BOILERS FOR PEOPLE WHO KNOW AND CARE
We ain’t bluffin’. Looks can be deceiving.
Chickens can’t really fly.
And not all boilers are madeTexas-tough to operate reliably and efficiently in a variety of industries. The RENTECH team and its boilers will earn your trust and respect because each boiler is custom designed and engineered to withstand your most demanding environment. So don’t be tempted to saddle up with a greenhorn. Insist that your boiler be built Texas-tough by the skilled people at RENTECH.
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Heat Recovery Steam Generators
|
Waste Heat Boilers
|
Fired Packaged Watertube Boilers
|
Specialty Boilers
www.HydrocarbonProcessing.com NOVEMBER 2010
HPIMPACT
SPECIALREPORT
BONUSREPORT
PLANT SAFETY AND
ENVIRONMENT
Methods to mitigate
CO2 and other air
emissions
LCFS impact oil sands
refiners
US demand for
lubricants increasing
HEAT TRANSFER
New designs foster
efficiency and uptime
BOILERS FOR PEOPLE WHO KNOW AND CARE
We ain’t bluffin’. Looks can be deceiving.
Chickens can’t really fly.
And not all boilers are madeTexas-tough to operate reliably and efficiently in a variety of industries. The RENTECH team and its boilers will earn your trust and respect because each boiler is custom designed and engineered to withstand your most demanding environment. So don’t be tempted to saddle up with a greenhorn. Insist that your boiler be built Texas-tough by the skilled people at RENTECH.
WWW.RENTECHBOILERS.COM
Heat Recovery Steam Generators
|
Waste Heat Boilers
|
Fired Packaged Watertube Boilers
|
Specialty Boilers
www.HydrocarbonProcessing.com NOVEMBER 2010 • VOL. 89 NO. 11
SPECIAL REPORT: PLANT SAFETY AND ENVIRONMENT
31
Stretch in technology and gaps in process safetyfor the hydrocarbon industry
Industry faces challenges to prevent and control hazards
M. S. Mannan
33
Better water management:A crucial and growing requirement Technologies for water reuse and recycling needed now
G. Messina
35
Water among causes for storage tank explosion Reinvestigation uncovers true accident eventsM. Ferjencik and B. Janovsky
41
Consider new analysis for flaresApplying dynamic models in designing safety systems can reduce capital costs Z. Urban, M. Matzopoulos, J. Marriott and B. Marshall
49
Designing the correct pressure-relieving systemUse these relief rate calculations for gas thermal expansion as a cause for overpressure S. Rahimi Mofrad
55
Customize operator training for your thermal oxidizersThis case history shows the benefits of site-specific programs in new equipment installations
T. Gilder, D. Campbell, T. Robertson and C. Baukal
61
Emergency response planning—start at the plant design stage
Follow these guidelines for a safer facility R. Saini
65
Optimized fired heater controlResidual oxygen measurement principle lowers emissions and improves efficiency A. J. Mouris
69
Consider real-gas modeling for turboexpandersNew visualization methods expose problems with traditional designs K. Kaupert
73
Predictive emissions monitoring helps reduce stack air emissionsNew technology reduces compliance costs while optimizing operations R. Hovan
79
Consider switching to Internet protocol surveillanceHere’s a checklist to make the jump M. S. Wilson
Cover The Kårstø gas processing plant on
the west-coast of Norway is the largest of its type in Europe. The installation plays a key role in the transportation and treatment of gas and condensate (light oil) from important areas on the Norwegian continental shelf. Thirty fields are linked to Kårstø via pipelines. Every day millions of cubic meters of gas and non-stabilized condensate flow into the plant, where the heavier components are removed by separation. The remainder, known as dry or sales gas, is exported by pipeline to the Continent.
HPIMPACT
17 LCFS will adversely affect oil-sands crude refiners 17 US demand for lubricants to reach 2.25 billion gallons in 2014 17 Linde supplying hydrogen technology to US BMW plant 18 Oil and gas reservesincreased 3 percent in 2009
COLUMNS
9 HPIN RELIABILITY Wire mesh vs. wire size for temporary strainers 11 HPIN EUROPE Consultants stand by need for swingeing cuts 13 HPINTEGRATION STRATEGIES Future of the collaborative process automation system 15 HPI VIEWPOINT Weighing on dual-temperature control 86 HPIN WATER MANAGEMENT Utility water boot camp for process engineers—Part 3 ENGINEERING CASE HISTORIES81
Case 59: Heat-up rates and thermal crackingA good analysis is usually better than speculation T. Sofronas
DEPARTMENTS
7 HPIN BRIEF • 23 HPINNOVATIONS • 27 HPIN CONSTRUCTION 29 HPI CONSTRUCTION BOXSCORE UPDATE
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4
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7[email protected] BILLY THINNES, NEWS EDITOR
HPIN BRIEF
■
Better gas
storage via MOFs
Natural gas-powered vehicles may soon be able to travel double the dis-tance on a single tank—due to metal organic frameworks (MOFs). BASF research scientists have developed an innovative method for the solvent-free industrial-scale manufacture of those materials for better gas storage. MOFs produced by the new method are currently being trialed for natural gas storage in heavy-duty vehicles.
