1995: retrofitting the ammonia plant with integrated turbine … · 2018. 8. 22. · triconex...

Retrofitting the Ammonia Plant withIntegrated Turbine-Compressor Control

Consolidating diverse controls for major process compressors, steam turbine prime movers, andassociated pressure reducing valves in a single triple modular redundant control system can reducevariations in steam and process headers significantly. This integrated digital control system also can

reduce the risk of unsafe process operation and provides primary electronicoverspeed trip to steam turbines.

Thomas R. Bailey and C. Scott HarclerodeTriconex Systems, Inc., La Marque, TX 77568

Introduction

I

ince the early 1960s, a number of ammoniaplants designed by M.W. Kellogg have beenconstructed and commissioned all over the

world. Large centrifugal compressors perform a cen-tral role in the manufacturing process in all theseplants, as well as those designed by other firms.Because of the importance of these machines and theirsteam turbine prime movers, any means of improvingtheir performance and reliability elicits attention. Theapproach to improving ammonia unit operation andreliability described in this article is through the use ofintegrated digital controls.

The phrase "integrated turbine-compressor control"has come to be used when describing a digital controlsystem that not only controls the turbine, i.e., a gover-nor, but also performs the compressor load control andantisurge control (Gaston, 1995). At first glance, thisapproach may seem odd, but there are a number ofdevelopments in the industry that have made it simplya logical next step.

AMMONIA TECHNICAL MANUAL 305

Factors Influencing Integration Trend

There are five main factors that are changing theway large process compressor control projects arebeing handled. First, the current generation of digitalelectronics provides sufficient computing performanceto consolidate all turbomachinery controls in one sys-tem. Another important reason for consolidatingprocess controls in a single system is the new fault-tolerant architectures. In some cases, as with theexample installation described below, a 2-out-of-3 vot-ing architecture called triple modular redundancy(TMR) is being employed (Figure 1).

Figure 1. TMR integrated turbine-compressorcontrol system.

1996

Reliability improves with the combination of controlsin a single "box" rather than using two "boxes".Additionally, costs of dealing with a single supplierare normally lower. Finally, in today's competitiveenvironment, there is a new willingness for companiesto examine historical reasons for doing things a certainway and departing from those procedures that nolonger make business sense.

Reliability

While many are familiar with the arguments forusing voting control systems for turbine or compressorcontrol systems, there is another, less subtle, improve-ment in reliability that results from using only one sys-tem for control. To illustrate this point, suppose aredundant turbine control system, which has a meantime to failure (MTTF) of 100,000 h (12 yr), is appliedto a turbine-driven ammonia refrigeration compressor.Further suppose that a redundant compressor perfor-mance and antisurge controller, which also has anMTTF of 100,000 h, is applied to the compressor sec-tion. These two systems can be contrasted with anintegrated system using the same turbine control sys-tem mentioned above, but adding only I/O to includethe compressor controls instead of adding anotherindependent system. To be conservative, the additionalI/O is arbitrarily assigned a short MTTF of only 4times that of the entire rest of the system. Often,enough spare I/O, with the possible exception of ana-log outputs, exists in a system to add surge protection.

To compare the two systems, the MTTFs are con-verted to the common notation of failure rates byinverting MTTF and normalizing to 106 h (MIL-HDBK-2I7F, Notice 1,1992):

= 1/MTTFTC (1)

where the units of ̂ are failures per million hours (seeFigure 2).

The combined failure rate is then the sum of the twoindependent failure rates. This is a reasonable assump-tion because most failures are managed by the redun-dancy and do not cause a system failure. On average,though, once every 12 years, a fault may occur thatwill be serious enough to bring down the redundant

system (this is not a TMR failure rate). Most failuresthat could shut down a redundant controller, whetherthe turbine or the compressor controller, would requireshutting down the unit. What is clear is that, if thealgorithm is properly executed, the single system has abetter failure rate. The combined MTTFs (inverting

are 50,000 h (~ 6 yr) and 80,000 h (-10 yr).

