sufficient height (right).

FIG. 14. Vertical cross-section vectors. Gas Processing | JANUARY/FEBRUARY 201625

PLANT DESIGN der of 10µ, and larger droplets without any large pressure drop. Mist consists of droplets in the submicron range (< 3µ), while 10µ and higher would be a spray. Gap A typical wire mesh pattern is shown Flow direction in FIG. 15, with droplet coalescing at the Vane pack junction of two wires. Also shown is a Perforated plate typical mist eliminator, consisting of a coarse and fine wire mesh followed by Typical wire mesh Droplet coalescence and capture Typical mist eliminator package a vane pack and perforated plate (right). FIG. 15. A typical wire mesh pattern (left), with droplet coalescing at the junction of two wires Passing through the wire mesh, small(right). er droplets adhere to the wire, coalesce and form larger droplets. The larger droplets are driven down by gravity and are collected by a drainpipe, plates or V-shaped channels. Grid and frame Wire mesh 1 Wire mesh 2

FIG. 16. Pocketed vane pack and related flow field.

Liquid in any quantity is a safety concern, since droplets may cause erosion damage in blades and corrosion in other downstream equipment. ... The sizing of each of the components of a knockout drum is not trivial, and advanced simulation tools must be used to ensure that the device operates as designed. • A perforated plate to impose a pressure drop. The wire mesh agglomerates small droplets into larger ones and captures smaller droplets. The vane pack then captures the larger droplets. The droplet capture efficiency and the wire mesh/vane pack droplet handling capacity and k-factors given in the device supplier hydraulic calculations are usually obtained from test data using air/water systems at lower pressures and ambient temperatures. Suitable derating parameters using Weber and Froude numbers must be calculated for different fluids with different gas/liquid density, viscosity, surface tension, operating pressure and temperature to re-estimate actual liquid carryover and droplet removal efficiency of the mist eliminator system. Typical mist eliminators take water liquid load of 1 gpm/ft2 derated to 0.5 gpm/ft2 for liquid hydrocarbon. Mesh mist eliminator. With high void fraction, wire mesh

or knit mesh may reduce liquid carryover by 100th of the or-

26JANUARY/FEBRUARY 2016 | GasProcessingNews.com

Vane pack. Vanes can be engineered to operate at higher gas velocities and flowrates relative to the mesh. The efficiency may drop off drastically at low velocities, mainly due to the fact that droplets will drift around the mesh filament and blades without touching or adhering to the surface. If the velocity is too high, then the droplets are captured; however, the higher flow will essentially overcome the surface tension forces of droplets adhering to the solid surface and re-entrain them back into the gas stream. Vanes may be of the corrugated variety, or they may even have pockets to capture droplets, as shown in FIG. 16. Enhancements for minimizing vessel size. For compressor

suction drums that use refrigerant, the low-, intermediate- and high-stage units are usually designed as one vessel, with a unit for each stage placed on top of one another. The vessel size is governed by the low stage due to larger flowrate and liquid content. To keep the vessel diameter constant for all three stages, the intermediate and high stages are most likely oversized and will not require a stringent analysis to predict liquid carryover. To conserve space, the low-stage mist-eliminator unit (usually a vertical box called four-bank housing) has four vertically placed mesh pads, a vane pack and perforated plate combinations at each face, as shown in FIG. 17. If the direction in which flow enters the vessel is taken as the east direction (as referenced in FIG. 6), then there is more flow to the north and south faces of the four-bank housing (FIG. 17A) compared to east and west faces (FIG. 17C). Furthermore, the cramped space between the housing and the vessel wall forces flow toward the upper quadrant, causing a large velocity gradient across the face of the mist eliminator (FIG. 18). This situation leads to high peak k-factors and localized flooding. The contour plots also show some flow redirected back into the vessel at the bottom of the housing, which has a negative effect on liquid removal efficiency. To mitigate the flaws in design, some improvements are recommended for four-bank housing: • Rotate the four-bank housing by 45° about its vertical axis, which will result in the front faces of the mist eliminator facing northwest, southwest, southeast and northeast • Change the dimension of the housing, allowing a total gap area that is at least greater than three times the area of the inlet nozzle, to reduce the approach velocities.

PLANT DESIGN

FIG. 17. Four-bank housing (a); side-to-side flow field (north to south) (b); crossflow field (east to west) (c) and variable-area perforated plates (d).

