Troubleshooting Natural Gas Processing

ransmission Norman P. Lieberman

TROUBLESHOOTING NATURAL GAS PROCESSING

NORMAN P. LIEBERMAN

P e n n W e l l Books A PennWell Publishing Company Tulsa, Oklahoma

Dedicated to Jack Stanley — Grace Under Pressure

Copyright © 1987 by PennWell Publishing Company 1421 South Sheridan RoadlP.O. Box 1260 Tulsa, Oklahoma 74101 Library of Congress cataloging in publication d a t a Lieberman, N o r m a n P. Troubleshooting n a t u r a l g a s processing. 1. Gas i n d u s t r y . I. Title. TP751.L54 1986 665.7 ISBN 0-87814-308-4

86-16878

All rights reserved. No part of this book may be reproduced, stored, in a retrieval system, or transcribed in any form or by any means, electronic or mechanical, including photocopying and recording, without the prior written permission of the publisher. Printed in the United States of America 2 3 4 5

90

89 ui

TABLE OF CONTENTS DEDICATION

iii

PREFACE

vii

INTRODUCTION

ix

SECTION I

TROUBLESHOOTING AT THE WELL SITE

1

Increasing Gas Row at the Wellhead

2

Additional Ideas to Enhance

1

Gas Row

16

3

Wellhead Surface Equipment

25

4 5

Wellhead Compression Process Cooling in Remote Locations

36 49

SECTION II TROCBLESHOOTING AT THE DEHYDRATION AND COMPRESSION STATION 6

Glycol Dehydration

59

7

Reciprocating Compressors

80

8

Reciprocating Engines

90

9

Loss in Centrifugal Compressor Capacity

100

Gas Turbine Driven Centrifugal Compressors

112

Light Hydrocarbon Distillation

120

10 11

12

13 SECTION III

A m i n e Regeneration a n d Scrubbing

133

Sulfur Plant Operation

148

PIPELINE PROBLEMS

14

Hydrates

172

15

Production Metering

180

16

Piping Pulsations

188

17

Corrosion and Fouling

192

GLOSSARYr

195

INDEX

203

PREFACE

The people who read this book are in the business of exploiting our country's most valuable, non-renewable, natural resource—nat­ ural gas. We are all faying to maximize cash flow and profit for both the lease operator and the landowner. That's fine; that's the Amer­ ican way. But, in a sense, the gas trapped deep in hidden sand formations belongs not only to our current generation, but to the generations coming along behind us. When we exploit a gas field, let's do it ef­ ficiently. It's pretty easy to damage a gas bearing sand formation by careless or hasty production methods. Once the gas is gone, it's gone forever. So let's leave a fair share for future Americans to exploit and enjoy. Norm Lieberman

VI

vn

INTRODUCTION FROM WELLHEAD TO TRANSMISSION PIPEUNE The natural gas which flows from a well is wet, saturated with heavy hydrocarbons and contaminated with salt and sand. Gas pres­ sure at the wellhead varies from a few PSIG to ten thousand pounds. Natural gas flowing from deeper wells may contain large quantities of hydrogen sulfide. The BTU content ranges from 1000 to 1400 BTU per SCF, while the temperature at the wellhead can be over 200°F. In contrast, gas in common carrier transmission lines is of a much more uniform quality. Typical conditions are: • • • • •

5 ppm H 2 S 800psig 90°F 1000 BTU per SCF 5 pounds water per million SCF

The common carrier transmission lines are usually 16" to 30" in diameter. They carry gas from perhaps fifty thousand wells, scat­ tered throughout remote and inhospitable regions, to the population centers of the nation. The lines from the wellheads are typically 2" in diameter. The gas flows into collection lines called laterals which range from 3" to 12" in diameter. Although there is no generally accepted practice, liquids are often separated from natural gas before the gas enters the collection lateral piping. The liquids consist of brine (salt water usually less saline than sea water) and condensate (natural gasoline). The condensate is collected in trucks and winds up in a petro­ leum refinery or similar facility, where the condensate is blended into gasoline. The brine is also removed from the well site in trucks, then injected back into the ground in designated disposal wells. After separation from wellhead liquids, the gas is metered. Exact measurement of the gas volume flowing from a well is impor­ tant for two reasons. First of all, the owner of the well is not the same individual who owns the mineral rights to the land. The land­ owner must be paid a royalty (about 20%) by the lease operator (i.e. the company or individual that produces and sells the gas). Sec­ ondly, the lease operator pays tax on his production (7% in Texas). Many wells are joint ventures, and this too necessitates careful metering. IX

Natural gas flows from the collection laterals to a gas condi­ tioning station. A small station may handle 10 million SCFD, while a big station may process 500 million SCFD. Initially, the. gas goes through a knock-out drum to remove entrained liquids. Then it can be filtered to remove sand and corrosion products, compressed and scrubbed with an amine solution to remove hydrogen sulfide. All natural gas is dehydrated. This is accomplished with a cir­ culating ethylene glycol system. The gas is dried so that it will not precipitate water at temperatures down to -35°F. A common carrier pipeline will not accept gas with hydrogen sulfide and water concen­ trations above standard pipeline specifications. After dehydration, ethane, propane, isobutane, normal butane and gasoline may be recovered from the dried gas. If the heat con­ tent of the gas exceeds 1100 BTU's per SCF, it is likely that it will be cost effective to recover these hydrocarbons as liquid products. Only about 35% of the ethane is usually removed from the gas, while 95% of the propane and heavier hydrocarbons are recovered. The propane is sold as HD-5 LPG; normal butane is blended into gasoline; while isobutane becomes a feedstock for a refinery's alkylation unit. Ethane is used primarily as a feedstock to a chemical plant's ethylene units. From this point on, natural gas is treated as a fungible mate­ rial. It is traded by pipeline companies and producers based on it's BTU content. A pipeline company often transports gas for if s com­ petitors and sundry producers. The tariff that is charged for this transportation is quite variable; 15# per 100 miles is an order of magnitude guideline. The velocity of gas in a pipeline ranges between ten to twenty feet per second. A pipeline that is heavily loaded (i.e. "packed") will exhibit a pressure drop of up to 10 PSI per mile, with 4 PSI per mile being more normal. Pipeline pressures range from 400 PSIG to 1350 PSIG. The standard maximum design pressure for vessels used in natural gas service is 1440 PSIG (100 atmospheres). Most transmission lines will have booster stations located every fifty miles or so. A typical booster station will raise the gas pressure 200 PSI. Gas entering a pipeline should be cooler than 120°F as the protective exterior coating of the pipe deteriorates at a temperature above 140"F. Between booster stations, the flowing gas approaches the temperature of the ground that the pipeline is buried under. Gas inside a transmission line is non-corrosive; it is the ex­ terior corrosion that one has to watch. On the other hand, upstream of the gas conditioning station, along the collection laterals, internal pipe corrosion is a serious problem. Most of the cost of producing natural gas is incurred in explo-

ration and drilling. The next largest cost components are royalty and tax payments. Gas treating, drying, compression and liquid hy­ drocarbon handling total a distant third on the list of expenses. But it is just these areas that call for the talents of the troubleshooter. Although the process and mechanical engineering concepts needed to tackle these areas are relatively straightforward, it is their in­ teraction with the gas well itself that makes the job of trouble­ shooting natural gas production a real challenge.