With their special structure and large surface area, MOFs open up new opportunities for alternative propul-sion systems, in catalysis, as nano-reactors, and in drug delivery, mak-ing them hugely interestmak-ing both for industry and university research.
“This substance class opens up new areas of applications in mate-rial science. We are delighted at this significant advance in industrial-scale production, which is a crucial requirement for the commercial use of these fascinating materials,” said Dr. Friedrich Seitz, head of research chemicals at BASF.
BASF has been working toward industrial-scale synthesis of metal-organic frameworks for the past 10 years. MOFs are highly crystalline struc-tures with nanometer-sized pores that allow them to store hydrogen and other high-energy gases. The larger specific surface area and high porosity on the nanometer scale enable MOFs to hold relatively large amounts of these gases. The pores are adjustable in terms of size and polarity and so can be fine-tuned for specific applications.
Used as storage materials in the natural gas tanks of municipal util-ity vehicles, MOFs offer a docking area for gas molecules, which can be stored in higher densities as a result. The larger gas quantity in the tank increases the vehicle’s range. An advantage of the production method developed by BASF is that it uses no organic solvents. The simple method gives a higher material yield from an aqueous medium and is suitable for existing BASF production plants.
MOFs were discovered toward the end of the 1990s by US chemist Omar M. Yaghi. HP
The US Environmental Protection Agency (EPA) has waived a limitation on selling fuel that is more than 10% ethanol for model year 2007 and newer cars and light trucks. The waiver applies to fuel that contains up to 15% etha-nol—known as E15—and only to model year 2007 and newer cars and light trucks. This represents the first of a number of actions that are needed from federal, state and industry towards commercialization of E15 gasoline blends. A decision on the use of E15 in model year 2001 to 2006 vehicles will be made after EPA receives the results of additional Department of Energy testing, which is expected to be completed in November. However, no waiver is being granted this year for E15 use in model year 2000 and older cars and light trucks—or in any motorcycles, heavy-duty vehicles or non-road engines—because currently there is no testing data to support such a waiver. Since 1979, up to 10% ethanol or E10 has been used for all conventional cars and light trucks, and non-road vehicles.
GE has snapped up Dresser for a cool $3 billion. The deal includes all of the Dresser businesses that provide products and services for compression, flow technology, measurement and distribution infrastructure for customers in more than 150 countries. Dresser’s extensive, global-installed base of products generate aftermar-ket service revenues in excess of 40% of total revenues. Morgan Stanley acted as the exclusive financial advisor to Dresser on this transaction.
Strong Petrochemical Holdings Ltd. has entered into an exclusive marketing agreement with Eurocontrol Technics Inc. Eurocontrol will appoint Strong as the exclusive sole agent to market and sell Eurocontol’s Petromark fuel authentica-tion system to potential customers in China, Hong Kong and other defined target markets throughout Asia. This exclusive agreement is contracted for an initial period of three years and is renewable for further periods of three years. Strong will act as the exclusive sole agent, responsible for the marketing and sale of the products in the terri-tories and Global Fluids International S.A., a wholly owned subsidiary of Eurocontrol, will be responsible for the design and technical support to the consortium. Strong will bring to the consortium its extensive business connections in the target markets with participants in the petrochemical complex.
Petrofac has a contract with the government of Sharjah, UAE, to take over operational responsibility and facilities management of the Sajaa gas plant and related assets, located approximately 30 km from Sharjah, UAE. The five-year contract was awarded following a competitive open bidding process and is worth in excess of $250 million. The government of Sharjah, acting through the Sharjah Petroleum Council, holds a 60% participating interest in the Sharjah gas and associ-ated liquids concession.
Marathon Petroleum Co. LP (MPC) is selling most of its downstream assets in Minnesota to ACON Investments, LLC, and TPG Capital, LP. ACON and TPG formed Northern Tier Energy LLC to operate the assets as a stand-alone com-pany. Included in the transaction will be the 74,000 bpd St. Paul Park refinery and associated terminals, 166 SuperAmerica convenience stores (including six stores in Wisconsin), SuperMom’s LLC, SuperAmerica Franchising LLC, interests in pipeline assets in Minnesota and associated inventories. The total sales value is approximately $900 million, including Northern Tier preferred stock with a stated value of $80 mil-lion. Approximately $300 million of the total sales value is for the inventories associ-ated with these operations. The agreement also contains earnout and margin support components where Marathon could receive up to an additional $125 million over eight years or may be required to provide up to $60 million of margin support to the buyers, subject to certain conditions. HP
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HEINZ P. BLOCH, RELIABILITY/EQUIPMENT EDITOR
HPI
N RELIABILITY
HYDROCARBON PROCESSING NOVEMBER 2010
I
9Even an experienced reliability professional may find some customary terminology dealing with wire gauge and wire mesh to be confusing. Our HPIn Reliability column of April 2009
mentioned pump suction strainers made of 20-gauge wire mesh and a few words about wire gauge will be helpful.
Wire gauge (also known under the alternative spelling “wire
gage”) is indicative of electrical wire diameter, with primary impli-cations for allowable electric-current flow (amperes). According to working tables published for Standard Annealed Solid Copper Wire,1 20-gauge wire has a diameter of 0.032 in. and, at about
40°F, has a resistance of approximately 11 ohms per 1,000 ft of length. While this month’s column has nothing to do with electric current, we want to assume that the 20-gauge stainless-steel wire we would like to see inside the three-mesh guard screen would be woven from wire that has a diameter of 0.032 in.