These changes alone may not be sufficient to provide a uniform velocity profile to each of the four sides. A third mitigating effort is to adjust the open area of the downstream distribution baffle. Each perforated plate may be split horizontally, into as many as four sections, as shown in FIG. 17D. By using less net-free-area (NFA) baffles at the top (thereby restricting flow and higher velocities to the upper segment) and gradually increasing the NFA toward the bottom, a more uniform flow distribution may be obtained at each face. This may even reduce the reversed flow, which is highly detrimental to a liquids separation system. The most effective method is to perform iterative CFD by using various combinations of pressure drop vs. superficial velocity, using the Ergun equation4 or Smith and Van Winkle equation.5 Intermediate normal velocity contours may be plotted to check for optimally uniform intake flow fields. The calculated NFA are used to fabricate the perforated plate sections. Exit nozzle considerations. The diameter of the outlet may be sized so that the overall pressure drop does not exceed the process design parameters, and the velocity of the gas flow does not exceed the inlet pipe velocity as it exits the system. A suggestion is to use a diameter that is at least three-fourths the size of the inlet diameter. The liquid outlet at the bottom head of the drum should be sized so that the exiting liquid velocity does not exceed 2 m/s, to prevent vibration and surge-related issues. Sometimes, a filter basket with grating, a bucket, and a weir and panel are used if solids and heavy liquids are expected to be removed. Takeaway. A number of guidelines and considerations are available to meet design challenges encountered during the design of liquid/gas separators. The key criteria are to ensure uniform distribution at the mist eliminator entry and to maximize liquid removal efficiency. Advanced simulation tools and empirical equations are used to ensure that the device is sized appropriately and operates as designed. GP LITERATURE CITED Hinze, J. O., “Fundamentals of the hydrodynamic mechanism of splitting in the dispersion process,” AIChE Journal, Vol. 1, No. 3, September 1955. 2 Kouba, G. E., “Mechanistic models for droplet formation and breakup,” Proceedings of the ASME/JSME 4th Joint Fluids Summer Engineering Conference, Honolulu, Hawaii, July 6–10, 2003. 3 Wallis, G. B., “The onset of droplet entrainment in annular gas-liquid flow,” 1

FIG. 18. Normal velocity contours at entry to each face of the mist eliminator in four-bank housing. Report No. 62GL127, General Electric Co., Schenectady, New York, 1962. Ergun, S. and A. A. Orning, “Fluid flow through randomly packed columns and fluidized beds,” Ind. Eng. Chem., June 1949. 5 Smith, P. L. and M. Van Winkle, “Discharge coefficients through perforated plates at Reynolds numbers of 400 to 3,000,” AIChE Journal, Vol. 4, No. 3, 1958. 4

JALEEL VALAPPIL is a principal process engineer and team lead for the advanced simulation group of Bechtel Oil, Gas and Chemicals in Houston, Texas. His areas of expertise include process engineering, simulation, control and optimization. He is responsible for developing and deploying advanced technical solutions during design, commissioning and operation of various Bechtel projects, including LNG terminals. Dr. Valappil holds a bachelor’s degree from the Indian Institute of Technology in Kharagpur and a PhD in chemical engineering from Lehigh University in Bethlehem, Pennsylvania. PHILIP DIWAKAR is a senior engineering specialist at Bechtel with 23 years of experience in CFD, FEA and acoustic- and flow-induced vibrations. He is a lead specialist in Houston, Texas, responsible for providing solutions for warranty-, environment- and risk-related issues covering several of Bechtel’s business units. To his name, Mr. Diwakar has more than 25 publications, six outstanding technical paper awards, three journal publications and an innovation award for fluid-structure interaction. He has also received technical grants for the design of buildings to withstand explosions in LNG plants, thermal fatigue in dehydrators, fume gas treatment and acoustically induced vibration. Gas Processing | JANUARY/FEBRUARY 201627

GasProcessingConference.com

AMERICAS

September 13–14, 2016 Norris Conference Centers – CityCentre Houston, Texas

Call for Participation Now Open Submit your abstract by March 17, 2016 The second GasPro Americas (GasPro) will be held September 13–14, 2016, in Houston, Texas. We invite you to be an integral part of the discussion, and join engineering and operating management from the downstream, midstream and upstream sectors of the oil and gas industry. If you would like to participate as a speaker, please submit your abstract(s) for consideration. GasPro 2016 will focus on gas supply, procurement, purchasing, transportation, trading, distribution, operations, safety, the environment, regulatory affairs, technology development, business analysis, LNG and more. We encourage you to take advantage of this opportunity to share your knowledge and expertise with your fellow peers in the industry. Submission guidelines: Abstracts should be approximately 250 words in length and should include all authors, affiliations, pertinent contact information, and the proposed speaker (person presenting the paper). Please submit via email to [email protected] by March 17. For more information visit GasProcessingConference.com Questions? Please contact Melissa Smith, Events Director, Gulf Publishing Company, at [email protected] or +1 (713) 520-4475. GasProcessingConference.com