x

XI

Section ±3

Troubleshooting At The Well Site

"Now son, it's only a matter of time and determination". Production Supervisor Larry Wflkes Texas City, Texas

1 INCREASING GAS FLOW AT THE WELLHEAD "I had left the gate open and now a large black cow was grazing alongside the highway." "What does this have to do with gas production," demanded Mr. Howlaway, "I'm not paying you to listen to another cow story." 'Tm coming to that part, but the cow is part of the story too," I explained. "As you probably know, poor grazing land is a sure sign of a tight gas formation. Cattle prefer ...." "No it isn't", interrupted Mr. Howlaway, "Cows have nothing to do with the permeability of a gas bearing sand formation. Kindly stick to the point." Trying to pacify my client, I drew the simplified sketch of a typical gas well shown in Figure 1-1. Mr. Howlaway was interested in methods to promote gas flow from low pressure wells without spending significant sums to up-grade production. It was going to be hard to proceed with my explanation though, without some reference to the cattle: "There are three basic problems which reduce the flow of gas from a well which has a sufficient gas pressure, porosity and per­ meability in the surrounding sand formation to sustain a much higher production rate: 1. Restriction to flow down hole such as occurs when sand covers the perforations in the casing. 2. Liquid loading of the production tubing with water and natural gasoline condensate. 3. Back-pressure on the wellhead tree caused by such factors as high pressure in the gas collection header piping. 1

2

INCREASING GAS FLOW AT THE WELLHEAD

TROUBLESHOOTING NATURAL GAS PROCESSING

Adjustable choke

High-low pressure shutdown

3

These points can best be understood by referring to Figure 1-1. Simply observing the operation of a well does little to help differen­ tiate the causes of diminished gas production. One of the questions asked by lease operators is how to calcu­ late the incremental gas flow that can be expected from a well due to reduced lateral collection header pressure. The formula used to estimate this increase is:

Cap

^

_,n

w=J

Q 2 = Qi

Gas to collection header

X

Pf - Pi P* - Pi2

(1)

Wellhead tree

where Surface

\

Qx = Q2 = Ps = Pi = P2 = n =

, Casing

• Tubing

.Packer

I77777T7777% v ' ' , Gas-bearing

fll/

/// .

/T7T

* sand formation

/

Perforations in casing Bottom of hole

Figure 1-1 Gas production from the tubing of a single completion well.

Initial gas flow. Final gas flow. Stabilized shut-in pressure, measured at the wellhead cap. Initial wellhead pressure. Final wellhead pressure. The slope of the wellhead performance curve obtained from a well's multipoint test.

While P x and Qi are known from the current operating data, and the lease operator will be able to estimate P 2 , (the final well­ head pressure) determining a reasonable value for the shut-in pres­ sure (Ps) and the slope of the wellhead performance curve (n) can be a challenge. After a well has been blocked-in, the pressure on the wellhead will increase for several hours, or even days. The reading on the wellhead tree pressure gauge after this pressure has stabilized, is termed the shut-in pressure. There are several problems which interfere with obtaining a true wellhead shut-in pressure. One difficulty is that while one is waiting for the wellhead pressure to stabilize, the lease operator can lose one to three days of production. Or, liquids may be accumulating in the mile or two of tubing between the perforations and the wellhead. If a well accumulates 4,000 feet of condensate in the tubing during a shut-in test, then the wellhead pressure will be surpressed by 1,000 psig. For this case, the observed wellhead shut-in pressure is meaningless. When the well is put back on-line and resumes gas flow, the wellhead pressure will probably increase,

4

TROUBLESHOOTING NATURAL GAS PROCESSING

rather than decrease! In many instances, the only practical way to determine a shut-in pressure is to search back over production records and find a time when the well was blocked-in for mainte­ nance. Next, check the reported wellhead pressure immediately after flow from the well was resumed. If the flowing tube (i.e. wellhead) pressure is somewhat lower than the shut-in wellhead pressure, one may assume t h a t a reasonable value for the shut-in pressure has been determined. The numerical value for (n), the slope of the wellhead perfor­ mance curve, can often be obtained from the initial performance test run on the well made immediately after completion. Usually (n) varies from .65 to .95. For troubleshooting type approximations, assuming that n = .8 will not introduce much of an error into the predi­ cated increment of gas flow due to a reduction in collection header pressure. WHY HAS GAS FLOW DROPPED? We are assuming that the reservoir pressure and porosity are adequate — that is, there is a plentiful supply of gas in the ground for the well to draw on. Also, we are assuming that the permeability of the reservoir is sufficient to allow a relatively free flow of gas to the perforations in the casing. (Porosity and pressure are a measure of the amount of gas trapped in the sand formation; permeability is a measure of the resistance of the sand formation to gas flow). We are concerned in this chapter with factors t h a t interfere with gas flow from the sand formation immediately surrounding the casing perforations up through and into the gas collection header. In this regard then, what is the physical meaning of equation (1) above in the context of our everyday experience? When the flowing tube pressure (i.e. the wellhead pressure during normal operation) is close to the shut-in pressure, a small reduction in the collection header pressure (with a concurrent drop in the wellhead pressure) causes a substantial increase in gas flow. On the other hand, when the flowing tube pressure at the wellhead is much less than the shut-in pressure, a small reduction in the wellhead pressure will not effect gas flow significantly. To emphasize this critical concept, note that when wellhead flow is restricted by back pressure from the collection header piping, the shutin and flowing tube pressures will be similar. On the other hand, if gas flow is restricted by a discarded tool stuck 8,000 feet down in the tubing string, then the shut-in and flowing tube pressures will be far apart. Why is this? Because, if the errant tool was removed from the tubing, the shut-in pressure will not be effected, but the well­ head flowing tube pressure would greatly increase (assuming that flow

INCREASING GAS FLOW AT THE WELLHEAD

5

from the well was choked back to maintain constant production). This leads to an important troubleshooting principal: The first point to establish in troubleshooting a well for lost production is whether the problem is above or below the surface!

LIQUID LOADING Although we have been talking about wellhead pressure (both shut-in and flowing tube), the wellhead pressure is just an indirect indication of the really important parameter-that is, the bottom hole pressure. It is the pressure inside the casing at the level of the perfor­ ations that determines gas flow. By lowering a pressure sensing instru­ ment suspended on a wire-line to the proper depth, bottom hole pres­ sures can be directly measured. But this is an expensive and time consuming procedure, and beyond the scope of the options available to the field troubleshooter. So we do not usually know the actual bottom hole pressure. If we knew the density of the column of fluids (i.e. the mixture of gas, conden­ sate and brine) inside the tubing, we could calculate the bottom pressure as follows: P

= P + (SG) H/2.31 p

(2)

i

where P = Pressure at perforations, psig P i = Wellhead Pressure, psig H = Vertical distance between wellhead tree and perforations, ft. SG = The average specific gravity of the three phase mixture in the tubing, taking into account the increase in gas density at greater depths. It is the difference between the bottom hole pressure (Pp) and the pressure in the surrounding sand formation t h a t determines the rate of gas flow from a well. From equation (2) we can see that the bottom hole pressure will increase as the density (SG) in the tubing rises. This increase in P p reduces the gas production from the well according to the formula: 2