The terms wire mesh and wire cloth are often used
interchange-ably. They denote a metal wire weave with its various implications regarding available flow-through area as a percentage of the total square inches of wire cloth area. Our April 2009 column meant to recommend placing a wire mesh made from 20-gauge wire inside
a three-mesh guard screen.
So, to clarify: While wire mesh made from 1⁄
32-in. wire is to be
placed inside a three-mesh guard screen, no 20-mesh wire cloth is
involved. The three-mesh guard screen is usually recommended for temporary strainers to reinforce a finer mesh.
• “Three-mesh” means wire cloth (or guard screen in the illus-tration published in April 2009). On a piece of paper, that would be three wires per in. in the x-direction (left-to-right) and three wires-per-in. in the y-direction (up-and-down). Similarly, eight mesh would be eight wires in the x-direction and eight wires in the y-direction; or 200 mesh would be 200 wires in the x-direction and 200 wires in the y-direction, etc.
• In a three-mesh screen there are, therefore, 3 x 3 = 9 openings. • In a three-mesh screen, the distance from the center of one wire to the center of an adjacent wire is 1⁄
3 in., or 0.333 in.
• One manufacturer2 of wire cloth offers three-mesh cloth
made with wires ranging from 0.031 in. to 0.162 in.—in each case, there would be nine openings and the distance from the center of a wire to the center of an adjacent wire would always be 0.333 in.
• If one were to pick the 0.162-in. thick wire, one would have greater strength than if one picked the 0.031-in. wire.
• Likewise, if one picked the 0.162-in. wire diameter, the resulting open area would only be 26%; whereas, if one selected the 0.03-in. wire diameter, there would be an 82% open area.
• For temporary strainers in process pump piping, one would pick a three-mesh guard screen with a wire diameter of about 0.135 in. To reiterate, the wire-to-wire center distance would be 0.333 in. and there would be nine openings. The wire-cloth manu-facturer’s tables (obtained from the Internet2) for this diameter give
an opening width of 0.198 in. (remember that opening width plus
wire diameter equals 0.333 in.). The tables also tell us that we have ~35% of the area open for liquid flow and ~65% of the area would be taken up by the 0.135-in. diameter guard screen wires.
Next, one would determine the wire mesh utilizing the 20-gauge wires. That particular wire cloth, to be placed inside the three-mesh guard screen, should use 20-gauge wire. Reference 2 shows the related wire diameter (0.032 in.) in the middle of a six-mesh table. The openings are 0.1347 in., and adding the two numbers gives us 0.1667 in.—six squares per in.
Using the above information and Fig. 1 will equip us to ask a draftsman to design a pointed cone—the three-mesh guard screen—with a surface area about three times that of the pipe or spool piece cross-sectional area. The six-mesh metal cloth would go on the inside of the cone and only then could we call it a strainer.
On any permanent strainer installation, it would be wise to monitor the delta-p (the pressure drop) between the mesh upstream and downstream sides. Clogged strainers can cause seri-ous machine malfunction and costly damage. HP
LITERATURE CITED
1 Marks’ Standard Handbook for Mechanical Engineers, 7th Edition (1969), McGraw-Hill Book Company, New York, New York.
2 www.mcnichols.com/products/wiremesh.
Wire mesh vs. wire size for temporary strainers
The author is Hydrocarbon Processing’s Equipment/Reliability Editor. A practic-ing consultpractic-ing engineer with close to 50 years of applicable experience, he advises process plants worldwide on failure analysis, reliability improvement and main-tenance cost-avoidance topics. He has authored or coauthored 17 textbooks on machinery reliability improvement and over 470 papers or articles.
90°
Identification tab at top for raised-face flanges. Mount on flange bolts.
Mount mesh made from 20-gauge wire inside a three-mesh guard screen and stagger the longitudinal seams.
Both sides of strainer flange must be free of gouges, weld spatter or other imperfections that might impair proper gasket sealing.
Install gasket on each side of strainer flange. 12-gauge x 1-in. wide
identification tab. 12-gauge ASTM “A” 167 type 316 1-in. ½-in. ½-in.
See detail “A”
Preferred flow direction Strainer assembly Screen section Detail “A” Strainer screen Screen seam Spool piece
Temporary strainer for pump suction piping. FIG. 1
For more information about UOP, visit www.uop.com ©2010 UOP. All Rights Reserved.
refining your profit
UOP helps you exceed your goals with innovative technology, catalysts and optimization solutions specifically designed to meet your needs.
UOP hydroprocessing solutions and optimization services are designed to help you maximize your return on investment and grow your business. As regional market demands shift, we provide the process technologies, catalysts and services that will meet your changing business needs. Our experts work closely with you to meet your desired yields and product specifications including ultra-low sulfur diesel standards while improving your operational efficiency. Backed by over 50 years of hydroprocessing innovations, UOP offers the best and most advanced solutions to keep your business one step ahead.