Specific topics to be discussed include: Petrochemicals/methanol/olefins Catalysts Small-scale and modular gas processing Plant design/revamp/grassroots Offshore/stranded gas Separation technology/NGL Field processing/gas treating Metering/custody transfer/ gas transfer Gas compression Operations/maintenance/reliability Safety/environment Pipeline infrastructure/storage Legislative and regulatory compliance (domestic international) Business and market perspectives Economics and finance Training and human capital Integration of global gas markets Project finance Project management/delivery

Organized by:

Risk mitigation LNG (outlook and exports)

Hosted by:

LNG supply chain

TOP GAS PROCESSORS IN NORTH AMERICA

North America’s top gas processors consolidate in 2015 J. STELL, Contributing Writer

By year-end 2015, activities by independent US gas processing companies proved to be nearly as volatile as oil and gas prices. Mergers, dropdowns, acquisitions and divestitures were planned, announced and completed, or scheduled for completion during the 2015 to mid-2016 time frame. Among the slate of activities, upstream players sold off midstream assets, midstream players expanded or contracted and, in at least one event, a downstream player acquired a major midstream company. In another move, a gas processor was forced to shut down a plant because the local gas producer shut in its wells due to economics. Also notable was a midstream operator’s move to export one of the first shipments of crude from the US, thanks to new legislation passed in late 2015. The sector’s trend of moving service-contract agreements away from percent-of-proceeds and into fee-based contracts is continuing. Going forward, industry watchers predict more changes in the midstream sector in 2016. Here, a selection of the most notable deals and projects by some of the top independent gas processors in the US is presented, in alphabetical order by company. DCP Midstream Partners LP. DCP, co-owned by Phillips 66 and Spectra Energy Partners, continues to be the top-ranked gas processor and liquids producer in the US. The company gathers and processes more than 7.1 trillion BTUs of gas daily, and its NGL production is approximately 410 Mbpd, representing more than 17% of all of the NGL produced in the US and more than 12% of the nation’s gas supply. DCP’s asset base includes 63 plants and 66,400 mi of pipeline. In late 2015, its owners gave the company a boost when Spectra dropped down ownership interest in the Sand Hills and Southern Hills NGL pipelines, and Phillips 66 contributed $1.5 B in cash. The transactions will help DCP pay down its credit revolver and support its efforts to convert some of its percentof-proceeds processing contracts to fee-based agreements—a critical step to reduce exposure to gas and NGL price declines. Also in 2015, DCP completed construction of its 200-MMcfd Zia II sour natural gas processing plant (FIG. 1) in Lea County, New Mexico, to serve producers in southeast New Mexico and the West Texas regions of the Permian Basin. In addition to the Zia II plant, the project includes front-end treating for sour gas; two acid gas injection wells; a 50-mi, 20-in. high-pressure trunk line that will intersect DCP Midstream’s existing New Mexico gathering system; and new, high-pressure pipelines and compression assets in West Texas.

After startup, DCP signed a 10-year renewal contract with one of its largest producer-clients in the Delaware Basin. The contract has been converted from percent-of-proceeds to 100% fee-based, and covers approximately 1 MM dedicated acres. The Zia II plant and new gathering systems add to DCP’s existing footprint in the Permian basin, where the company owns and operates 18 gas processing plants. Energy Transfer Equity LP. At press time, Energy Transfer

Equity is moving to acquire The Williams Cos. Inc., with a proposed $37.7 B of financial transactions. In 2015, Energy Transfer Partners merged with Regency Energy Partners in an $18-B deal. The company owns and operates roughly 6,700 mi of gas and NGL gathering pipelines, four natural gas processing plants, 15 natural gas treating facilities, and two natural gas conditioning facilities.

EnLink Midstream LLC. During late 2015, EnLink announced plans to acquire gathering and processing assets in the West Texas Delaware Basin from a subsidiary of Matador Resources Co. for $143 MM. This move by Matador, an upstream producer, is an effort to gain cash in light of low oil and gas prices. As a result, Matador will become a customer of the midstream facilities on 15-year fixed-fee agreements. EnLink plans to spend up to $500 MM during 2016 to expand its Delaware Basin processing and gathering systems, including the installation of a 120-MMcfd processing plant and more gathering lines. Also, the company plans to expand its processing capacity in the Cana-Woodford play in Oklahoma. Artesia Pecos Diamond

NEW MEXICO

Zia II Hobbs Linam Ranch

E. Carlsbad Antelope Ridge Goldsmith Roberts Ranch Pegasus Ozona Guadalupe Pipeline SW Ozona

TEXAS

Eunice Fullerton Spraberry Benedum Rawhide

N E

W S

Crockett Pipeline Sonora

Owners Asset types (vary by color indicating owner) Gathering areas DCP Midstream DCP Midstream Natural gas plant Fractionator DCP Midstream partners Plant under construction and plant Joint venture with others NGL pipeline Intrastate natural gas pipeline

