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)

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)

Process manufacturers continue to seek ways to improve their energy efficiency, due to the high cost of energy. Corrosion and solids deposition in boilers, condensers, and steam turbines reduce the efficiency of this equipment and increase energy usage. This can also lead to unscheduled downtime if the conditions persist long enough to cause equipment failure.

One important way to minimize corrosion and the formation of solid particles is to have ongoing, accurate and reliable pH control in the boiler water, boiler feedwater and steam condensate, and main steam (carryover.)

The challenge is that these applications are often very low in conductivity. This is a challenge for continuous pH measurement due to the unavoidable formation of liquid junction potentials in the reference sensor. These cause offsets and instability in the pH measurement.

Emerson's Brian LaBelle, a power industry manager for Rosemount Analytical liquid analytical devices, explained these junction potentials are caused by spontaneous migration of ions from more concentrated to more dilute solution within a pH sensor electrode. What happens is a charge separation occurs among the various ions present. (At the word "ion", my mind raced back to those repressed memories of college chemistry lectures...)

Sometimes a severe junction potential occurs when there is an imbalance of negatively and positively charged ions across the liquid junction found in the basic reference electrode. The lower the porosity of the junction, the greater is the charge separation across this junction.

Sounds like we've gone a long way from the original problem of keep the equipment from corroding and being gummed up with solid particles.

Brian brought me to the solution by explaining that the technology team came up with the solution of replacing the diffusion junction with an open capillary (that's a hole for most of us.) Actually, this is not new or innovative, but what is innovative is that precise, laser drilling on a micro-scale of tens of microns is far more precise than what can be achieved with a twisting, mechanical bit. To minimize the junction potentials and provide more accurate measurement, the optimum capillary is laser-drilled at 25 microns in diameter. This capillary is also tapered outward to the outlet filter to help avoid clogging.

As we depart the micro world of ions and laser holes and return to our world of boilers, condensers, and steam turbines, the pH measurement with the Rosemount Analytical 3200HP pH sensor provides more accurate and reliable continuous measurement to ward off corrosion and solids formation. This means more reliable, efficient operations for this energy-consuming equipment.

Tags: pH measurement | pH sensor | energy efficiency | corrosion | boiler | condenser | steam turbine |

July 19, 2007 in Analyzers, in Boilers, in Measurement | Comments (0)

Recently, a North American chemical manufacturer was having problems with their boilers tripping during startup and shutdown sequences. This problem was caused by a wide variation in the process' demand for steam. This situation caused lost production, which affected the overall plant efficiency.

Jim Dunbar, an Emerson variability management consultant was called in to provide emergency tuning services, to set the loops on the boilers to be able to handle the range in steam demand.

Jim's mission was to work with 2 boilers and about 10 loops controlling these boilers to resolve the situation.

The problem began when the plant installed a new steam-driven compressor that required a minimum steam pressure for operation. The team installed a backpressure controller to satisfy the steam requirements of the compressor. However, the boiler still had to ramp up very quickly to maintain the plant steam header pressure on process unit shutdowns. When the boiler firing-rate was increased too rapidly, the boiler would trip due to low feedwater level.

Jim worked with the plant staff to perform open loop bump tests on the feedwater flow and drum-level control loops. This data was collected in the PI historian and analyzed with the EnTech Tuner. Lambda tuning constants were calculated resulting in much faster and stable drum level control. Next, the boiler master controls were tuned to coordinate the speed of response with the level control. It was important that the firing response was fast enough to meet the requirements of the steam header, but not so fast as to cause an unrecoverable upset to the drum level resulting in a boiler trip.

Since his visit to the site, the manufacturer has not had a boiler trip in over four weeks, despite numerous simultaneous unit shutdowns.

Beyond the improved reliability of the process, Jim provided the operations staff some key insights on what to watch for if instability creeps back into the process.

Tags: boiler | steam demand | backpressure | steam header | lambda tuning |

June 21, 2007 in Boilers, in Process Optimization, in Variability Management | Comments (0)

You might think because I work for Emerson, that I know all the developments going on. Far from it… I try to create this illusion by subscribing to the personalized RSS search over at MyEmerson News, in addition to my RSS subscriptions to the growing number of bloggers in our world of process automation.

The news blurb said:

Vortex technology has traditionally been preferred for measuring flow in saturated steam applications, but users also want a compensated mass flow output. Emerson's new Rosemount MultiVariable Vortex Flowmeter combines the benefits of proven Rosemount vortex technology with a temperature-compensated mass flow output directly from the meter. Besides reducing process variability, the new flowmeter lowers total installed cost of temperature-compensated measurement points by 25%.

Eric described how a temperature compensated mass flow of a vortex meter for saturated steam typically required external sensors and a flow computer to do the calculations. This new multivariable flowmeter includes everything necessary to do the calculations within the flowmeter and send it back to the automation system via HART digital communications, pulse output, or conventional analog 4-20mA signals.

By eliminating these separate components the cost of installation and ongoing maintenance is reduced. Eric calculates the installation cost savings by what is eliminated from externally compensated saturated steam measurements. These include the thermowell, temperature sensor, temperature transmitter, wiring, commissioning, and either separate flow computer or calculations in the automation system.

On the maintenance front, the technology team did something unique by designing a non-wetted temperature sensor in the flowmeter which can be replaced without shutting the process down—always a good thing for plants seeking maximum manufacturing efficiency.

Tags: vortex flow | multivariable | temperature compensation | mass flow | HART |

November 30, 2006 in Boilers, in Measurement | Comments (0) | Trackback (0)

Trying to manage energy consumption and steam usage in a manufacturing process can be a tricky undertaking. The need to do it is ever increasing with higher fuel costs. A recent AEI Environment Policy Outlook study shows the gas and oil price trends over the past 25 years.

The variables operations staff typically must juggle include process load requirements, multiple fuel types, boiler/turbine availability and efficiency levels, and electric buy/sell prices to name a few. Of course, steady state operations are rarely possible because product mix and volumes being produced are normally in flux.

You may recall Bob Sabin, a consultant in Emerson's Industrial Energy Solutions organization, from an earlier post on Chemical Recovery Boilers. Bob discussed how the team of energy consultants works with process manufacturers to develop facility specific models and rule sets to continually determine the optimum operating setpoints for all the process units.

They have packaged their approach into a SmartProcess Energy application that is used to reduce the total cost of energy in a mill/plant by automating critical decision-making. The energy optimization process begins with a review of existing Powerhouse operations and recent operating data. The consultants use off-line modeling tools to evaluate improved operating methods and estimate the level of savings that can be achieved. The effort reviews the fuel alternatives, purchased versus produced power options and constraints, and the current decision making process for optimizing energy and steam production and usage.

Bob said that a key to Emerson's energy optimization approach is extensive data validation to help the application tolerate measurement errors and device failures. The decision making rules for optimum operation are implemented using mathematical models running within the automation system controller.

He pointed to two areas of savings. The first is identifying large opportunities for cost improvement such as changes in fuel type usage. Perhaps more important is the second area, which is the constant small adjustments being made to process setpoints in real-time. This helps move the total operation to its absolute best cost point based on current constraints. These are adjustments that could not easily be recognized by the operators.

The Industrial Energy Solutions team has documented typical annual savings of $500K to $2MM USD where the SmartProcess Energy application has been applied.

Tags: energy usage | energy management | steam usage | powerhouse | fuel types |

August 14, 2006 in Boilers, in Process Optimization | Comments (2) | Trackback (0)

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)