TIM LLOYD WRIGHT, EUROPEAN EDITOR
HPI
N EUROPE
HYDROCARBON PROCESSING NOVEMBER 2010
I
11 In November 2009, I wrote about how the world’sdown-stream consultants seemed almost to be vying to ring up the most pessimistic prognosis for refinery closures. A year on, there’s little to suggest they were off the mark. Talking to one of them today, they’re just as bearish as they were then. You may recall that JBC Energy in Vienna told me last year that 2.8 mil-lion bpd (MMbpd) of European refinery capacity must close. By February of this year, they increased that estimate by nearly 600,000 bd.
How much to cut? From its work for OPEC, the US consult-ing group, Ensys said that 10 MM bpd of cuts would be required to bring global utilization rates up to 85% by 2020. Energy Mar-ket Consultants (EMC) in London, part of Facts Global Energy, had perhaps the most dire warning, putting the level of necessary reductions at 11 MMbpd by 2020.
This was when I asked Leif Nilsson, the canny trading man-ager at Preem, by then specializing in storing up oil for better times ahead, for his advice for refiners. “Margins are going to be bleak,” he said. “Just try and sit it out.”
Margins are still bleak. Margins have come back some since the depths of the economic crash last year, but they’re still way below the pre-crash glory days. EMC’s variable cost FCC margin is hovering around $1.50/bbl, and, with some cuts of the barrel, it is heavily negative. Refiners have clearly concluded that they need to take action to reduce their exposure.
Shell has announced the closure of one site, albeit at the far extent of the Atlantic Basin in Montreal. It has successfully con-cluded the sale of a German site, Heide, to a private investor, and is said now to be in exclusive talks to sell its Gothenburg, Sweden refinery to a Finnish company with fuel retailing interests.
In its most recent results presentation to analysts, Total reiterated its plans to reduce its refining output by 500,000 bpd by 2011. There was, however, no new information on its long-standing effort to sell the UK Lindsay refinery, or its UK retail network. Meanwhile, Total’s abortive attempt to negotiate redundancies and the closure of its Dunkirk, France, refinery are thought to be what has given some potential investors in Europe’s downstream industry pause for thought.
I hear that Essar of India’s team, which has been looking over key assets like the 246,000-bpd Shell Stanlow refinery, got itchy feet after watching, as on June 30, a French court ordered Total to restart its Dunkirk refinery within 15 days, or face a €100,000 fine.
Hope floats. There are some small signs of light at the end of this dark tunnel. For one thing, a key distillate market is in flux. Heating oil futures have been in contango since the massive
demand destruction that accompanied the 2008 money supply crisis. With no buyers now, futures markets have consistently reflected premiums for oil delivered in the future. It’s a bearish, rather than optimistic, signal, suggesting a belief that things can only get better because they’re so bad now.
In just the last few days, as I write, that structure has flipped around, although just for the coming months before winter. Sud-denly and admittedly compared to a very low baseline, Europe is the top destination for surplus cargoes of distillate. A surge of opportunistic vessel fixtures this week indicated that US and Asian traders and refiners, as predicted in my October column incidentally, are attempting to capture some of a $17/metric ton spread between European ULSD/50-ppm heating oil and spot prices in the US.
Reflecting the improved demand, the OPIS Spot Northwest Europe Gasoil Cargoes to Brent Crude crack averaged $11.24/ bbl for the first three weeks of September this year, compared to $5.74/bbl for the same three weeks a year earlier.
Still too much spare capacity. So when I spoke to Roy Jordan at EMC this week, I asked if he thought the reversed market structure was indeed a sign that things are on the up for European refiners. “Unfortunately, you’ve got to see it in the con-text of a structural surplus of gasoline and an inability to export to the US,” he said. “Yes, that heating oil crack is improved, but you have to see it against very weak fuel, gasoline and naphtha cracks.” Jordan says that the heating oil market, itself driven to a great extent by diesel demand, is Europe’s essential oil. Take that profitable cut away from European refiners, and they might as well shut up shop altogether, he suggests.
EMC’s view of the recent backwardation? “We’ve got it down to the refinery maintenance season,” he says. And so, as EMC prepares new figures for a forthcoming refining outlook, I asked Jordan if EMC is sticking to its guns on the need for cuts. When I last spoke to EMC, they were estimate a need for 7 MMbpd of reductions by 2015, with a further 4 MMbpd necessary by 2020.
“There’s no retreat since then,” says Jordan. “We’re more con-firmed than ever. The spare capacity is enormous and margins are not recovering.” HP
The author is HP’s European Editor and also a specialist in European distillate markets. He has been active as a reporter and conference chair in the European downstream industry since 1997, before which he was a feature writer and reporter for the UK broadsheet press and BBC radio. Mr. Wright lives in Sweden and is the founder of a local climate and sustainability initiative.
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a disposable media system. Plus, with no cartridges or bags to change out, employee exposure to hydrogen sulfide is minimized or eliminated. Amine fi ltration is a key factor for trouble-free sulfur removal. Pipe scale, corrosion, iron sulfi de, sand and other solids build-up in closed-loop amine systems. They foul fl ash drums, heat exchangers, strippers, re-boilers and carbon fi lters and also attract hydrocarbons – which cause system foaming. ClearAmine™ provides an effi cient method of removing harmful solids to protect your investment, extend equipment life, and maximize your amine system’s effectiveness.