FIG. 1. DCP completed construction of its 200-MMcfd sour natural gas Zia II processing plant in Lea County, New Mexico, to serve producers in the Permian Basin. Map courtesy of DCP Midstream Partners LP. Gas Processing | JANUARY/FEBRUARY 201629

TOP GAS PROCESSORS IN NORTH AMERICA

The sector’s trend of moving servicecontract agreements away from percent-of-proceeds and into fee-based contracts is continuing. Going forward, industry watchers predict more changes in the midstream sector in 2016. Enterprise Products Partners LP. In 2015, Enterprise Products Partners signed an agreement with Occidental Petroleum to jointly develop a new 150-MMcfd cryogenic processing plant pipeline in the Delaware Basin. The JV, Delaware Basin Gas Processing, is targeting a mid-2016 startup date. On December 23, 2015, Enterprise Products Partners announced that it had agreed to provide pipeline and marine terminal services to load its first crude oil export cargo of oil produced in the US (believed to be the first significant oil export shipment from the Gulf Coast in 40 years), now allowable under a law enacted earlier that month. The 600-Mbbl cargo of domestic light crude oil loaded at the Enterprise Hydrocarbon Terminal on the Houston Ship Channel during the first week of January 2016. Keyera Corp. In November 2015, Keyera announced that it

will suspend operations at its Caribou gas plant due to a producer’s decision to shut in gas production wells on December 1, 2015. The Caribou gas plant is Keyera’s only gas plant located in northeast British Columbia, where producers receive NGX Spectra Station No. 2 pricing that has been affected by low North America natural gas prices and regional sales gas pipeline constraints. As a result, gas production in the area has become uneconomical, and several producers have chosen to shut in production until pricing improves. The Caribou gas plant was constructed in 1997 and purchased by Keyera in 2004. In 2015, due to declining throughput, the plant’s contribution to Keyera’s adjusted earnings before interest, taxes, depreciation and amortization became unsustainable.

Kinder Morgan Inc. The company gained processing capacity

in 2015 with its $3-B acquisition of Hiland Partners. The deal in-

cluded fee-based gathering and transportation pipelines, as well as processing assets in the Bakken shale play in North Dakota. Marathon Petroleum. In an unusual move, downstream player Marathon Petroleum acquired midstream assets in an effort to move up the value chain. In December 2015, MPLX LP and MarkWest Energy Partners LP completed a merger by which MarkWest became a wholly owned subsidiary of MPLX. The deal combines the nation’s fourth-largest crude oil refiner and one of the Appalachian Basin’s largest gas processors, creating the fourth-largest MLP in the country based on a market capitalization of $21 B. The transaction provides Marathon with increased vertical integration and a direct supply of NGL for its refining business. The new business combination will help Northeastern upstream producers place the overabundance of NGL into the ready market of Marathon downstream operations, as well as remove the wet gas drilling constraints, thereby allowing producers to support drilling down to a lower price deck. MarkWest plans $1.5 B of annual investment through 2020 to expand its cryogenic processing, fractionation and other midstream assets in Ohio, West Virginia, Pennsylvania, Kentucky, Texas and Oklahoma (FIG. 2). MarkWest is the nation’s second-largest natural gas processor and fourth-largest fractionator, with 34 processing facilities representing around 6.8 Bcfd of processing capacity and 380 Mbpd of fractionation capacity, and more than 7,500 mi of pipeline. The company plans to construct an additional 18 plants in the coming years, including the new Hildalgo plant in the Delaware Basin that will be operational in 2Q 2016. Meritage Midstream Services. Meritage Midstream’s Canadian affiliate, Meritage Midstream Services III LP, entered into definitive agreements with Canadian International Oil Corp. (CIOC) to build natural gas gathering, compression and processing assets, and crude oil gathering assets, to support the development of CIOC’s Montney and Duvernay shale play positions in west-central Alberta. Meritage III will provide 75 MMcfd of gathering and processing capacity, which will be expandable to 225 MMcfd. Construction of both systems began in May 2015. The 42-km high-pressure gas gathering system will deliver rich gas to the new processing plant to be built approximately 60 mi south of Grand Prairie, Alberta. The plant is expected to come into service in April 2016 and will offer connections for residue gas to the TransCanada Pipeline and other delivery points. Navitas Midstream Partners LLC. In September 2015, Navitas Midstream Partners LLC acquired gas gathering and processing assets serving Martin, Midland and Glasscock counties in Texas, from a subsidiary of DCP Midstream LLC. The assets include more than 1,000 mi of pipeline and a 60-MMcfd processing plant in Midland County, Texas. ONEOK Partners LP. By year-end 2016, ONEOK plans to

FIG. 2. MarkWest, which was acquired by Marathon Petroleum, sells all of the NGL purity product produced at its fractionators, including from this plant in Siloam, Kentucky. Photo courtesy of MarkWest.