Performance

Another attribute of advanced microprocessor con-trol is that more sophisticated algorithms are appliedto the control of the entire machine. The system canexploit the dynamic coupling between these machinesif a single control program incorporates all controlfunctions and sequence logic. For example, if a majordisturbance occurs which lowers dramatically the suc-tion header pressure, a normal pressure cascade con-trol loop may lower the speed setpoint to the turbinecontroller to reduce the flow out of the suction header.If, however, the compressor is operating close tosurge, the process header controller is doing exactlythe wrong thing and may actually drive the compres-sor into surge by calling for reduced speed. In fact, thecontroller must be designed to first increase the speedto secure the compressor operating point by adjustingthe recycle valve then, if still necessary, slowly reduc-ing speed to increase the suction pressure.

In addition, the antisurge approach uses the pressureratio method to closely approximate sonic velocitycompensation of the Hp vs. Q2 performance/surgemap. It establishes a universal surge curve that isinsensitive to changes in speed, molecular weight, orsuction temperature, and average compressibility.

20fail.*10*hrs

J.nc= 12.5fail.»10jshis

Figure 2. Reliability comparison of integrated sys-tem and two independent systems.

AMMONIA TECHNICAL MANUAL 306 1996

Costs

Finally, cost-effective management is contributing tothis trend. There are usually fewer costs associatedwith managing a single supplier than with administer-ing two or more suppliers. A qualitative look at costreductions turns up the following areas: reduced pro-curement effort (RFQ/bidding process), smaller com-bined system (less floor or rack space), simpler com-munications interface between controllers or with aDCS, more straightforward training requirements,fewer spare parts to inventory, lower project executioncosts, and better contractual accountability.

Example Ammonia Plant Project

A typical ammonia plant upgrade is offered here asan example because of the broad applicability of itsturbomachinery to other process plants in the chemicalprocessing and refining industries. The scope of theintegrated turbine-compressor (ITC) control systemcovered by this article is the following:

• Air machine (four stages) and its steam turbinedriver

• Ammonia refrigeration compressor (three stages)and its steam turbine driver

• Syngas and recycle compressors (three stages) andtheir extraction steam turbine driver

• High pressure (1,500-psig, 10.3-MPa) to interme-diate pressure (545-psig, 3.8-MPa) reducing valve

• High pressure (1,500-psig, 10.3-MPa) to interme-diate pressure (545 psig, 3.8-MPa) steam dump valve.

Extncaon Syngas ft RecycleSt«.in. TurWi» Compressor (3 stag*»

Steam RefrigefiHoo Compreiwr SteamTurbiw (3 tfCflM) Tirtina

Figure 3. Ammonia process machinery controlsystem.

In addition to the functions provided above, a secondTMR system was used to execute all BSD functionsincluding the primary overspeed trip protection forthese machines (Figure 3).

Specific Requirements

Because the control system upgrade was only part ofa larger effort to increase the capacity and reliability ofthe unit, a number of other activities were going on inparallel. The additional capacity reduced the perfor-mance margin on some of the process equipment.Where manual operation was acceptable previouslyas the throughput increased, operators found that themanual approach to loading the machines and control-ling headers was not as effective as before. It wasthought that the unit suffered too many trips that wereinitiated by process disturbances. As a result, bettercontrol was seen as a fundamental aspect of the pro-ject. To this end, a DCS system was installed to opti-mize the different parts of the process and to provideoperators with an automatic turbine-compressor con-trol system. Another important objective was stabiliz-ing the 545-psig (3.8-MPa) steam supply, which wasused by the plant and exported for sale to neighboringprocess plants. Finally, instrumentation was added toensure that there were no single points of failure.

New Control System

The TS3000 integrated turbine-compressor controlsystem installation can be examined by looking at thefour major areas: control system hardware; operatorinterface; new instrumentation and actuators; controlsystem software.