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HPI
NTEGRATION STRATEGIES
HYDROCARBON PROCESSING NOVEMBER 2010
I
13Larry O’Brien is part of the automation consulting team at ARC covering the process industries, and an HP contributing editor. He is responsible for tracking the market for process automation systems (PASs) and has authored the PAS market stud-ies for ARC since 1998. Mr. O’Brien has also authored many other market research, strategy and custom research reports on topics including process fieldbus, collaborative partnerships, total automation market trends and others. He has been with ARC since January 1993, and started his career with market research in the field instrumentation markets.
DAVE WOLL AND LARRY O’BRIEN, CONTRIBUTING EDITORS
Future of the collaborative process automation system
ARC conceived the Collaborative Process Automation Systems (CPAS) in 2002 in response to DCS end users’ requests for us to provide a vision of how process automation systems should evolve. Clients and others continue to ask ARC where the automation market is headed. The DCS came on the scene in 1975 and smart field devices arrived about five years later. Since then, ARC has observed incremental innovation, but nothing revolutionary. With this in mind, we recast the request for ARC’s view into the future as an effort to identify innovation we think the market needs to consider in the near future.*
Smart field devices are not smart enough. At present, 50% to 75% of field-device downtime is caused by lack of confi-dence in the measurements. The current generation of smart field devices is capable of communicating basic device diagnostics along with the measurements. While this has been acceptable in many industries, we would also like to see quantitative measurements of the relative health of a device and, if there is an issue, how long
the device will continue to operate dependably.
When will distributed control become truly distrib-uted? Manufacturing challenges are changing, and automation must change to stay in control. We now deal with a high degree of uncertainty in an increasingly dynamic environment. Manufactur-ing assets continue to become more costly to purchase. Expansions to existing manufacturing assets are expensive, and existing assets almost impossible to replace. While automation can be viewed as a solution to a certain degree, these systems could provide more. What have been dubbed distributed control systems in the past are really not all that distributed, since, to a large degree, they still tie functional requirements to architectural constraints.
Future requirements need intelligent agents. Manu-facturing challenges continue to change, and the current IEC 61131-3 standard will not be able to satisfy the execution seman-tics and new requirements for a truly distributed and flexible automation system.
The Technical Committee 65 received a new work proposal (NWP) to standardize application of function block software modules in distributed industrial-process measurement and con-trol systems. The resulting standard, IEC 61499, will facilitate the manufacturing agents that will shape the next-generation automation systems.
Multi-vendor control. The technology exists (or is certainly feasible) to make the basic control system a multi-supplier struc-ture. For example, if the control system LAN were based on FOUNDATION fieldbus HSE, then just like field instruments can come from different suppliers, the process controllers could also come from different suppliers.
Online version upgrade. Process automation system sup-plier has at least one major version release every year. Unlike a maintenance release, a version release usually requires the system to be taken out of service (thus interrupting production).
With most of today’s systems, it’s possible to perform a two-step version “hot” upgrade without shutting down by loading the new version into the redundant side, then committing the new software to the primary side of the system and the process. We feel that this is unreasonably risky and only marginally practical. We feel a three-step approach where the changes can be validated is reasonable.
Business-to-operations integration. Normally, integrat-ing two different systems, especially systems as diverse as a business and manufacturing system, can be complex and difficult. This is where Reference Standards can make a major contribution. Their primary value is that they contain well-understood and well-doc-umented work processes that lead to handing off proper informa-tion. Several years ago, several senior practitioners on the business and manufacturing sides recognized the value of integrating Supply Chain Management Consortium reference model (SCOR) with the manufacturing reference model, ISA-95, and have began to address the problem.
Application executive of the future. The application executive, a core CPAS function, monitors the health of applica-tions running in a collaborative and synchronized manner with other applications, the system itself, and the personnel using the system. Today, this is accomplished largely in an environment combining proprietary structures, de facto standards and enabling technologies.
One potential scenario for the future of the application environ-ment is to have this completely based on standards such that no single supplier has to “own” the environment or platform for it to function properly. In this future vision, the user would purchase applications from the supplier that provided the best fit for the required functions. It would be loaded into the system and would auto-configure to adapt to the operating system, communications protocols, and whatever hardware requirements are present. HP
*Note: Readers can visit www.arcweb.com/res/cpas for more
information on ARC’s latest research into CPAS.
Larry O’Brien is part of the automation consulting team at ARC covering the process industries. He is responsible for tracking the market for process automation systems (PASs) and has authored the PAS market studies for ARC since 1998.
Dave Woll is a vice president of consulting at the ARC Advisory Group. He has been associated with defining and applying process automation for over 35 years. Mr. Woll is currently focused on assisting major users developing their process auto-mation system strategies.
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Tim Lloyd Wright is HP’s European Editor and has been active as a reporter and conference chair in the European downstream industry since 1997, before which he was a feature writer and reporter for the UK broadsheet press and BBC radio. Mr. Wright lives in Sweden and is founder of a local climate and sustainability initiative.
HYDROCARBON PROCESSING NOVEMBER 2010
I
15 I’d like to weigh in again on the continuing debate regardingdistillation column control.1–4 Attention has now turned to the
practicality of “dual temperature” control,which is the simultaneous control of temperature on both the overhead and bottoms of a dis-tillation column, typically with top temperature cascaded to reflux flow and bottom temperature cascaded to reboiler heat input.
