Emerson Process Experts

Emerson's Doug White sent me his presentations from the recent AIChE spring meeting. Doug is a principal consultant and vice president for advanced process control (APC) services, and has many years of experience justifying, designing, installing and commissioning APC applications for process manufacturers.

Given rapid rising energy costs, his presentation, How to Save Energy through Advanced Automation, caught my attention. He starts by showing an upward trend in natural gas prices (in one word—ouch!) Doug makes the point that process energy usage is often the largest controllable cost in most plants.

Doug shows energy flows for process manufacturers in different industries including chemicals, pulp and paper and oil refining. He also gives some typical percentages of the energy flow inputs and outputs. For example, a typical refinery's sources of energy include 1% purchased steam, 25% purchased fuel, 64% raw materials consumed as fuel and 10% purchased power. This energy is used in steam production and central power production in the power plant. In the process and offsites areas, the energy is mainly consumed in the process-fired equipment, direct fuel usage and electric motor drives. Energy not consumed in the process is exported as steam, fuel and power.

Applying better automation and APC can help improve efficiencies around individual equipment like boilers, heaters and kilns (links are to earlier posts where equipment efficiency stories have been chronicled.) Savings can also be achieved at a unit, multi-unit and site level by finding opportunities in optimization, waste heat recovery, and off-spec/waste minimization.

As the earlier percentages indicate, you may have a control loop heavily involved in your plant's energy usage. It may well be worth improving the measurement, control valve performance and loop control performance to reduce variability and energy consumption. Also, your process may have bypasses around production equipment that may be compensating for poor control through the equipment. Optimized control can eliminate the need for these bypasses.

The presentation is loaded with specific examples including stem systems, combustion control, heaters, distillation controls, plant utility systems, facility optimizers, boiler load allocation and site energy balances. Some examples like power boilers include return on investment (ROI) calculations that may assist you in your project justification efforts.

I wanted to highlight some key points Doug makes around heater optimization. If there is resistance in improving heater controls because the damper control is are not reliable, then he recommends adding positioners to the dampers. Bring the feedback to the control system and then analyze and fix any controller problems. If the next objection is on-line analyzers don't exist or are not maintainable, Doug notes that analyzers are cheaper and more reliable, especially mass flow meters. With today's higher fuel costs, these analyzers should be well justified.

There are likely many areas to look for energy savings. Doug recommends a disciplined approach to evaluation and analysis to prioritize the opportunities. Given the increasing costs of energy and the fact that this is often the largest controllable cost in a process manufacturing plant, it may make sense to establish a program around saving energy and apply focused efforts in prioritized projects to reduce overall energy consumption.

Tags: natural gas | APC; | advanced process control | project justification | energy savings | boilers | fired heaters | combustion control | distillation |

May 13, 2008 in Boilers, in Distillation Column, in Energy Management, in Fired Heater, in Lime Kiln, in Process Optimization | Comments (0)

High energy costs continue to prompt process manufacturers to seek ways to increase their energy efficiency. A colleague pointed a great post to me, The Seven Steps to Successful Industrial Energy Management, on the Energy Pathfinder blog.

My take away was that the culture for becoming more energy efficient starts at the top and developing metrics, incentives, and disincentives to change organizational behavior are keys to success.

I thought I'd share this post with Bob Sabin, a consultant in Emerson's Industrial Energy Solutions organization. You may recall Bob from earlier posts.

Bob believes improving the operation of the Industrial Powerhouse can be a large factor in improving overall energy management at process manufacturing sites. The carbon footprint of the powerhouse can be reduced, the reliability and responsiveness of the operation can be increased, and the cost of energy can be reduced—all at the same time.

With this focus (and not to be out done by the seven steps), Bob offers his ten steps to successful Industrial Powerhouse improvement:

1. Obtain top management commitment to improving the carbon footprint, reliability, and cost of operation of the Powerhouse.
2. Benchmark current operations in terms of efficiency, reliability, cost, and emissions.
3. Survey current process equipment, control technology, and operating methods. Create a matrix of factors that are impacting or limiting operating performance.
4. Examine potential process equipment repairs and upgrades that could deliver benefit, rank these in terms of return for investment, and complete repairs and upgrades that will deliver good immediate benefit.
5. Focus on process parameter measurement devices and actuators. Especially for combustion air and fuel flows, ensure that repeatable measurement and control capability exists.
6. Implement full automatic control that is robust and reliable. Even the best operating crews cannot optimize Powerhouse performance every minute of the day for every day of the year.
7. Install optimized control functionality as appropriate to optimize efficiency, prioritize lowest cost fuels, load equipment based on cost, and make economic operating decisions automatically.
8. Change Standard Operating Procedures for the Powerhouse to ensure that process units are run in automatic using the optimized control functions. Make focus of operations identifying and troubleshooting process issues rather than manual process operating adjustments.
9. Regularly benchmark operation in terms of efficiency, reliability, cost, and emissions, repeat steps above when results are not satisfactory.
10. Investigate and consider re-powering the industrial site with lower cost fuels and/or technologies.