2

Q-P'-Pp r

where Q = Gas Flow P — Reservoir Pressure

(3)

6

TROUBLESHOOTING NATURAL GAS PROCESSING

The main point t h a t the troubleshooter must absorb from the preceeding paragraphs is that any increase in the average fluid density in the tubing will surpress gas flow. An increase in this density is always due to the accumulation of condensate and/or brine in the tub­ ing. Unfortunately, there is no way to measure this accumulation. Hence, the troubleshooter cannot really make direct use of equation (3). However, with a little experience, it is possible to determine the approximate effect of liquid loading on many wells. ENTRAINMENT VELOCITY A well that produces 100,000 SCFD of gas as a minimum, but periodically reaches a peak production rate of 300,000 SCFD once a day, is continuously loading and unloading liquids. The sequence of events are: • The velocity of gas flowing up through the tubing is insufficient to entrain liquids out of the tubing to the surface. • Liquids accumulate (load) in the tubing. • The weight of liquid increases the pressure differential between the wellhead tree and the bottom of the hole, as per equation 2. • The gas flow from the well drops, as per equation 3. • Gas flow continues to bubble-up through the tubing; but at a rate insufficient to entrain liquids out of the tubing. • The gas pressure inside the tubing at the bottom of the well, and also in the sand formation surrounding the perforations continues to build as the gas flow diminishes. • At some point, the well reaches a condition of instability. For example, a small reduction in the wellhead pressure due to a downstream pressure reduction causes a small increase in gas flow. This promotes a small amount of liquid unloading from the tubing. The resulting decrease in average fluid density in the tubing drops the bottom hole pressure. Gas is now sucked out of the sand formation, and through the perforations, at an accelerated rate. • A chain reaction has been set in motion. Accelerated gas flow speeds liquid unloading; which in turn drops the bottom hole pressure, and progressively increases the rate of gas production. An atomic bomb is detonated by creating a critical mass of plutonium. A gas well is unloaded by reaching the well's entrainment velocity; a point encountered suddenly and in a dramatic fashion. The sound of slugs of brine and condensate blasting through the wellhead tree and surface equipment is quite audible. Typically, both the well­ head pressure and the gas flow will increase as the slugs of liquid "hit" the surface piping with increasing frequency.

INCREASING GAS FLOW AT THE WELLHEAD

7

Once the liquid is cleared out of the tubing (this takes 30 minutes to a few hours), the flow stabilizes for several hours and then slips away as the pressure in the sand formation around the casing perfor­ ations is dissipated. Once the velocity through the tubing drops below that needed to continue entraining the liquids, gas production drops rapidly, and the cycle, as shown in Figure 1—2 is repeated. SUSTAINING ENTRAINMENT VELOCITY When I first started troubleshooting partially depleted natural gas wells, I often wondered why so many of the hundred odd wells I visited were averaging 200-300 MSCFD. I had expected a more linear distribution between the minimum gas production per well (20 MSCFD). Actually, 30 to 40% of the wells I observed clustered around an average production rate of 250 MSCFD.

I

TlME Figure 1-2 Peaks indicate cyclic unloading of liquids.

8

INCREASING GAS FLOW AT THE WELLHEAD

TROUBLESHOOTING NATURAL GAS PROCESSING

Wells with average production rates below 150 MSCFD, all had one factor in common - low wellhead pressure. The lower the wellhead pressure, the greater the velocity developed in the tubing with a given volume of gas. For example, 150 MSCFD of gas flowing at a pressure of 600 psig develops the same velocity as 240 MSCFD flowing at a pressure of 1000 psig. For those readers familiar with Stokes Law:

V « gr 2 (D L - Dy) / (vis)

9

Of course, my objective was to derive a value for "K" which I could use to predict with confidence V E for hundreds of other wells. For my data base, I calculated values for "K" ranging from 0.85 to 1.10. The density of brine is about 63 lbs./ft. and condensate is about 42 Ibs./ft. .The gas density is calculated at the wellhead temperature and pressure.

TABLE 1-1

(4)

COMMON TUBING DIMENSIONS (Inches)

where V = velocity of a droplet of liquid falling in a gas phase under the influence of gravity. g = Gravitational constant. D L = Density of liquid droplet. Dy = Density of the continuous gas phase. r = Radius of droplets vis = Viscosity of gas phase.

Size,O.D.*

Size, I D .

2% 27/s 3V2 4 4V2

1.995 2.441 2.992 3.476 3.958

*Tubing size in gas field parlance only refers to the outside diameter.

One can see t h a t as the density of the liquid droplets decreases, the gas velocity necessary to entrain the droplets also decreases. Hence, one would anticipate that entraining condenate would require a lower velocity than that required to entrain water. Also, dispersing the liquid (i.e. reducing V in equation (4) such as by forming an aerated foam) would also lower the minimum velocity required to entrain liquids. I have observed the flowing gas volume and corresponding wellhead pressure for a dozen odd wells just as they reached their minimum entrainment velocity. That is, the point in time when I could hear repeated slugs of liquid passing through the wellhead tree. Using the tubing inside diameter (see Table 1), I then calculated the minimum or incipient velocity needed to unload liquids from each well. This data was then correlated using the standard relationship for liquid entrain­ ment employed in the chemical process industry:

V E = K / D L - DyV/2 V

Dv

)

where V E = Incipient entrainment velocity K = An empirically derived constant D = Density, lbs./ ft3

(5)

Equation 5 and the corresponding "K" values were developed for 8-10,000 ft. wells, with wellhead pressures varying between 100 to 500 psig. The liquid phase was always brine and 18 molecular weight natural gas was being produced. The tubing strings were either 2%" or 2%" O.D. I do not suggest that one should use any particular "K" value for an individual gas field. The idea is to get out of the office and play with the wells. Then, using Equation 5 as a basis, develop "K" values applicable to one's own gas field. " V E " is a^so referred to as the "flowpoint", and a rather detailed review of this subject has been published. 2 KEEPING WELLS UNLOADED Mr. Howlaway eyed my equations suspiciously, "I can see that you have developed a method to predict the combination of the gas production rate and wellhead pressure necessary to keep my wells from loading -up with liquid. But suppose the production rate that the reservoir can support is too low, or the wellhead pressure is too high to achieve the minimum entrainment velocity. What should I do about that?" Of course, there were a wide variety of answers to Mr. Howlaway's question. Major industries have been created to assist gas producers to keep wells from loading up with liquids. Gas lift Mandrels and