My short answer agrees with Zak Friedman: Beware, all ye who
wander here! Attempting dual-temperature control is most often
undertaken by those oblivious to its perils. Industry is littered with its wreckage in the form of columns configured for dual-temperature control, but with one of the controls abandoned— either the reflux or reboiler is operated in automatic or manual mode, not cascaded. This is unfortunate from both composition control and energy conservation points of view.
The lesson from all the wreckage (and from this debate) is that successful dual-temperature control takes more preparation than most casual control strategy reconfigurations get. Appropriate preparation in this case would include a rigorous simulation of the several variables that affect overall separation because dual-temper-ature control really means controlling one temperdual-temper-ature plus overall
separation (think Δ-temperature between the top and bottom). For practical purposes, separation is usually considered con-stant. When Mr. Shinskey or Mr. Friedman points out that a one-degree change in bottom temperature will result in approximately a one-degree change in the overhead (Δ-temperature remains the same), this is another way of saying the same thing. If separation is constant, it cannot be controlled, and therein is the problem that many people fail to realize, at least initially. To the extent that overall separation does vary, it is usually due to uncontrollable fac-tors, such as feedrate and quality, rather than controllable ones.
That said, if you have the luxury of controlling feed or a feed
analyzer, responsive pressure control, which affects vapor veloc-ity and tray efficiency, ) excess stages, a reliable simulation, good operators and economic or equipment limitations that prohibit doing the split in two columns, then perhaps dual-temperature control is worth a try. That’s my long answer, which more agrees with Shinskey, and which can be shortened to: if it must be done, it might be possible!
A third answer worth mentioning is that the traditional
solu-tion (or compromise) to this dilemma is to put one temperature
control on the top or bottom (whichever purity is the higher prior-ity or harder to achieve) and operate the other end of the column on ratio control. This results in good stability, depending on feed and other variables, and keeps energy consumption in check. The ratio is usually reboiler heat-to-feed (when top temperature is controlled) or reflux-to-feed (when bottom temperature is controlled).
The latter option (reflux ratio) has a couple “material balance” risks. If all the light material is not removed with the distillate, it can accumulate in the overhead and lead to erratic pressure and temperature behavior. It’s possible to run the reflux drum empty.
There are no such limitations with the former option (reboiler ratio), and indeed, it is probably the single most common (success-ful) column control configuration in the industry. It’s not as good as the grail of stable dual-temperature control, and is a good mea-sure better than running the reflux or reboiler at a fixed setpoint, both in terms of constant separation and energy conservation.
Yet another answer is special cases. On columns that have
side-draws, additional boil-up does not ultimately return as reflux, so dual-temperature control can work well. This is well known on main fractionators that often have several temperature control-lers—top, bottom and side-draws. Occasionally, side-draws are found in other processes on true distillation columns, as well.
Another special case, although it’s also a trick answer, is dual-temperature control where the would-be-ratio controller is replaced with a proportional-only temperature controller with feedforward
signal. This provides for minor adjustment based on temperature deviation, but without the integral action that leads to wind-up and instability (although it is still easy to get instability if gain is set too large). The feedforward signal serves the role of the original ratio control. In my experience, this does not improve matters noticeably, but it can please other stakeholders (who don’t “get” the limitations) to see the controller at least make an effort, and it makes it easy to switch between top and bottom ratio control, especially without impacting data historians, documentation and graphics, since the temperature control tags persist either way.
A final point in the debate has been model-based multivari-able control (MPC) and whether it changes the game. Arguably,
where dual-temperature control is feasible, model-based control has a better shot of keeping it in the window, based on its aware-ness of all the variables affecting separation (not just the relative gains of the two temperature controllers). But my experience is that neither MPC nor inferentials (which are essentially tempera-tures) change the (un)likelihood of success and many late-model MPCs exhibit similar modern day wreckage in the form of the reflux or reboiler MVs that are “clamped” or “out-of-service.” Some things never change! HP
LITERATURE CITED
1 Friedman, Y. Z., “Distillation column dual-temperature control, Hydrocarbon Processing, March–April, 2010, (letters, August 2010).
2 Kern, A. G., “More on APC designs for minimum maintenance,” Hydrocarbon Processing, December 2009.
3 Friedman, Y. Z., “APC designs for minimum maintenance,”Hydrocarbon Processing, June–August, 2009 (and letter by P. R. Latour, October 2009). 4 Greg, F., “Multivariable control of distillation,” ControlGlobal.com, May–July, 2009.
Weighing on dual-temperature control
[email protected]ALLAN KERN, GUEST COLUMNIST
HPI
VIEWPOINT
The author has 30 years of process control experience and has authored sev-eral papers on inferentials, expert systems, advanced controls and decision support systems, with emphasis on practical process control effectiveness. Mr. Kern is a professional engineer (inactive), a senior member of ISA, and a 1981 graduate of the University of Wyoming.