Bob and the Industrial Energy Solutions consultants have helped process manufacturers achieve ongoing savings from improved energy efficiency by putting these steps into practice. If your energy costs are higher than they could be, give these ten steps a try or contact the industrial energy team for help.

Tags: industrial powerhouse | process equipment | industrial energy | energy efficiency | energy management |

February 4, 2008 in Energy Management, in Plant Equipment, in Process Optimization | Comments (1)

The Automation.com list server has an interesting thread, Three Element Drum Level Control Problem. The question asked was:

We have a waste heat recovery boiler that is supplied by exhaust of a 20MW Gas Turbine. We've seen that at lower turbine loads (75% and below) the three element drum level controller cannot maintain the drum level at desired setpoint. As soon as the load on the Gas Turbine is increased to more than 75% of rated load, the stability keeps getting better. At rated load (20MW) the drum level is very stable and close to the setpoint.

There have been several responses discussing the tuning at various loads. I asked around to see what advice we might have to offer. Emerson's Jack Tippett, a variability management consultant noted that it is critical to know your process dynamics. His point:

If you don't know the process dynamics, control tuning is an art not a science and good control performance is an accident not a certainty.

Once you know your process dynamics, it is important to design your strategy to assist in achieving the process objectives in light of those dynamics. Jack noted a similar situation from his past where he tuned the levels in a 450-megawatt heat recovery steam generator (HRSG) system.

There were six boilers including two lines with high, medium and low-pressure drums. This power producer was unable to achieve a station ramp rate of 25 MW per minute necessary for automatic generation control (AGC) due to serious swings in the drum levels.

After measuring and determining the process dynamics, the process was re-tuned and they were able to achieve the ramp rate and achieve good level control at less than 70% load.

Jack also noted that they chose a single-element control strategy for the following reasons:

1. Feedwater flow control requires a working flow meter: the sense lines for the flow transmitter were outside and were subject to freezing. The Fisher valve had a DVC positioner and AMS software to monitor incipient valve non-linearities (which are the main reason for the second element.)
2. The open loop dynamics (changing the feedwater valve position manually and watching the response to level) on all six boilers showed very small dead times (1 to 6 seconds). This meant that the proportional-integral (PI) level tuning could be very aggressive. As a result, there was no value in the third element (steam flow feed forward)—the level control could be fast enough to respond the changes in level due to steam demand changes. The real need for the feed forward from steam is when the level dynamics are very slow (30 – 90 seconds dead time) so that the feedwater flow can anticipate the long-term level changes (due to steam demand) in spite of the shrink/swell effect.

By having good measurement in the flow, valve position, and valve characteristics and good understanding of the process dynamics across its operating range, Jack and the plant engineers were able to successfully implement a simple single-element control strategy.

Tags: drum level control | process dynamics | heat recovery steam generator | HRSG | automatic generation control | AGC | single element control |

January 14, 2008 in Boilers, in Control Strategies, in Energy Management, in Variability Management | Comments (1)

A great question came in on the Operating Fired Heaters More Efficiently and Reliably blog post:

Jim I work with natural draft heaters on a daily basis and have initiated several efficiency tests with improved burner internals. I am looking for an opportunity to optimize dual firetube treater by first off improving the combustion efficiency to 80% in each tube and then staggering the temperature controls so that one tube runs 90 to 100% of the time and the other tube only fire during high load requirements.

I sent the comment around our advanced automation consultants for any comments that they might have and I received a great reply from Lou Heavner whom you may recall from earlier posts. Lou describes how to approach optimizing these heaters:

Heater efficiency is calculated using heat loss or input/output method. Input/Output method is difficult because you have to account for lags and delays between fuel firing rate changes and the measurement of process heat absorption changes and in the specific case where there is incomplete phase change on the process side (e.g. partial vaporization) you cannot easily solve with reasonable instrumentation. The heat loss method measures heat loss in the flue gas and assumes any other losses are negligible and constant. If not, they need to be measured and added as well.