30JANUARY/FEBRUARY 2016 | GasProcessingNews.com

construct its 100-MMcfd Bronco processing plant in southern Campbell county, Wyoming, which will take gas produced from the liquids-rich Turner, Frontier, Sussex and Niobrara shale formations in the Powder River basin. The $305-MM

TOP GAS PROCESSORS IN NORTH AMERICA facility will include a 65-mi NGL pipeline to connect the facility to ONEOK’s Bakken NGL pipeline lateral. ONEOK’s Williston basin gas processing capacity is expected to increase to 1.2 Bcfd in 3Q 2016. Paramount Resources. In late 2015, Paramount Resources commenced activities to seek a buyer for its midstream assets. The Calgary-based company is working with the Royal Bank of Canada on possible sales or partnerships for facilities that include gas processing plants. First-round bids were submitted in 2015. Potential interest has been discussed, but not formalized, with the Canada Pension Plan Investment Board and Wolf Infrastructure, as well as with Apollo Global Management’s CSV Midstream Solutions. When completed, the deal will serve as another example of upstream companies shedding midstream assets to manage cash flow in the low-commodity-price environment. PennTex Midstream Partners LLC. In September 2015, PennTex began operations at its new 200-MMcfd Mount Olive gas processing plant (FIG. 3) and related residue gas and NGL pipelines, increasing the partnership’s processing capacity to 400 MMcfd in the Terryville complex in northern Louisiana. Sited near Ruston, the facility consists of the processing plant with onsite liquids handling facilities for inlet gas, as well as for additional residue gas and NGL pipelines. The 14-mi residue gas pipeline has throughput capacity of approximately 400 MMcfd and provides market access for residue natural gas from PennTex’s processing plants. The 41-mi NGL pipeline has throughput capacity of more than 36 Mbpd and provides transportation to downstream markets for NGL. It also marks the completion of the second phase of the company’s Terryville complex assets. The first phase of development, which was completed in May 2015, included the 200-MMcfd Lincoln Parish cryogenic natural gas processing plant and 31 mi of related natural gas gathering and residue gas transportation pipelines. PennTex provides midstream services under long-term, fee-based agreements.

Phillips 66. At year-end 2015, Phillips 66 began operations at its new 100-Mbpd NGL fractionator at the company’s Sweeny complex in Old Ocean, Texas. Sweeny Fractionator One supplies purity ethane and LPG to the petrochemical industry and heating markets, and is supported by 250 mi of new pipelines and a multimillion-barrel storage cavern. The company will have the capability to place the LPG into global markets upon completion of its 150-Mbpd Freeport LPG export terminal in 3Q 2016. Tall Oak Midstream LLC. Early in 2015, Tall Oak Midstream reported that initial gas gathering operations were underway on the Tall Oak STACK (which stands for the Sooner Trend, the Anadarko basin, and Oklahoma’s Canadian and Kingfisher counties) systems system. Tall Oak gathers gas on its STACK system for multiple customers, and it commissioned the system’s first processing plant, named the Chisholm plant, in 3Q 2015. The system is anchored by long-term gathering and processing agreements with Felix Energy LLC and PayRock Energy LLC. Targa Resources Partners LP. In November 2015, Targa Resources Corp. (TRC) announced plans to roll up its limited midstream partnership, Targa Resources Partners LP (TRP), into the corporation. When completed, all of the outstanding common units of TRP will be owned by TRC and will no longer be publicly traded, and the incentive distribution rights of TRP will be eliminated. All of TRP’s outstanding debt and Series A preferred units will remain outstanding. GP

FIG. 3. PennTex began operations at its new 200-MMcfd Mount Olive gas processing plant in 2015. Photo courtesy of PennTex Midstream Partners LLC. Gas Processing | JANUARY/FEBRUARY 201631

InstruCalc CONTROL VALVES • FLOW ELEMENTS • RELIEF DEVICES • PROCESS DATA

New Version Available

InstruCalc 9.0 calculates the size of control valves, flow elements and relief devices and calculates fluid properties, pipe pressure loss and liquid waterhammer flow. Easy to use and accurate, it is the only sizing program you need, enabling you to: • Size more than 50 different instruments, • Calculate process data at flow conditions for 54 fluids in either mixtures or single components and 66 gases, and • Calculate the orifice size, flowrate or differential range, which enables the user to select the flow rate with optimum accuracy.