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HYDROCARBON PROCESSING NOVEMBER 2010
I
17HPI
MPACT
LCFS will adversely affect
oil-sands crude refiners
Purvin & Gertz, Inc., has released a report on the effect low-carbon-fuel standards (LCFS) will have on oil sands. The report notes that LCFS programs are being implemented in California, Oregon and British Columbia. They are under consideration in many other states and provinces and are becoming regional in nature. LCFS programs dif-fer by jurisdiction, but have in common mandated reductions in the carbon inten-sity of transportation fuels. By targeting petroleum-derived gasoline and diesel and promoting low-carbon alternative energy forms such as electricity, hydrogen, natu-ral gas and next generation biofuels, LCFS programs are intended to reduce overall greenhouse gas (GHG) emissions on a “well-to-wheels” basis.
“In effect, LCFS programs contribute to an ‘off-oil’ strategy,” said Tom Wise, who directed the study.
The energy needed to produce oil sands crudes is higher than for most con-ventional crudes, so the resulting carbon intensities of refinery-produced gasoline and diesel from oil sands are also higher. Tom Wise points out it is a mistake to paint all oil sands crudes with the same brush because there are different oil sands crudes, such as synthetic crude oil and bitumen blended with various diluents, and each has a different pathway and car-bon intensity.
“Contrary to widely held perceptions, our study concludes that some oil sands diluted bitumen does not have high carbon intensity under the California regulations and should not carry an LCFS penalty,” Mr. Wise said.
The Purvin & Gertz study estimates the well-to-wheels carbon intensities of refinery-produced gasoline and diesel from various oil sands and conventional crude oils. The study estimates the impact on consumer product prices, refinery mar-gins and oil sands crude prices, for a range of LCFS carbon costs. In market regions that implement LCFS programs, consumer product prices will increase and refinery margins will fall.
“Some of the oil-sands crudes would require price discounts to compete with conventional crudes due to a reduced incen-tive to refine or upgrade heavy crudes,” said Mr. Wise.
Further, reduced crude runs in market regions with LCFS programs could result in refinery closures and displace oil sands crudes to other markets. For instance, LCFS programs in the US Midwest would cause leakage of oil sands crudes to the US Gulf Coast or Asia-Pacific.
US demand for lubricants
to reach 2.25 billion
gallons in 2014
US demand for lubricants is forecast to expand 1.3% annually to 2.25 billion gallons in 2014, valued at $22 billion. This represents a significant improvement over the performance of the 2004–2009 period, when lubricant demand declined 5% annually. A turnaround in motor vehicle production, along with an accel-eration in the number of automobiles in use, will support demand for automotive lubricants. Additionally, increased manu-facturing output will drive demand for industrial lubricants. However, total lubri-cant consumption is not expected to reach pre-recession levels. This will largely be due to the greater use of longer-lasting, higher-performing synthetic lubricants that extend drain intervals, therefore reducing overall lubricant requirements in volume terms. Average price increases will continue to be significant due to expected growth in crude oil prices and a shift in product mix toward higher-value lubricants. These and other trends are pre-sented in a new study from The Freedonia Group, Inc.
Engine oils accounted for more than half of total US lubricant demand in volume terms during 2009. A significant rebound in motor vehicle output following the dou-ble-digit annual declines of the 2004–2009 period will propel engine oil demand in the factory-fill segment. However, this rep-resents only a small fraction of engine oil demand, and the overall outlook for these products will be restricted by lengthening oil change intervals and the use of high
performance synthetic lubricants. As such, aftermarket demand will decline, with the “do-it-yourself ” segment continuing to lose out to “do-it-for-me” services, a trend that stalled in 2008 and 2009 as drivers sought out more economical alternatives for their vehicle service needs during difficult eco-nomic times.
Process oils—including white oils, rubber oils, electrical oils, ink oils, agri-cultural spray oils and defoamer oils—rep-resent another leading lubricant category. Demand for these products is forecast to advance at the most rapid pace, promoted by rebounding manufacturing activity fol-lowing the real (inflation-adjusted) declines of the 2004–2009 period. In particular, an improved outlook for food and beverages, chemicals, plastics and rubber will offer good growth opportunities. However, pro-cess oils will continue to encounter chal-lenges brought about by changing environ-mental and regulatory standards.
Linde supplying
hydrogen technology
to US BMW plant
The Linde Group will provide the BMW Manufacturing Co. plant in Spar-tanburg, South Carolina, with a hydrogen fueling system for its material-handling fleet. An according agreement was signed in mid-August 2010. More than 85 pieces of material-handling equipment are hav-ing their lead acid batteries replaced with hydrogen fuel cells. The trucks deliver process parts to assembly areas throughout the plant. After the conversion, this part of BMW’s internal logistics will be completely emission-free.
“This is one of the largest hydrogen applications of its kind,” said Dr. Andreas Opfermann, head of innovation manage-ment of The Linde Group. “We are proud to work together with BMW, supplying both a high-efficiency fueling system and hydrogen with almost no carbon footprint. This project clearly shows the potential that hydrogen offers for internal logistics.”
Refueling at the six indoor dispenser stations will be facilitated by Linde’s ionic compressor fueling system, combining efficiency and high throughput with
low-BILLY THINNES, NEWS EDITOR
HPI
MPACT
18
maintenance costs and low noise compres-sion. The hydrogen supplied to BMW, a byproduct from a chemical plant, is puri-fied, compressed and liquefied by Linde using electricity produced from renewable hydropower.