10

TROUBLESHOOTING NATURAL GAS PROCESSING

plunger lift systems are just two of the many gas lift downhole methods commonly employed to remove liquids from gas wells. However, as far as retrofitting low pressure wells at the surface is concerned, the simplest most cost effective means to remove accumulated liquids from a well is a n "Intermitter." Figure 1-3 illustrates a typical Intermitter installation. A motor on-off valve located downstream of the high pressure separator alter­ nately shuts-in and opens-up flow from the well. Wellhead pressure is allowed to build to several hundred psig above the pressure in the gas collection lateral. When the intermitter motor valve springs open, the sudden release in pressure creates a surge in gas flow through the tubing string. The accelerating gas flow reaches and surpasses the entrainment velocity, and the well is thus unloaded. PROBLEMS WITH CISE OF INTERMITTERS The valve trim on the intermitter should be at least twice the diameter of the choke. When the intermitter valve opens it should not restrict gas flow from the well. Unfortunately, if the wellhead pressure builds to an excessive level, the sudden surge in gas flow when the intermitter opens may have two detrimental effects: 1. The flow recorder may be over-ranged to such an extent that it is damaged. 2. The high pressure separator may fill with liquid so rapidly that the dump valve may not be able to drain liquid down fast enough to prevent liquid carry-over into the instrument gas bottle shown in Figure 1-3. Ordinarily, the intermitter motor valve is controlled by a timer (Electronic digital timers with a variety of built-in. computer features are now available). The well may be set to flow on a 24 hour open/12 hour shut-in cycle. To prevent the problems described above, a highpressure over-ride is set to open the motor valve when the pressure build-up is more rapid than anticipated. The electronic timer mentioned above already incorporates this pressure over-ride feature. The optimum time intervals for cycling between opening and closing the motor valve are learned from experimenting on individual wells. Once experience has shown that a well begins to load up with liquids after free flowing for 28 hours, the intermitter controller should be set to shut the well in for pressure build up after 30 hours of production. SOAP STICKS Equation 5 implies that the lower the density of the liquid

INCREASING GAS FLOW AT THE WELLHEAD

11

accumulating in the tubing, the lower the entrainment velocity. This means that less gas flow is required to keep a well unloaded of liquids, when the liquid density is reduced. Addition of soap sticks to a well is a simple method to reduce the density of liquids in the tubing. Adding soap sticks achieves this objective by causing the water to turn to froth. The soap sticks are approximately 18 in. long by V/z in. in diameter and consist simply of soap. They are dropped down the well by placing them into the wellhead tree between the two master valves on the vertical section of the tree. A typical rate of soap-stick addition is two sticks every four days. Two different types of soap sticks are available: A hydrocarbon soluble stick for removing naphtha-i.e., natural gas condensate from the tubing and a corresponding water-soluble stick. Using both types in conjunction is often an effective means of stimulating gas flow. Note: Hydrocarbon-soluble sticks may create an emulsion in the naphtha that may subsequently have to be chemically treated in order to sell the condensate. Improper and excessive use of soap sticks can damage the gas bearing sand formation. Dropping sticks into a shut-in well and permitting the soapy solution to permeate back through the perfora­ tions in the casing should be avoided. Also, the froth carried out of a well after soap sticking may over-load the high pressure separator and result in the entrainment of liquid to down stream equipment. This can be an especially troublesome problem when compressors are located downstream of wells being soap sticked. Often the most cost effective method to unload wells is to increase the velocity of gas flowing through the tubing by reducing the wellhead pressure. For example, if the wellhead pressure is reduced from 315 psig (i.e. 330 psig) down to 150 psig (i.e. 165 psig), the velocity in the tubing string will double. However, according to Equation 5. V E , the entrainment velocity, will also increase by 41%. This occurs because halving the pressure also halves P v , the vapor density, and this in­ creases V E by the V2~] The sum of these effects is to reduce the SCFD of natural gas required to exceed the entrainment velocity by 30%, when the wellhead pressure is halved. The most cost effective method to cut the wellhead pressure is to install a small, reciprocating, gas engine driven compressor at the well-site down stream of the high pressure separator. Techniques to adjust and troubleshoot these machines will be discussed in a later chapter.

DOWN HOLE PROBLEMS "Let's hold it a minute", interjected Mr. Howlaway. "It's not that I haven't been trying to listen to you for the past two hours . . . . but

12

TROUBLESHOOTING NATURAL GAS PROCESSING

INCREASING GAS FLOW AT THE WELLHEAD

13

my mind tends to wander. I'm thinking about our Juanita # 5 well, down in Jim Hogg County. That well doesn't make any liquids - brine or condensate. When we first put it on line it flowed 4,200 MSCFD. Now, just a year later, it can barely sustain 80 MSCFD with a wellhead pressure floating on the gas collection lateral pressure of 600 PSIG. I tried installing a wellhead compressor to increase gas flow. The com­ pressor worked okay. It reduced the wellhead pressure to 300 PSIG. The results were real disappointing; the incremental gas flow of 10 MSCFD barely was enough to run the compressor." Mr. Howlaway stared out of the window at the emaciated cattle searching for the last blades of withered grass and continued. "I noticed though, that while the well was shut-in to permit the compressor piping to be tied-in, the wellhead pressure rapidly increased to 1900 PSIG. You would think that a well with all that high pressure gas behind it could produce more than 80 MSCFD with a W wellhead choke? What do you think".

SAND COVERING PERFORATIONS c

e 5

c J2 T3

3

1

J O

I

The points t h a t Mr. Howlaway had enumerated: • No liquids produced. • A recent past history of high gas production. • Low gas flow at a reasonable low wellhead pressure through a relatively large choke. • Rapid build-up to a high shut-in pressure. • No significant improvement in gas flow even when the wellhead pressure was sucked down with a field compressor. These factors were all indicative of down hole problems — most probably sand covering the casing perforations (see Figure 1—1). Some­ times a sand bridge forms above the perforations. Either way, the effect is the same; a great reduction in gas production. Equation 1 explains why all of Mr. Howlaway's observations were consistent. The recent 4,000 MSCFD of gas flow indicated the permea­ bility of the gas bearing sand formation was excellent. See if you can calculate from Equation 1 why the installation of the wellhead compres­ sor was a mistake.

TAGGING BOTTOM Rapidly opening the wellhead valves on a high pressure well flowing into a low pressure collection system is a good way to ruin a well when the following two criteria are met: • The wellhead choke is large. • The well has been shut-in for a while.

14

TROUBLESHOOTING NATCIRAL GAS PROCESSING

The surge of gas flow resulting from following this procedure may, depending on the producing formation, suck sand out of the formation, through the casing perforations and into the tubing. To determine if sand is indeed covering the perforations, a weighted wire line is lowered through the tubing through a device called a "lubricator". When the wire line loses tension, the operating personnel at the surface surmise t h a t the weight has "tagged bottoms". This tagged depth is compared to the well's completion record to determine if any or all of the casing perforations are submerged in sand. If more t h a n 20% to 30% of the perforations are covered, it is a good idea to wash the well out with a "coil tubing unit". The cost to tag bottoms with a wire line unit is only a few thousand dollars. Washing a well clear of sand with a coil tubing unit can cost ten times as much. A coil of tubing — perhaps 10,000 feet long, is lowered into the well. Water and high pressure nitrogen are employed to force the sand out of the bottom of the well and up through the annular space between the tubing and the outside of the coil tubing. It is not uncommon to see gas flow triple, after a well has been relieved of it's load of accumulated sand. Prior to placing a compressor on a partially depleted well, it is a good idea to obtain at least a qualitative idea of difference between the shut-in and the flowing wellhead pressure. If this difference is large, then it is far better to check for sand in the tubing than to blindly install the wellhead compressor. Certainly, if sand is covering the casing perforations, it is a waste of time and money to install a wellhead compressor. Of course, the presence of sand in a relatively young well is indi­ cative of a sloppy operation at some previous occasion. This is especially true if the material being pulled into the tubing is frac sand rather than formation sand. There is no sense pumping frac sand into a for­ mation and then crushing the sand and sucking it out of the formation by over-rapid natural gas production. The sun, having burned the last trace of moisture from the already parched hills, dipped below the horizon. Mr. Howlaway stared out the window at the reddening sky. "What about the black cow. Is the cow still relevant". "Of course. The cow is part of the story too", I explained. "Men have been shot for leaving gas field gates open. Driving cattle back onto a lease is always relevant to troubleshooting gas production. As for the black cow, when it saw that I meant business; when it understood that I wasn't leaving until it went back through the gate; it just natur­ ally marched back onto the lease. It was only a matter of time and determination. Sure, the cow is part of the story too", I concluded.