Hardware

The specific control system employed in this case isthe TS3000 TMR Integrated Turbine-Compressor con-trol system, manufactured by Triconex Systems, Inc.of La Marque, TX. This system has been used for over100 critical turbine control systems and used foraround 1,000 emergency safety shutdown systems forvarious industries. The TMR controller uses a two-out-of-three voting scheme for detecting and masking


faults. It provides for on-line repair of a failed modulewhile the other two channels continue to control theprocess. Diagnosis of failures is as easy as identifyingthe component that votes against the majority.

The BSD function added to this process employed asecond TS3000 for overspeed protection as well asother safety system logic. Figure 4 shows six speedprobes installed in the turbine case to provide threespeed inputs for each system. All trip indicationsdeveloped by the ITC system are communicated to theBSD system trip check and execution. The systemsalso communicate with a DCS network of interactivegraphical display workstations.

Operator Interface

The Foxboro DCS displays give operators graphicalinformation and predetermined authority over theoperation of the compressors. Overall compressoroperating point, for example, is displayed as well asseparate graphics for each of the process stages thatmake up each compressor train. A number of other dis-plays were developed to present information needed tounderstand how the machinery is operating. These dis-plays allow the operators latitude to affect processchanges. Historical trends, reports, etc. are availablethrough this DCS communications link to the controlsystems.

New Instrumentation and Actuators

The reliability of the control system cannot be sig-nificantly improved without making appropriateimprovements in the field devices. The most extensiveportion of this upgrade is the replacement of most ofthe actuation systems of the three turbines. As seen inthe contrast between Figures 5 and 6, the new high-pressure hydraulic servo-actuation system simplifiedthe operation of the turbine and cleaned up themechanical/hydraulic interface. In one case, a pneu-matic actuator was replaced with a hydraulic servo-actuator so that the performance could be improvedwhile using the same actuation interface for each ofthe three turbine inlet valves and the extraction valve.Each servo-actuator has two torque motor coils toaccommodate redundant inputs and dual LVDTs to

provide redundant position feedbacks. Trip solenoidsare also redundant and use a fail-safe (deenergize totrip) philosophy.

Among other enhancements made to remove poten-tial single-point-failures were the adding of two newtransmitters for each existing trip limit switch. Thenew transmitters are compared to a limit in softwareand become two inferred digital inputs which are thenvoted (2-out-of-3) along with the original switch inputto provide a fault-tolerant logical trip initiator. Anyfailure that may occur in this triple arrangement is eas-ily detected and replaced on-line. Other measurementswere made (dual) redundant.

Software

The software uses specialized turbine and compres-sor control functions that are enabled by standard lad-der logic structure and remote inputs, such as processsetpoints, received over the MODBUS communica-tions port from the DCS. Software development forthe control system primarily involved configuring andtesting proven software function modules.

All monitoring, control and protection functions forthe three machines is done in a single system becauseit minimizes the number of discrete pieces of hardwareand reduces intermodule communications wiring.

Figure 4. Six magnetic pulse type speed pickups.


Figure 5. Original steam turbineinlet valve.

Figure 6. Steam turbine inletvalve HP actuator retrofit.

Turbine Compressor Controls

The standard digital speed/load control algorithm,based on a voted digital speed input and some loadprocess variable such as megawatts, discharge pres-sure, suction flow, etc., is well established in theindustry. The purpose of the article is, however, todemonstrate the ease with which compressor controland protection can be added to the turbine control sys-tem. Most of the field measurements necessary to per-form the additional compressor functions are alreadyrequired to operate the turbine properly in the presenceof a variable compressor load.

Process limit overrides, for example, are incorporat-ed in the integrated turbine-compressor control algo-rithm. Specifically, high discharge temperature, highdischarge pressure and low suction pressure conditionshave priority over other speed or flow demands.