“We have a clear vision and we are deter-mined to reach our goal of using renewable energy as much as possible throughout the plant site,” said Josef Kerscher, president of BMW Manufacturing. “We realize this is
an ambitious goal and the hydrogen fuel cell project puts us another step toward ful-filling our vision.”
BMW is able to boost productivity in two ways: Refueling these trucks with hydrogen takes an operator less than three minutes, compared with about 20 minutes to change out a battery. These units, when full, run on 2 kilogram fuel tanks and oper-ate for 8–10 hours. Also, fuel cells do not lose power over time, as lead-acid batteries
do toward the end of a shift. BMW is also able to reduce its total electricity demand, since no battery recharging is required, and eliminate the environmental disposal costs for lead acid batteries.
Oil and gas reserves
increased 3 percent
in 2009
The worldwide upstream investment of 224 oil and gas companies decreased 23% to $378 billion in 2009, according to a report released by IHS Herold. Although development spending fell nearly 20%, the first decline in a decade, total hydrocarbon reserves increased 3% as both oil and gas reserves grew for the first time since 2005. Production also increased 1%, driven by a 2.2% increase in natural gas output.
“We were very surprised at the strength of reserve additions given the weak eco-nomic conditions and tightness in credit markets during 2009,” said Nicholas Cac-chione, director of IHS Herold and author of the report. “As an industry, we spent fewer dollars, but they went further in terms of purchasing power.”
Oil reserves reversed a two-year decline, rising 3% to 164 billion barrels. The main driver was 8.6 billion barrels in positive reserve additions, but extensions and dis-coveries in the Canadian oil sands and South and Central America also added a record 7.9 billion barrels. Natural gas reserves climbed 3.7% despite a record 11.4 trillion cf in negative reserve revisions, as development of unconventional plays in North America and liquefied natural gas (LNG) resources in Asia accelerated.
The decline in capital spending was led by a 40% reduction by E&P companies, while the integrated oil companies cut investment by just 9%. Exploration spend-ing was most resilient, droppspend-ing just 12% to $62.7 billion. In contrast, unproved acquisition costs were down 71%, and a 2% dip in proved acquisition outlays would have fallen 50% were it not for the $20 billion Suncor/Petro-Canada merger.
“With the recession and ongoing uncer-tainty in the market last year, companies put acreage acquisition on hold and seemed to focus on their in-house development opportunities,” said Mr. Cacchione. “This decision, I think, reflected their desires to monetize known holdings that can be brought into production much more rap-idly than something with a less certain pay-out several years down the road.”
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Lower capital spending and higher reserves resulted in a near 50% decrease in reserve replacement costs (to $11.41/boe) and lowered finding and development costs to $12.23/boe. Strong natural gas reserve additions led reserve replacement rates to the highest levels in five years.
Despite the strong performance metrics, upstream profits plunged 47% as a 13% decline in pre-tax expenses did not offset a 30% reduction in revenues. The integrated
oil companies accounted for 85% of the universe’s profit with the E&P companies accounting for the balance. Reserve write-downs slashed net income for the large E&P companies and drove the mid-sized and small E&P companies to a loss. However, the industry generated free cash flow due to the steep decline in capital investment.
The IHS Herold report found that dividends rose modestly to another record level, which it noted “is remarkable” given
the turmoil in the financial markets and the generally miserable results in the indus-try’s downstream operations. Dividends exceeded $100 billion, but common share repurchases were 23% lower, falling for the first time since 2004. Capital constraints brought about by reduced revenue and ris-ing costs have almost completely eliminated share buybacks as a viable use of funds.
Key regional findings of the report include:
• Strong drill-bit additions aided improving results for reserve replacement costs and rates in the US. Unit profitabil-ity declined for the fourth consecutive year. Mineable bitumen reserve additions in Canada offset weak natural gas reserve additions. Profits were down sharply in Canada as well.
• Oil and gas reserves in Europe con-tinued to decline as companies redirect cash flows to other regions. The reserve replacement rate reached a five-year high through improving reserve additions, but the region was still below full reserve replacement figures.
• Capital spending in the Africa and Middle East regions was down 14%, which was much less than the worldwide average. This drop in spending is due to regional dominance by the integrated oil compa-nies, that tend to spend through the com-modity cycles.
• Asia-Pacific reserves gained 3% as nat-ural gas extensions and discoveries surged. Reserve replacement rates in the region were well above full replacement levels.
• Capital spending in South and Cen-tral America increased since regional play-ers have strong development portfolios to exploit. Total reserves in the region increased 3%, the first gain in several years.
• An uptick in proved acquisition spend-ing limited total capital spendspend-ing decline to 17% in the Russia/Caspian region, while drill-bit spending outlays fell 22%. Pro-duction in the region increased 18%, with strong results from both oil and gas output.
IHS Herold anticipates a modest global rebound in upstream capital spending in 2010.
“In North America, E&P investment increased 30% in the first half of 2010, which was higher than expected,” Mr. Cacchione said. “We think this should drive a global investment increase of more than 20% for the year. Outside of North America, where spending declines were less severe, we foresee upstream investment ris-ing about 10%.” HP ?lek\i9l`c[`e^j`jk_\nfic[c\X[\i`e k_\gif[lZk`fef]hlXc`kp$\e^`e\\i\[#
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