INCREASING GAS FLOW AT THE WELLHEAD

15

REFERENCES 1. Smith, R.V., "Practical Natural Gas Engineering, Pennwell, Tulsa, Okla., 1984, page 108. 2. Greene, William R., "Analyzing the Performance of Gas Wells", Journal ofPetroIeum Technology, July, 1983, pages 1378-1384. 3. Otis Engineering Corp., General Sales Catalogue, Dallas, Texas. Gas Lift Equipment & Services, page 250.

ADDITIONAL IDEAS TO ENHANCE GAS FLOW

2

17

• 30% of the wells did not exhibit any observable increase in gas flow. • An additional 10% of the wells actually lost production as the wellhead pressure dropped.

ADDITIONAL IDEAS TO ENHANCE GAS FLOW

If the reader will consult equation 1, of the previous chapter, he will note t h a t when wells have relatively high stabilized shut-in pressures, as compared to their flowing wellhead pressure, that the incremental gas flow obtained from a further reduction in the flow­ ing wellhead pressure may be quite small. It transpires that there is another factor which tends to negate the effects of decreased well­ head pressure. This factor is water.

CONING WATER INTO A WELL One of the more puzzling phenomenon I have observed in gas field production happened during my tenure as an operator of well­ head compressors. One would intuitively assume that the faster the wellhead compressor ran, the more gas would be delivered through the sales meter. Normally, as the compressor speed was increased by manually screwing open the governor speed control valve, the com­ pressor suction pressure fell. Of course, this also reduced the well­ head pressure and the gas flow would be expected to increase accord­ ing to the formula: Q=C(PR2 where Q PR PI

C,n

-Pf )°

_

Gas flow, SCF — Reservoir pressure = Wellhead pressure = Constants peculiar to -0i

WELLHEAD COMPRESSION

4 WELLHEAD COMPRESSION

A wellhead field compressor appears to be a simple enough de­ vice. Thousands of these small, gas engine driven, reciprocating machines are in service throughout the country. When properly matched to a well, a field compressor is a cost effective method to maintain or increase gas flow from older wells. However, in spite of their superficial simplicity, the adjustment of field compressors to maximize gas flow is a complex job. This is attributable to the many modes in which a small field compressor can operate and to the dynamic nature of the well itself. It is the inter-action of the com­ pressor, the collection header pressure and the gas well flowing characteristics t h a t make adjusting field compressors a challenging assignment. COMPRESSOR CONFIGURATION Figure 4-1 illustrates a typical two-stage compressor. Machines of this type range from 30 to 300 horsepower. They are driven by a gas engine; fueled by natural gas. Engine speed is 250 to 450 rpm, with the compressor inter-cooler and after-cooler air fans driven by the engine. Such machines are rugged, reliable and flexible. To il­ lustrate their flexibility, there are three principal modes of opera­ tion. Two Stage (Tandum) Operation Both compressor stages are fully operational. Note that the first-stage is called the "head-end" and that the second-stage is termed the "crank-end. 36

37

Head-End Operation The compressor cylinder valves have been disabled in the crank-end (i.e. second-stage), so that only the head-end does compression work. This type of operation is summarized in Figure 4—1. Crank-End Operation The compressor cylinder valves have been disabled in the head-end (i.e. first-stage), so that only the crank-end does compression work. Note that the head-end cylinder's volumetric capacity is much greater than that of the crank-end. However, the volumetric capac­ ity of the head-end can be adjusted with the cylinder clearance valve (see Figure 4-1), whereas the volumetric capacity of the crank-end is fixed. In addition to these permutations, the compressor speed can be varied over a wide range, the suction flow may be throttled, engine fuel can be drawn from either the suction or discharge, and the dis­ charge, and the discharge cooler may be by-passed. Reducing the surface pressure by compression reduces the gas pressure in the tubing at the level of the perforations and hence in­ creases the flow of gas from the formation through the casing per­ forations. The incremental flow of gas obtained from a well by sur­ face compression is a function of many complex variables. Gas wells that have become water-logged may double or triple 795 PSIG

INTERSTAGE COOLER

\ 8 0 0 PSIG

llO°F 2lO°F GAS ENGINE

—

CRANK END

HEAD END

CYLINDER CLEARANCE ADJUSTMENT

■I38"F

FUEL GAS"

SPEED CONTROL 80°F-

GAS TO PIPELINE S

790 PSIG

;

- 2 0 0 PSIG GAS -*FROM WELL

Figure 4—1 A wellhead compressor, two stage, gas driven set-up for "head­ end only" operation.

WELLHEAD COMPRESSION

3 8 TROUBLESHOOTING NATURAL GAS PROCESSING

production when joined to a properly sized and operated field com­ pressor. For example, a well was producing gas at a rate of 300,000 SCFD with a compressor suction (i.e. wellhead pressure) of 400 PSIG. The compressor configuration was altered from crank-end op­ eration to head-end operation. In effect, the volumetric capacity of the machine was doubled. Consequently, the wellhead pressure was reduced to 280 PSIG, and gas flow rose to a rate of 350,000 SFCD. After operating for a short time in this manner, slugs of water began to pass up through the wellhead valves. The hammering sound of water entering a wellhead tree is called "water hits". As the slugs of water raced up the tubing, the weight of water suppres­ sing gas flow was removed (i.e. the well unloaded). Both the well­ head pressure and the flow increased. Hours later, the well perfor­ mance stabilized at 780,000 SCFD and a 350 PSIG compressor suc­ tion pressure. ENTRAPMENT VELOCITY This incident illustrates the importance of adjusting field com­ pressor operation to maintain a minimum velocity in the production tubing. The velocity must be sufficient to entrain water, which mi­ grates into the well, up into the high pressure separator. Based on a limited amount of data taken in gas field operation and a more substantial data base developed in the process industry, the follow­ ing rule of thumb is suggested: V E = 1.2 ( \

DT

-Dv Dv

where VE Dv DL

= = =

Entrainment velocity, ft./sec. Density of gas, lbsVft.3 Density of liquid, lbs./ft.3

This equation for entrainment velocity is in the form of Stokes Law for settling of particles in a fluid. The coefficient of 1.2 will vary with gas viscosity, depth of the producing formation and the presence of surfactants in the well liquids. The reader should develop a suitable coefficient from his own experiences. Correlations developed by other workers in this field suggest that the minimum velocity to "unload" a well is greater than t h a t shown above. *' 2 Note t h a t adding soap sticks to a well reduces the D L term in the above equation by over 50% and thus effectively lowers the entrain­ ment velocity.