Heat loss requires knowledge of the supply air (and fuel) temperatures and the flue gas exhaust temperature as well as the composition of the fuel and flue gas, just like with a boiler. In perfect combustion, there would be no unburned fuel in the flue gas and no sensible heat losses. But due to practical considerations, there are sensible heat losses and to calculate them, you need to know the delta T between the exhaust and ambient and how much excess oxygen remains in the exhaust. Efficiency calculations made using this technique can be pretty accurate in a natural draft heater, but if there is air leakage after the combustion zone, tramp air will show up as lower efficiency due to increased O2. And there is usually an optimum cost operation where the trade-off between sensible heat losses and unburned fuel losses require some level of unburned or incompletely burned fuel leaving in the flue.

When you are ready to control, the goal is to minimize excess O2 while not allowing excessive fuel to go unconsumed. CO analyzers are often used to detect incompletely burned fuel and the goal is usually to keep it below 150 ppm or some lower target. O2 is controlled to stay as low as possible without exceeding the CO limit, which is usually 2% O2 or less for the fluegas.

You can do this with simple feedback control, but feed forward control can help do better. Information on fuel quality, if it varies, and process side temperatures and flows (the heater load demand) can be used to adjust the fuel and air for combustion to meet the heating demand at maximum efficiency. Fuel and air cross limits are often used to maintain fuel and air ratio without getting into a fuel rich condition in the firebox during load changes. But airflow is usually difficult to measure. Therefore, it is often inferred from damper position.

When evaluating an application, we would want to know what instrumentation already exists and what the process variability looks like. What efficiency are they currently obtaining? Then we would look at the control valves and any other contributors to variability to see if they warrant repair or replacement. We would similarly evaluate the instrumentation and analyzers to see if they need anything there.

Then we could evaluate the control strategy and performance and recommend reconfiguration or tuning as appropriate, which may include advanced process control (APC). The person evaluating the controls would have to weigh the cost against the improvement from better loop tuning, valve repair/replacement, CO analyzer, etc. to come up with the best solution. Dampers are often the weak link in fine control of a natural draft heater.

As my colleague Doug Simmers in Emerson's Rosemount Analytical business noted, "The commenter is probably correct with the strategy to fire one heater full out, and bring the second unit on only when needed. Running at full fire develops the best turbulence for fuel/air mixing, and the excess O2 can be kept lower." This is a load allocation problem when two heaters are firing simultaneously. If we can model heater efficiency for each heater as a function of load, then we could optimize the load allocation across both heaters when both must be fired. Actual testing would identify the models, uncover the best strategy, and verify or disprove this assumption."

He may also be interested in the efficiency calculator, developed by Doug's team.

Join the conversation and add a comment if you have experience to share.

Tags: fired heaters | firetube | fuel firing | flue gas | efficiency calculator |

July 23, 2007 in Analyzers, in Energy Management, in Fired Heater, in Process Optimization | Comments (4)

In an earlier post about fired heater efficiency and reliability, I had spoken with Emerson operations consultant, Chris Forland, on the opportunities for refiners to optimize this energy intensive unit.

Working with engineers in the Rosemount Analytical Gas division, Chris has developed a spreadsheet with fired heater efficiency economic calculations which allows refiners to get a rough estimate of the potential value in applying efficiency solutions like the SmartProcess Heater Optimizer.

You can enter data in the cells with blue text for each fired heater in your plant to get a quick assessment. Chris has filled in typical values from a cross section of refineries in case you don't have exact data. This will let you get a feeling for the overall improvement opportunity and if there is enough return on investment to warrant a closer look.

If you have fired heater units in your manufacturing process, give this calculator a try and let us know what you think by adding a comment or contacting us.

Tags: fired heater | economic calculator | refining | refinery | energy efficiency | heater optimizer |

December 4, 2006 in Energy Management, in Fired Heater, in Process Optimization, in Refining | Comments (2) | Trackback (0)

A continuing theme to several of these blog posts is how process manufacturers are looking for ways to improve energy efficiency in these times of high energy costs. One way to do this is to optimize the steam required for a distillation process.

I caught up with Pete Sharpe whom you may recall from an earlier post on reducing costs of APC projects using pre-engineered applications. Pete has recently completed some work for a specialty chemical manufacturer that wanted to improve the performance of the distillation columns by decreasing the steam required and decreasing the reflux flows to the columns.

Pete worked with the process engineers to apply model predictive control (MPC) technology found in the SmartProcess Distillation Optimizer. This application is one of the pre-engineered SmartProcess applications Pete described in the earlier post.

The distillation process is a classic multivariable problem with control variables, manipulated variables and constraint variables.

Using model predictive control, the column can be controlled and operated as a unit instead of a collection of loops.