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Control Valve Revisions: • Updated to ANSII/ISA 75.011.01-2012 • Calculation accuracy changed for critical flows • Viscosity correction factor changed • Pressure drop calculation revised to agree with Crane Technical paper No 410. • Option of Cv Units (English) or Kv units (Metric) added. • Option of either aerodynamic noise calculation by ISA 75.17 method or InstruCalc method • Calculation accuracy added (input data within acceptable limits) Relief Devices: • Pressure Relief Devices Program follows API 520 Pt 1, 9th edition dated 7/14 OPERATIONAL IMPROVEMENTS The ability to have more than one calculation open at a time has been added. Each instance of the program is framed in a different color. The user can have multiple “what if” scenarios displayed for making engineering decisions.

Order Direct from the Publisher. GulfPub.com/InstruCalc or call +1 (713) 520-4426.

NEW IN GAS PROCESSING TECHNOLOGY A. BLUME, Editor

Bunkering ship concept approved

Optical sensor for gas analysis

Classification society Bureau Veritas (BV) has granted approval in principle (AIP) to a 4,000-m3 bunkering ship concept developed by French LNG containment manufacturer GTT. The concept is for a bunker tanker that could deliver LNG as ship fuel, using tanks with a GTT Mark III Flex cargo containment system of up to 2 barg. Combining the membrane containment system with the ability to store LNG at pressures up to 2 barg allow the bunker vessel to have a higher capacity and increased operational flexibility. The pressurized membrane tank concept means that LNG bunker tankers can manage boiloff gas (BOG) better, and increase loading and delivery flowrates. Under GTT’s system, BOG management during loading and bunkering operations is made more flexible because of the wide vapor pressure operating range. Vapor can be buffered and condensed in the tanks to help the fueled ship or feeding facility handle the vapor. Condensation may be performed by spraying LNG into the vapor phase. The higher pressure also means that, during voyage and standby mode, a longer duration is seen before gas pressure in the bunker tanker’s tanks reaches the upper limit. This improves the holding time when BOG is not being consumed and reduces the use of the reliquefaction plant, thereby diminishing costs.

Gas composition can change as LNG undergoes treatment and transportation; unaccounted-for changes will negatively impact downstream operations, such as refining and power generation. Therefore, LNG composition must be measured at many points in the supply chain, including gas pretreatment facilities, LNG export and import locations, storage tanks, and vaporization/condensation facilities. Fast, online hydrocarbon composition analysis for C1–C5 alkanes (methane, ethane, propane, etc.) is needed to determine gas quality in LNG transport applications. Gas chromatography (GC) has been the dominant analytical tool for the speciation and compositional analysis of C1–C5 hydrocarbon gas mixtures. GC analytical measurements require between 90 sec and 5 min, and a continuous supply of high-purity carrier gas. As well, the comparative nature of GC requires regular calibration of the analyzer. These characteristics make online deployment of GC tools difficult at best, and frequently impossible. Infrared (IR) spectroscopy is an optical technique that measures the wavelength-dependent absorption of infrared light passing through a sample, and then uses the absorption data to determine sample speciation and composition. It has a long and successful history in industrial online gas/liquid measurement applications. IR spectroscopy is fast (seconds or sub-second measurement time) and provides a direct, first-principles (not comparative or correlative) measurement by using simple, flowthrough sampling configurations that do not require carrier gas or other consumables. These characteristics make it eminently suitable for online analytical applications. At present, IR spectrometers that use discrete optical filter elements (known as nondispersive infrared, or NDIR, spectrometers) are widely used in online applications. NDIR analyzers are robust and effective analytical tools; however, they are not capable of differentiating or speciating hydrocarbon mixtures, such as those in LNG, due to the fact that compound-specific IR absorptions strongly overlap in such mixtures. MKS Instruments has introduced an improvement to conventional NDIR instrumentation: Precisive TFS Tunable Filter Spectroscopy. TFS uses a proprietary tunable Fabry-Perot optical assembly to enable wavelength scanning in preselected regions, coupled with a chemometricbased pattern-recognition algorithm that deconvolves and quantifies multi-component spectra, such as those existing in LNG spectra. This TFS “engine” has been implemented in the new, standalone Precisive 5 hydrocarbon gas analyzer, available in a NEMA4X, IP66rated, Division 2-/Zone 2-certified enclosure for use in various natural gas processing applications. It provides speciated concentration values for methane, ethane, propane, iso-butane, n-butane and pentanes, and uses this data to report calorific values and Wobbe indices for the analyte gas. Optional CO2 and H2S direct measurement channels are also available. The Precisive 5 analyzer is permanently calibrated; requires no consumable gas; and can sample gas at a wide range of pressures, temperatures and flowrates.

www.bureauveritas.com

www.mksinst.com

Gas-block terminal design approved

The Dresser-Rand business within Siemens Power and Gas recently received an order from Elizabethtown Gas for two LNGo natural gas liquefaction systems. The order includes installation and commissioning at the Elizabethtown Gas site. The systems will be sized to produce approximately 13,500 gpd of LNG. Dresser-Rand’s LNGo natural gas liquefaction system is a modularized, portable LNG plant designed to provide onsite liquefaction. This point-of-use production plant is a standardized product made up of four packaged skids: a power module, a compressor module, a process module and a conditioning module. LNGo natural gas conversion plants enable the distributed production of LNG on a small scale. The technology eliminates the need for the costly trucking of LNG long distances.