39

INCREASING WELLHEAD TUBING VELOCITY The easiest, but least cost effective method, to operate a field compressor is the crank-end mode. When only the Crank-end (i.e. second stage) is in operation, capacity, compression ratio, as well as engine horsepower load and compressor rod loading are minimized. Left to their own devices, field personnel oft-times run compressors on the crank-end only. To increase the wellhead tube velocity, it is usually necessary to switch the compressor operation to the head­ end mode. This involves removing the crank-end cylinder valves and re-installing the head-end cylinder valves. The head-end cylinder clearance valve should then be closed as far as possible so as to fully utilize the available engine horsepower. To calculate approximate horsepowerT the following equation may be used: HP = THFX MSCFD 6.7

(Per Stage)

where THP

=

HP

=

Theoretical horsepower per mole obtained from Figure 4—2. Actual engine horsepower required including auxiliaries.

Maximizing engine horsepower and hence gas flow immediately after switching to head-end operation is helpful in achieving the tubing entrainment velocity. A gradual increase in gas flow will not be as effective in unloading the well. Therefore, the engine rpm should be set at maximum and the head-end cylinder clearance set­ ting should be minimized as soon as the machine is put back on line. HORSEPOWER BOTTLENECKS There are three fundamental limits to which all field compres­ sors are subject: • Compressor rod loading • Speed • Engine horsepower In addition to calculating the actual engine horsepower by the above equation and comparing it to the name plate rating, the en­ gine exhaust gas temperature should be checked. The engine man­ ufacturer specifies a maximum exhaust temperature for the engine when running at maximum load. If this design temperature is

40

TROUBLESHOOTING NATORAL GAS PROCESSING

750°F, while the observed engine exhaust is 600°F, it is quite appar­ ent that the engine is not running at its maximum load. On the other hand, if the cylinder clearance valve is closed a few turns, and the machine slows down (or even stalls) the engine is positively working as hard as it can. Of course, as with a car engine, adjust­ ments to the carburetor and ignition systems can correct horsepower limits. Do not forget that for a field compressor to develop its rated horsepower, -it must be operating at its maximum design speed. Slowing an engine down without reducing its horsepower load will raise the temperature of the exhaust gas. To economize on the avail­ able engine horsepower one can: • Minimize pressure drop between the wellhead and the com­ pressor suction. If the pressure difference between these two points exceeds 10 PSIG, there is an unnecessary restriction to flow. Perhaps the positive choke in the wellhead has not been removed. Oft-times the surface piping diameter has not been sized for low pressure gas. Gas heaters, necessary to prevent hydrate formation on high-pressure wells, should be by-passed

WELLHEAD COMPRESSION

41

when field compressors are installed. • Withdraw gas from the suction of the compressor, rather than the discharge, for engine fuel. A 100 horsepower compressor will require 30 MSCFD of fuel or several percent of the unit's capacity. • Do not simply disable compressor valves when either the head­ end or crank-end is to be taken out of service. Remove the valve assembly completely from the cylinder. Even though the valve plate may have been removed from the suction valve, the remaining portions of the valve will still offer a substantial re­ sistance to flow and hence absorb horsepower. • By-pass the inter-cooler when on "crank-end" operation; alter­ nately by-pass the after-cooler when on "head-end operation. • Wash the inter-cooler fin tubes to remove bugs and dust. Com­ pressor horsepower required is proportional to gas inlet temperature. ROD LOADING LIMITS As the wellhead pressure falls, the differential pressure that the field compressor must deliver increases. This is because the col­ lection header into which the compressor discharges remains rela­ tively constant. As this differential pressure rises, the compressor may become limited by "rod loading". A machine may be only utiliz­ ing a fraction of the available engine horsepower and trip-out due to low suction pressure or high discharge temperature. Both of these trip points are a function of the maximum compressor rod loading which, is, in turn, a function of the differential pressure across an individual stage and the cylinder geometry. Note that at a fixed dis­ charge pressure, a falling suction pressure always results in an in­ crease in discharge temperature. Naturally, operating field personnel will try to avoid repeated compressor shut-downs due to low suction pressure or high discharge temperature. The proper response would be to convert the compres­ sor from single-stage to tandum (i.e. two-stage) operation. However, for reasons enumerated below, field personnel may choose to remain on single-stage operation and: • If on crank-end operation, reduce rpm. • If on head-end operation, open the cylinder clearance valve.

1.5 2.0 2.5 3.0 COMPRESSION RATIO Figure 4—2 Theoretical horsepower for a 0.65 S.G. natural gas.

Both of these methods will effectively eliminate trips caused by high discharge temperature or low suction pressure. Unfortunately, they also reduce natural gas production. Why is it then, that operat­ ing field personnel do not go immediately to tandum operation to

42 TROUBLESHOOTING NATURAL GAS PROCESSING

eliminate trips caused by excessive rod loading? A few of the reasons are: • Making the conversion requires tools, valve parts and time. Also, the machine must be shut-down and re-started. • Often, the well will produce large quantities of water or con­ densate for several hours after the tandum operation is initiated. The vapor-liquid separator drum on the compressor suction line may not be able to keep up with the liquid flow. Manual draining of the drum is therefore appropriate. In practice, this means that an operator must remain at the well site for half a day to monitor and control the liquid level in the compressor suction drum. • It is human nature to avoid step-changes. Converting from single stage to tandum operation entirely alters the wells characteristics; whereas small reductions in speed or suction volume may be made gradually over a period of time. Converting to tandum operation reduces the rod loading by spreading the differential pressure out over two stages. For a given wellhead pressure, the two-stage operation also lowers the compres­ sor discharge temperature. VARYING SPEED If a compressor has an excessively high second-stage (crankend) discharge temperature and a low first-stage (head-end) dis­ charge temperature, one should proceed as follows: • Reduce the adjustable clearance on the head-end. • Slow the machine down. • Balance the above two steps to restore the original wellhead pressure. This technique switches load from the crank-end to the head­ end without changing gas flow. Note that to minimize horsepower the pressure ratio for both stages should be about equal. Operating with the "head-end" cylinder clearance valve wide open will tend to over-load the crank-end, under-load the head-end and waste net en­ gine horsepower. Regardless of other circumstances, a compressor should never be run over its rated speed. However, if the machine will not come-up to its rated speed when it is runnning below its rated horsepower (as calculated above), then something is amiss with the engine.