In addition to reduced operator load, the process engineer identified 400 lb/hour savings in steam on one of the columns and close to 900 lb/hr on the first column where the Distillation Optimizer application was implemented. With a cost for 135 psi steam of $5 per klb, this translates into energy savings of more than $50,000 USD for these particular columns. This savings adds up as all of the distillation columns on site are converted over from multi-loop control to MPC-based control. Steam reductions are a result of lower reflux flows that have been reduced by about 20%. While this change increases the average overhead impurities as is expected, it is well within specifications.

Now that the Distillation Optimizer has demonstrated stable results on two of the columns, Pete is working with the process engineers to implement it on the remaining columns over time. Beyond better performance and increased efficiency, the best measure of the success to date has been operators leaving the MPC control on more than 90% of the time. This is one of the true tests according to Pete and the Advanced Automation Services team.

Tags: model predictive control | APC | MPC | distillation | energy efficiency | steam usage |

June 28, 2006 in Chemical, in Distillation Column, in Energy Management, in Process Optimization | Comments (2)

We discussed improvement of multi-fuel boilers in an earlier post. Similarly, pulp and paper manufacturers often wrestle with chemical recovery boilers because of the complexity of the combustion process. This complexity is largely driven by the variability in the "fuel" (black liquor) and often by swings in production rate.

The variation in the BTU content of the incoming black liquor can cause difficulty in meeting the emissions restrictions, can lead to fouling of the boiler, may impact boiler efficiency, and can limit liquor throughput. Safety is also a major concern around a recovery boiler process.

Bob Sabin, a consultant in Emerson's Industrial Energy Solutions organization described the challenge as maximizing liquor throughput while minimizing the fouling of the upper boiler and maintaining optimal unit thermal efficiency. This can be done if the boiler combustion controls are configured to compensate for liquor BTU changes.

The process Bob and the team follow with pulp and paper manufacturers typically begins with an analysis where they measure the mills operating performance and compare it with world class performance. Some benchmarks include: maintaining excess oxygen at 1.5% to maximize unit efficiency, maximizing liquor throughput to either permit or steaming limits, minimize fouling to require one water wash per year, and running the recovery boiler in fully automatic mode more than 95% of the time.

Through this benchmarking process deficiencies and mechanical design limits can be identified and corrected. The economic benefits of process improvements can also be calculated.

Next a detailed field audit of valves, instrumentation, wiring, and control system performance is performed to find areas requiring attention.

With this assessment completed a complete cost estimate and return on investment calculation and justification can be developed to improve the performance of the recovery boiler. The expertise of the team has been packaged into a SmartProcess Recovery boiler solution which encompasses design, installation, commissioning, start-up, and operations personnel training.

Pulp and paper manufacturers typically experience project payback in three to six months through increased liquor throughput, better thermal efficiency, water wash reductions, and reduced variability in green liquor reduction.

Tags: recovery boiler | combustion | pulp | paper | liquor throughput | thermal efficiency |

June 13, 2006 in Energy Management, in Pulp & Paper | Comments (6)

As process manufacturers grapple with high fuel costs to create the steam for their processes, they often look to increase the use of biomass and alternate fuels in their boilers.

The key measurement is typically the cost per pound of steam. This can be reduced by maximizing the use of cheaper fuels like wood, stoker coal, and other forms of biomass while minimizing the use of natural gas and oil.

I spoke with Chip Rennie in Emerson's Industrial Energy Solutions organization on the control challenges of operating boilers when running non-fossil fuels. These fuels can vary in moisture, consistency of particle size, BTU content, combustion air requirements, and boiler emissions performance limits.

From Chip and the consulting team, well operating multi-fuel boilers can often generate 90% of the plant's steam, operate in automatic control over 95% of the time, minimize carbon in ash, and maintain emissions to specified levels.

Chip stresses the key to optimizing the operation of these boilers begins with an assessment of the mechanical components and instruments. Optimum business results cannot be achieved if these underlying components greatly limit performance. Examples of issues to be resolved include include fuel conveyor changes, fuel bins and distribution equipment, overfire or undergrate air system modifications, fan upgrades, or damper improvements.

Chip and his team have bundled their expertise on multi-fuel boilers into a SmartProcess application and call it SmartProcess Boiler. This application provides complete automatic control of the boiler at all times including start-up, automatically adjusts for changing fuel BTU per volume, and the system allows a multi-fuel boiler to be used as a swing boiler while burning least cost fuels.

The application automates many functions that are often done manually and allows a higher percentage of steam to be generated with biomass or alternate fuels.