ABS has granted approval in principle (AIP) for the design of the China National Offshore Oil Co. (CNOOC) Gas-Block (CGB) terminal. The CGB unit functions as an offshore LNG receiving, storage, regasification and bunkering terminal, comprising a concrete caisson structure with a steel roof and steel skirt. The overall structure includes the caisson deck, external transverse bulkheads and external longitudinal bulkheads. The terminal will house horizontal LNG storage Type C tanks and additional processing equipment topside. It is expected to be installed on the seabed with a design water depth of 10 m to 20 m. The storage volume of a single block can vary from 5,000 m3 to 50,000 m3, and the total storage volume can be up to 300,000 m3 when several blocks are combined. According to CNOOC Gas and Power Group, the CGB terminal offers a number of advantages, including modularized construction and installation. The hull, LNG tanks and topside facility can be constructed in a dry dock and then wet-towed to the installation site. Since the steel skirt can be lowered onto and extracted from the seabed, the terminal can be easily relocated from one site to another. Designed-in safety means that the concrete box is capable of sustaining LNG liquid in case of tank leakage, and it features a high load-carrying capacity against wind, wave, current and seismic loads. The AIP scope for the CGB terminal concept included reviewing the feasibility of the structural design of the equipped concrete hull and the global performance in accordance with ABS rules and guidelines for gravity-based LNG terminals. It also provides the parallel main structure analysis of the terminal hull for construction, transportation, operations, seismic, and accidental LNG leaking loading conditions. ABS has been supporting clients involved in gas-related projects—including LNG and LPG transportation, LNG and LPG as fuel, and emerging offshore LNG terminal technology projects— for more than 60 years.

www.dresser-rand.com

www.eagle.org

Order received for small-scale LNG

Gas Processing | JANUARY/FEBRUARY 201633

NEW IN GAS PROCESSING TECHNOLOGY A. BLUME, Editor

Canada opens Sealing parts for gas sweetening largest CNG station Today, refineries and gas plants around the world are processing crude oil and natural (sour) gas containing

An Emterra compressed natural gas (CNG) truck cut the ribbon during the grand opening ceremony, in late October 2015, for the new GAIN Clean Fuel CNG station located in Mississauga, Ontario, Canada. It is the largest public CNG station in the country and was built through a partnership among C.A.T. Inc., Emterra and US Venture Gain Fuel Canada ULC, which owns the GAIN Clean Fuel brand. The station will fuel C.A.T.’s fleet of 100 CNG trucks and Emterra’s fleet of more than 100 vehicles. All GAIN Clean Fuel stations are said to provide easyaccess, fast-fill capabilities.

higher concentrations of hydrogen sulfide (H2S) than ever before. At the same time, global environmental standards demand progressive reduction of H2S content in gas- and oil-based end products. As a result, the hot amine “sweetening” treatments used to remove H2S are becoming much more aggressive to the materials used to seal pumps, valves and other vital process equipment—to the extent that commonly used fluoroelastomer (FKM) and perfluoroelastomer (FFKM) seals are failing more frequently, risking toxic leakage and potentially costly downtime. DuPont Kalrez Spectrum 6380 perfluoroelastomer sealing parts are said to offer outstanding resistance to amines and strong oxidizers at high temperatures in gas sweetening processes. The Kalrez Spectrum 6380 parts exhibit 10 to 15 times lower swell than FKM, and four times lower swell than general-purpose FFKM, in such environments. A major chemical company in France, processing a mix of amines, ethylene oxide and other chemicals at 150°C, has reported a seven times longer seal lifetime when switching to a Kalrez Spectrum 6380 O-ring from a competitive broad-resistance FFKM-grade O-ring. In this actual case history example, the conventional FFKM O-ring survived the hazardous and highly aggressive process conditions for only 15 days before requiring replacement, while the Kalrez Spectrum 6380 part survived for 3.5 months. According to the company, the benefits of installing Kalrez Spectrum 6380 parts have been seen in increased system efficiency, significantly extended mean time between repairs (MTBR), greater reliability, and enhanced safety from the reduced risk of potentially dangerous chemical leaks. Ultimately, this has led to valuable annual savings in reduced total system cost. The use of the Kalrez Spectrum 6380 parts in amine gas sweetening applications can extend mean time between repair for valves and mechanical pump seals, reduce leakage and contribute to reduced maintenance costs and lower emissions. Furthermore, the Kalrez 0090 parts represent another option for this application when high pressure resistance is needed. In laboratory testing for rapid gas decompression resistance, Kalrez AS568-312 O-rings received the best possible rating as per the NORSOK M-710 Revision 2 standard.