WELLHEAD COMPRESSION

43

TRANSIENT EFFECTS To further complicate the adjustment of a field compressor, one needs to be aware of certain transient effects that the well imposed on the compressor. • Many wells, immediately after unloading liquids exhibit an increase in wellhead pressure sufficient to overload and stall the engine. • Opening the head-end cylinder clearance valve to reduce the first-stage discharge temperature will immediately increase this discharge temperature and can trip-off the compressor. However, once the wellhead pressure rises due to less gas being moved, the head-end discharge temperature will drop. • After switching a compressor from single-stage to tandum oper­ ation, the second-stage discharge temperature will tend to in­ crease for a few days as the wellhead pressure drops. This often leads to compressors tripping off unless corrective action is taken. • The immediate effects of soap-sticking a well (i.e. unloading liquids by adding a foaming agent into the well's tubing) may be to over-load the engine due to excessive suction pressure. • A compressor which has operated properly in a tandum mode is shut-down for maintenance and thereafter repeatedly trips off on high discharge temperature. The problem is that the well has loaded-up with liquids and the resulting low wellhead pressure is causing too high a compression ratio. MINIMUM SCICTION PRESSURE Figure 4-3 illustrates how an extraneous factor may cause a field compressor to trip-off prematurely. In this case, the field operators were reporting that they could not operate a compressor suction below 70 PSIG. Their experience had taught them the following: 1. They would set the compressor to operate in the tandum mode. 2. Over a period of a few days the wellhead pressure would diminish from 120 PSIG to 70 PSIG. 3. At 70 PSIG (as indicated by the flow chart pressure recorder) the unattended compressor would trip-off. Figure 4-3 shows that this was not quite true. The cause and solution to this problem resided in the pressure setting of the threephase, low pressure separator. As this vessel was set to hold 65 PSIG, it followed t h a t the high pressure separator could not drain

WELLHEAD COMPRESSION

45

whenever it's pressure reached 65 PSIG. The liquid level in the high pressure separator would then rise and carry-over water to the field compressor. As engine fuel was being drawn from the compressor suction line, the water overflowing from the separator entered the engine and caused it to stall. The simple solution to this problem was to reduce the three-phase separator pressure from 65 PSIG to 30 PSIG. DOAL COMPLETIONS Attempting to utilize a single compressor to service both the casing and tubing flows on a dual completion well can present some real problems. On one installation, both the casing and tubing were piped into the suction of the reciprocating machine. However, the operators observed that when the tubing flowed unrestricted into the compressor suction, the casing flow stopped. To "correct" this sit­ uation, a restrictive choke was placed in the tubing side of the well­ head tree. This resulted in a wellhead tubing pressure higher than the compressor discharge pressure! This odd situation resulted in a net reduction of gas flow from the well as a consequence of the com­ pressor installation. The reason for this detrimental effect was that the wellhead compressor was too small. FUEL SAVINGS IDEA One method to achieve significant fuel economies on a wellhead compressor, is to utilize the flash gas vented from the low pressure, three phase separator, as compressor fuel. Assuming that the com­ pressor suction pressure is 300 psig, and the low pressure separator pressure is 30 psig, the equivalent of 1,000 SCF of 1,000 BTU nat­ ural gas, will be evolved from the low pressure separator, for every two barrels of condensate collected. For example, a well serviced by a sixty horsepower compressor produces twelve BSD of natural gasoline. Tying in the low pressure separator vent gas to the com­ pressor fuel gas knock-out drum will reduce the net compressor fuel gas consumed by fifty percent. SUMMARY The objective in adjusting field compressor operations is to maximize the use of available engine horsepower while simultane­ ously maximizing wellhead pressure by keeping the tubing velocity above the entrainment velocity. Compressor rod loading (or high dis­ charge temperature) limits are minimized by adjusting inter-stage pressure with the head-end cylinder clearance valve.

4 6 TROUBLESHOOTING NATURAL GAS PROCESSING

WELLHEAD COMPRESSION

TABLE 4-1 FIELD TROUBLESHOOTING CHECKLIST FOR WELLHEAD COMPRESSORS 1. 2.

3. 4. 5. 67. 8. 9. 10. 11. 12. 13.

14.

15.

Check interstage line temperatures to determine which valves have been removed from a cylinder. Remove disabled valves, cages, and valves in ends taken out of service and replace with gaskets. This reduces parasitic pressure loss. By-pass crank-end when not in use through fuel gas lines. Saves horsepower. Is engine exhaust temperature at least 600°F? Lower temper­ ature indicates inadequate compressor utilization.' Is engine "missing" more than ten times a minute? This also indicates inadequate engine utilization. Can a dual acting machine operating on crank-end be changed to head-end? Can a dual acting machine operating on head-end have the cylinder clearance reduced? Can a dual acting machine operating on head-end be switched to dual acting without exceeding rod loading, maximum exhaust temperature or maximum horsepower? Can tandem machine operating on crank-end be switched to head-end? Is a tandem machine, operating on head-end, limited by max­ imum rod load and/or discharge temperature? If so, correct by going to tandem operation. Are there any bad valves indicated by hot valve caps (suction valves can easily be identified as bad). When switching to tandem, do not maximize gas production first day. Compressor will have a tendency to trip-off due to high discharge temperature. When operating a compressor in tandem, the crank-end dis­ charge temperature can be reduced at constant suction pressure and flow by closing the head-end clearance pocket and slowing down the machine. However, this is a small effect. Opening a clearance pocket to reduce discharge temperature will immediately raise the discharge temperature! However, once the wellhead pressure rises due to less gas being moved, the discharge temperature will drop. For wells served by a three-phase separator, adjust the threephase separator pressure down when going to tandem op­ eration. When the compressor suction falls below 65 PSIG,

16.

17. 18. 19. 20. 21. 22. 23. 24. 25.

26. 27.

47

liquid will carry-over from the high pressure separator and trip the compressor unless the 3-phase separator pressure is reduced. About one out of three wells will start making water "hits" when the compressor suction is dropped significantly. Usually the high pressure separator will not be able to drain suffic­ iently fast for the first hour. It needs to be drained manually for this period. Such wells will double or triple their gas flow after making the water hits. Some wells, after making water hits exhibit an increasing well­ head pressure. This may trip off the compressor due to overload. Is compressor at maximum rpm? Some engines bog down below rated horsepower due to inade­ quate fuel gas flow. Check liquid dumps for leakage (i.e. dump line is cool). Is compressor suction pressure not less than 20 psi below well­ head pressure? Is discharge to suction bypass check valve leaking and/or blocked-in? Does metered flow match the flow predicted by curve charts? About 20% of the time they do not match. Indicates bad valves in cylinders or wrong meter reading. For compressor's with meters on suction, is the engine fuel gas flow being deducted from royalty payments. Is fuel gas from the suction of the compressor? On average, a compressor will use 2% — 5% of it's production for fuel. For tandem machines operating at maximum this can be a much higher percentage. Is a well soap-sticked and flowed back properly? Remember that the discharge temperature from a compressor will increase as the well pressure is depleted.

4 8 TROUBLESHOOTING NATURAL GAS PROCESSING

REFERENCES 1. J.O. Duggan "Estimating Flow Rate Required to Keep Gas * Wells Unloaded". J. Pet. Tech. (December 1961) p. 1173. 2. R.V. Smith "Practical Natural Gas Engineering, Pennwell Publications (1983) pgs. 204-210.

5 PROCESS COOLING IN REMOTE LOCATIONS Those of us trained in the process industry think in terms of circulating cooling water or electric powered fans when we envision a cooling operation. None of this applies in the gas fields. Power to provide cooling is supplied by auxiliary drives connected to gas dri­ ven engines. There are three basic cooling functions required in the gas fields: • Natural gas compressor discharge. • Engine cooling water. • Combustion air discharge from a turbocharger. Air, rather than water, is the usual heat sink employed in gas fields. As an approach temperature of less than 20° is difficult to achieve in an air cooler, summer-time cooling is often marginal. For example, with 105°F ambient conditions, one would not expect to be able to cool a compressor discharge below 115°F to 120°F.