Projects are typically done as a turnkey including design, installation, commissioning, start-up and training of the operations staff to run the boiler using the newly optimized equipment, firing methods, and control tools. Given the high costs of fossil fuels today, payback on the entire project is typically 3 to 6 months.

Tags: energy usage | boiler control | multifuel | boiler | biomass | fossil fuels | alternate fuels |

June 1, 2006 in Boilers, in Energy Management, in Pulp & Paper | Comments (10)

Building on my prior mentioned rising energy costs post, manufacturers are looking beyond optimizing their throughput, quality, and plant availability at how they can optimize the use of energy, since this directly impacts their bottom line.

Changing process conditions causes changes to the plant utility system which impacts: power demand, steam demand, fuel balance, emission targets, and the dynamics of the operation. Effectively managing utility system operations must consider the competing economic and production issues in a timely manner to improve the profitability of the production process.

I spoke with Peter Stanley, an Energy Management consultant in the Performance Monitoring and Optimization business unit of Emerson's Asset Optimization division. Steve and the team typically see opportunities for a 2-5% reduction in annual fuel bills by applying an Energy Management application to optimize the utility system. This can translate into as much as 25% of utility annual fuel spend.

The first step is to look at the major areas of energy usage. The first area is in the steam balance which is the steam required to provide heat across the site. Units may be importers or exporters of steam, and the amount of steam produced or consumed changes with throughput and operating mode.

The next area is power balance, again by looking at the importers and exporters of electricity. Many plants have on site generation in addition to what they purchase from the local utility, and can export excess power back to the utility grid.

Fuel balance looks at the mix of fuel gas and waste or by products which have little or no value. The objective is to consume in the lowest cost manner that raises the maximum energy for the process units.

Environmental constraints look at NOx and SOx levels and avoiding the maximum limits based upon the regulatory statutes and availability of emissions trading practices.

In addition to changing process conditions based upon what is being produced, the prices of fuel and power changes. Contractual arrangements for the import or export of electricity, fuel, or steam also impact the optimization.

A final area of consideration is the performance of the existing equipment including the boilers, gas & steam turbines, recovery steam generators, etc.

Building a solution with Emerson energy management experts and the AMS Optimizer, it is possible to continually deter the set of operating setpoints that will allow the utility operations to continually run at its economic optimum based upon all these factors and constraints.

Peter describes the approach where Emerson partners with its customers to deliver a guaranteed level of benefits typically within six months for a completed system. Payment for services and software is not due until the end of the project when the guaranteed level of benefits has been achieved.

Peter stressed that all projects have paybacks within 12 months and Internal Rate of Returns greater than 200%. Support of the optimizer solution is provided with a long term support contract.

It sounds like in an era of high energy costs and a solution with performance guarantees, that this is definitely an area to consider if your manufacturing process consumes lots of energy.

Tags: energy | asset optimization | utilities | steam | fuel | emissions | combustion | AMS |

April 26, 2006 in Energy Management | Comments (0) | Trackback (0)

You don’t have to look too hard to find news stories (here, here, here) of rising oil prices and their impact on process manufacturers around the globe.

Refineries and petrochemical manufacturing processes can especially require vast amounts of energy to process the feedstocks into intermediate or final products.

I spoke recently with Doug White, who leads our advanced automation services consultants for Emerson Process Management. Some of the folks I’ve written about like James, Eric, and Lou are senior consultants in Doug’s organization.

Doug mentioned that one of the units at which refiners and petrochemical manufacturers should take a close look is the fired heater which provides the required heat for the distillation process. In many plants, these units were built 10-15 years ago or more. Most were built in times when natural gas was extremely inexpensive. There was little need for energy efficient designs—so even today they consume energy at higher rates than they could.

He sees these units as a quick way for manufacturers to save costs and improve their bottom lines.

Doug described these opportunities and gives very practical advice on how to get the project assessed, implemented, and sustained in an Oil & Gas Journal article entitled: Advanced automation technology reduces refinery energy costs. Some steps Doug recommends from the assessment phase:

1. Data gathering. Compile information about existing systems.
2. Interviews with plant staff. Find current energy-use problem areas, understand current operational procedures, and stimulate ideas on possible changes.
3. Evaluation of plant energy economics. Understand what are the major users and their costs of operation.

If you are one of the manufacturers struggling with higher energy costs, this article is well worth the read to develop a plan to reduce these high energy costs.

Update: Repaired broken hyperlinks.

Tags: refining | petrochemicals | fired heater | distillation | project assessment | project implementation |

April 3, 2006 in Energy Management, in Fired Heater, in Refining | Comments (0) | Trackback (2)