www.gainfuel.com

www.dupont.com SALES OFFICES—EUROPE FRANCE, GREECE, NORTH AFRICA, MIDDLE EAST, SPAIN, PORTUGAL, SOUTHERN BELGIUM, LUXEMBOURG, SWITZERLAND, GERMANY, AUSTRIA, TURKEY

Bret Ronk, Publisher Phone/Fax: +1 (713) 520-4421 E-mail: [email protected] www.GasProcessingNews.com

SALES OFFICES—NORTH AMERICA IL, LA, MO, OK, TX Josh Mayer Phone: +1 (972) 816-6745 Fax: +1 (972) 767-4442 E-mail: [email protected]

AK, AL, AR, AZ, CA, CO, FL, GA, HI, IA, ID, IN, KS, KY, MI, MN, MS, MT, ND, NE, NM, NV, OR, SD, TN, TX, UT, WA, WI, WY, WESTERN CANADA Ryan Akbar Phone/Fax: +1 (713) 520-4449 Mobile: +1 (832) 691-6053 E-mail: [email protected]

CT, DC, DE, MA, MD, ME, NC, NH, NJ, NY, OH, PA, RI, SC, VA, VT, WV, EASTERN CANADA Merrie Lynch Phone: +1 (617) 357-8190 Fax: +1 (617) 357-8194 Mobile: +1 (617) 594-4943 E-mail: [email protected]

DATA PRODUCTS J’Nette Davis-Nichols Phone/Fax: +1 (713) 520-4426 E-mail: [email protected]

Catherine Watkins Phone: +33 (0)1 30 47 92 51 Fax: +33 (0)1 30 47 92 40 E-mail: [email protected] Jim Watkins Phone: +33 (0) 1 30 47 92 51 Fax: +33 (0) 1 30 47 92 40 Cell: +33 (0) 6 76 35 11 52 [email protected]

ITALY, EASTERN EUROPE

Fabio Potestá Mediapoint & Communications SRL Phone: +39 (010) 570-4948 Fax: +39 (010) 553-0088 E-mail: [email protected]

UNITED KINGDOM/SCANDINAVIA, NORTHERN BELGIUM, THE NETHERLANDS Michael Brown Phone: +44 161 440 0854 Mobile: +44 79866 34646 E-mail: [email protected]

SALES OFFICES—OTHER AREAS CHINA—Hong Kong

Iris Yuen Phone: +86 13802701367 (China) Phone: +852 69185500 (Hong Kong) E-mail: [email protected]

INDIA

Bret Ronk Phone/Fax: +1 (713) 520-4421 E-mail: [email protected]

JAPAN—Tokyo

Yoshinori Ikeda Pacific Business Inc. Phone: +81 (3) 3661-6138 Fax: +81 (3) 3661-6139 E-mail: [email protected]

34 JANUARY/FEBRUARY 2016 | GasProcessingNews.com

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2016

August 2–3, 2016 Norris Conference Centers – CityCentre Houston, Texas

Final Call for Participation Call for Abstracts Extended

Gulf Publishing Company, publisher of Hydrocarbon Processing and Gas Processing, is pleased to announce that the fourth annual GTL Technology Forum will be held in Houston, Texas on August 2–3, 2016. If you would like to participate as a speaker, we invite you to submit an abstract for consideration by our advisory board. This year’s program will focus on economics of scale and the dynamics of GTL in a low-cost environment.

Suggested topics and areas of interest include: • GTL: Fischer-Tropsch • GTL: MTG/methanol • GTL products: fuels, lubes, specialty products, etc. • Economics, properties, performance, etc. • Floating GTL • Financing of GTL projects by owners, equity, banks • Permitting issues (requirements, thresholds, timing, etc.) • Waste heat recovery • Maximizing wax and chemicals production • Upstream and downstream integration • SynGas generation (SMRs, ATRs) • And more. For a full list, visit GTLTechForum.com

Don’t miss this unique opportunity to share your knowledge and expertise with your peers in the industry. Submission Deadline: March 4, 2016. Abstracts should be approximately 250 words in length and should include all authors, affiliations, pertinent contact information, and the proposed speaker (person presenting the paper). Please submit via e-mail to [email protected]. Speaker/Sponsor/Exhibitor Inquiries: Please contact Melissa Smith, Events Director, Gulf Publishing Company, at [email protected] or +1 (713) 520-4475.

GTLTechForum.com

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