There is one other aspect of this system which isremarkable — the integration of the pressure reducingvalves (PRV) with the 1500 psig inlet and 545 psigextraction pressure control loops governing the opera-tion of the syngas compressor train.

Syngas Turbine Extraction/PRV Control

The ITC has incorporated the PRV as the third vari-able for the control of the system. With three outputs,three parameters can be controlled instead of the nor-mal two parameters controlled by most extractionalgorithms.

Startup

The startup of the turbine is accomplished by initial-ly setting the maximum limit for the inlet valve, VI, to0%. The extraction valve, V2, is adjusted to satisfy theinitial "horsepower demand." The 545-psig (3.8-MPa)header pressure demand will not be satisfied by V2since the horsepower (speed) demand has a higher pri-ority, forcing it open—removing 545-psig (3.8-MPa)steam from the header. Consequently, the letdownvalves must open to maintain the 545-psig (3.8-MPa)pound header.

When the "ring pressure" discrete input is sensed,the VI maximum limit is ramped to 100% — allowingit to open as needed to increase steam flow. When"ring pressure" is sensed, the position of V2 is"remembered" and will be used as the minimum V2


valve position during normal shutdown. As VI opens(satisfying the horsepower requirement), V2 is closedproportionately, and therefore the letdown valves areclosed.

Normal Operation

When the 545-psig (3.8-MPa) header pressure dropswhile on-line, the controller starts closing the V2valve. VI is opened proportionally to maintain thespeed setpoint. If the header pressure still does notmeet the setpoint (low header pressure), and the V2valve reaches its minimum limit (cooling steam flow),or the point at which it maintains the "horsepowerdemand," then the letdown valve(s) begin to open tomaintain the 545-psig (3.8-MPa) header.

Any of the syngas valves may be placed in a "manu-al mode" whereby the operator may directly open orclose the respective valve by entering a "valve posi-tion setpoint" through the DCS. Transitions from"auto" to "manual" or conversely "manual" to "auto"are bumpless.

Normal shutdown

During normal shutdown, all valves are placed in"auto" control, and the VI maximum limit is rampedto 0%. This effectively ramps the VI valve output to0%. Concurrently, the speed setpoint is also rampeddown to "warmup" speed. The minimum V2 valveposition is ramped to the position "memorized" duringstartup when "ring pressure" condition was attained.This ensures the complete closure of VI before "ringpressure" is lost. When V2 "minimum valve limit"becomes the "memorized value," V2 moves to thestartup position and the PRV(s) open to make up anyneeded steam to maintain the 545-psig (3.8-MPa)header pressure.

Trip

All valves are forced to "auto" and all respectivevalve outputs are set to 0.0%.

Compressor controls

Process compressor capacity or load control is a cas-cade loop which determines the speed setpoint for theturbine. This control function can be performed withinthe ITC or by a remote distributed control system(DCS). A manual speed setpoint may also be issued.

An interesting aspect of this system is the integratedsurge prevention system. This new algorithm wasemployed for the first time in an ammonia manufac-turing unit on this project. By minimizing errors due tovariations in gas composition and conditions in pre-dicting surge, the algorithm stabilizes the process.There are several features designed to improve theresponsiveness of the system to some types of distur-bances because the turbine speed control algorithm isintegrated with the compressor performance control.

These surge protection features are adjusted to fit thecomplement of measurements available for each case.Some of these are:

• Surge characterization• Choice of Dp vs. h or Pd/Ps-1 vs. he algorithms• If a surge occurs, the surge safety margin readjusts• Active control line "hovers" close to actual operat-

ing point• Nonsymmetrical opening and closing• Equal percentage valve linearization• Recycle valve "dumps" or opens immediately• Independent proportional term forces recycle

valve open.In some applications, the flow measurement is avail-

able for the discharge and must be referred to the suc-tion. In these cases, a temperature measurement isrequired at the compressor suction. Fortunately, thealgorithm that reduces the error in surge predictionapplies to most compressor systems.

Conclusions

Integrated turbine compressor control technology isnow a real alternative for ammonia manufacturingplants. Because the installations do not have muchoperating time, the results are largely anecdotal. ITC,however, has been applied to wet gas, cracked gas,furnace gas compressors and air machines. Units suchas olefins, FCCTJ, and hydrotreaters are starting to


compile statistics that seem to bear out the expecta-tions.

Literature Cited

Boyce, M.P., et al., "Tutorial Session on PracticalApproach to Surge and Surge Control Systems,"Proc. of 12th Turbomachinery Symp.,Texas A&M University Turbomachinery Lab.,pp. 145-173 (1983).

Gaston, John R., et al., "Integrated TurbineCompressor Controls Retrofit for an Olefins Unit,"Int. Gas Turbine Inst. Turbo Expo Conf. Proc.,ASME, New York (1995).

Johncock, Allan, W., and John R. Gaston, TS3000Surge Conm?/,Triconex Systems, Inc., La Marque,TX(1994).

U.S. Department of Defense, Military StandardizationHandbook: Reliability Prediction of ElectronicEquipment, MBL-HDBK-217F, Notice 1,Washington, DC (1992).

DISCUSSIONKanwer Khan, Engro Chemical: For a typical syngascompressor, what is the minimum safety margin fromthe surge curve that you design your system for?Jacoby: The standard rule of thumb that most controlengineers will use is a 10% margin, but we now haveexperience with these systems in two of our ammoniaplants where our operators reduced that margin to aslow as 3%. They would actually turn it down that low.They had some steady-state operation, and they want-ed to avoid a lot of recycling. We don't recommendgetting that close, because you really don't have a lotof margin left. It does demonstrate the reliability ofour algorithms and their ability to protect the machineagainst surge. None of the users have reported thatthey have experienced any surge with our system.Khan: Secondly, this surge curve that you have shownhas two slopes. One is for the initial speed and theother is for little higher loads. Is the system that youdesign capable of handling these two curves or is itdesigned for one linear equation?Jacoby: We have even implemented systems that hadthree different slopes, all in the same system. That linecan be defined in terms of the pressure ratio and a ratioof suction orifice differential to the suction pressure.That is the only definition that we have to put into ourcontrol system software. With those process variableinputs, it always knows where the compressor is oper-ating relative to that surge line. That surge line must be

established from the compressor vendors test curves,and we try to do some field testing prior to the startupto see how close the system instrumentation is at pre-dicting the actual flows and pressures.Khan: The typical compressor surge curve would notbe a straight line. It would be a slightly sloped line.Do you linearize that slope to make a straight line?Jacoby: Yes, we do a curve fit. It tends to be segmentsof straight lines to approximate the curve and line.Andrew Walker, ICI Chemicals & Polymers: You dis-cussed much about the machine protection from theprocess point of view. Does this system incorporate anaspect of vibration controls or trips at all?Jacoby: We do not actually have the hardware forvibration monitoring. What we have done is to inter-face with the Bentley/Nevada hardware. At an ethyl-ene plant in the Baytown, Texas area, we have a cou-ple of systems installed that take the analog outputs ofthe Bentley/Nevada hardware directly into our controlsystem. Our control system is continuously monitoringthe vibration level at every probe. It then does votingon the axial displacement. There are two probes witha shutdown philosophy to trip the turbine on radialvibration if you have an alarm level on one end and adanger level on the other end. If you have danger onone end and were not alarming on the other end, theassumption is that the rotor is vibrating at only oneend. You don't have distortion at the middle of the


shaft that would be wiping out labyrinths. If you have state labyrinths. Yes, we do get involved in the vibra-vibrations on both ends, it's a reasonable assumption tion monitoring but, only after it has been input from athat you have a shaft bow that will be wiping out inter- vibration monitoring system.


1995: retrofitting the ammonia plant with integrated turbine … · 2018. 8. 22. · triconex...

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