GAS COOLING Underground gas transmission pipelines are externally wrapped in a protective plastic type coating. Gas temperatures in excess of 130°F to 140"F can cause embrittlement and eventual failure of this coating. For this reason, the usual industry practice is to specify that natural gas discharging into a transmission pipeline be cooled to less than 120°F. Also gas entering a pipeline is cooled to promote efficient glycol dehydration. For example, with a n ordinary triethylene glycol dehydration unit, operating at a 900 PSIG contac­ tor temperature, an inlet gas temperature of not more than 125°F 49

50

PROCESS COOLING IN REMOTE LOCATIONS

TROUBLESHOOTING NATURAL GAS PROCESSING

is necessary to meet pipeline moisture specifications. Natural gas effluent from a compressor is typically 150°F to 200°F. Wellhead gas from high pressure wells is also in this tem­ perature range. Most often, gas is cooled in a fin-fan air cooler as shown in figure 5-1. The fan is rotated by a belt drive powered by a compressor's engine. Alternately, the fan may be powered by cir­ culating high pressure oil. 20O"F AIR OUTLET-N LOURVERS I

NATURAL GAS IN

HEAT TRANSFER COEFFICIENTS To check the overall performance of a fin-fan exchanger being used to cool natural gas, the exchanger's heat transfer coefficient "U", should be calculated as follows: U =

A Q

= =

T

=

BELT GAS

GAS COMPRESSOR

=$£=

ENGINE

FUEL-

£

PULLEYS

I20°F

COOLED GAS OUT

Figure 5—1 Gas field cooler.

WHAT CAN GO WRONG Air cooling is deceptively simple. For instance, I have encountered the following problems while troubleshooting air coolers: Air leakage around the tube bundle. Fan speed too low. Belts loose. Fan blade pitch wrong. External tube fouling. Internal tube fouling. Maldistribution of gas in parallel tube passes. Excessive number of tubes plugged. Pass-partition baffle leaking. Excessive gas inlet temperature.

Q T.A

where

mm

NO'F-

51

Extended tube surface area, ft2. Duty, based on specific heat, mass flow and temperature reduction of the gas being cooled, BTU's per hour. The log mean temperature driving force between the air and natural gas, °F.

A typical value for "U", when cooling 800 to 1000 PSIG gas using 3/4" O.D. tubes is four to five BTU's/HR/°F/Ft 2 . Coefficients much lower than this value indicate fouling or a leaking tube-side pass partition baffle. The only difficulty in calculating the heat transfer coefficient is obtaining a representative temperature for the exchanger air outlet temperature. A hand held digital pyrometer is about the best solution to this problem. INSUFFICIENT AIR FLOW If the air flow existing from the tube bundle is hotter than the effluent gas, the chances are there is insufficient air flow to properly cool the gas. In particular, if the air temperature blowing out of the effluent end of the tube bundle is only 10°-15° cooler than the effluent gas, lack of air flow is almost certainly the culprit. FAN TIP SPEED Most fans are designed for a maximum fan tip speed of 14,000 feet per minute. To calculate the tip speed of the fan, do not calcu­ late the fan rpm, from the pulley size and driver speed. The belts may be slipping. Measure the fan speed directly with a tachometer. Then calculate the fan tip speed as follows: 3.14 . 2ir. (RPM) . (F) = T.S. where F

=

Fan blade length, ft.

52 TROUBLESHOOTING NATURAL GAS PROCESSING

T.S.

=

Fan tip speed, ft./min.

If T.S. is less than 14;000 feet per minute, first check the ten­ sion of the fan belts. Next, for fans powered via a belt drive from a gas driven engine, determine if the fan speed corresponds correctly to the engine speed:

where

Fan RPM

=

Engine RPM X (PDE/PDF)

PDE PDF

= =

Diameter of the fan pulley Diameter of the engine pulley

The smaller t h e pulley (also called a sheave) the faster the fan speed. A number of standard size pulleys for fans are readily avail­ able. For example, if you decided more air flow was needed on a cooler, and the calculated fan tip speed was only 10,000 feet per minute, a smaller pulley could be placed on the fan. For instance, changing a 24" pulley to a 20" pulley (both are standard sizes) would increase the fan tip speed to 12,000 feet per minute. The end result of such a reduction in pulley size would then be:

PROCESS COOUNG IN REMOTE LOCATIONS 5 3

is attributed to moths. In their uncounted millions, these tiny kamikazes clog the tube bundle. Along with dust and other assorted bugs, moths must be hydro-blasted from the exterior of tube bundles several times a year. GAS SIDE PROBLEMS Whenever finned—tubed cooling bundles are arranged in paral­ lel, as shown in figure 5-2, a potential exists for poor cooling due to gas maldistribution. A low gas outlet temperature from an in­ dividual bundle is indicative of lack of gas flow through that bundle. To correct this situation, measure the total pressure drop across the coolers. Next, install restriction orifices in the inlet of each bundle, with openings calculated to double the observed pressure drop. This should bring the outlet temperatures from each bundle reasonably close together. If not, take the tube bundle with the low gas outlet temperature off-line for hydro-blasting of the tube side. PASS PARTITION LEAKAGE Figure 5-3 illustrates the function of the pass partition baffle in a two pass air cooled bundle. If this baffle starts leaking, hot inlet

• Air flow would increase by 20% (i.e., linear with fan speed. • The pressure head developed by the fan should increase by 44% (i.e., fan speed squared). • The engine horsepower consumed by the fan would increase by 73% (i.e., fan speed cubed)

IOO°F

wwww

As the horsepower absorbed by a fan is typically in the three to five percent range of total engine horsepower, t h e 73% increment to obtain an increase in cooling air flow of 20% is normally not pro­ hibitive. Caution: It is good engineering practice to check with the fan manufacturer prior to reducing the size of t h e fan pulley. FAN BLADE PITCH Air flow from a fan will vary considerably with t h e blade pitch. The pitch is adjustable. To save engine horsepower, an operator may set the blade pitch at 15° during the winter. During the summer, he may attempt to maximize air flow by setting t h e blade pitch up to maximum—22.5°. Almost all fan cooler blades are adjustable over this range. Watch for loss of air flow through the finned tube bundle by air by-passing the bundle. Especially in older units, the tube bundle may no longer "square-up" with the fan's frame very well. Seal the leaking areas with strips of sheet metal. In southern Texas, the most common cause of reduced air flow

MWWW I80°F 220°F^

■I60°F

1 COMPRESSOR DISCHARGE

COOLED GAS

Figure 5—2 Restriction orifices are often needed to insure adequate cooling.

PROCESS COOLING IN REMOTE LOCATIONS

5 4 TRCKIBLESHOOTfNG NATURAL GAS PROCESSING

gas bypasses the tubes and flows directly to the outlet. To troubleshoot this problem, see if the temperature at the back end of the bundle is cooler than the gas outlet temperature. If so, a leaking pass partition baffle is positively to blame for the high gas cooler outlet temperature.

o

»— < Wt-

incc 5t^f a. a.

EXCESSIVE GAS INLET TEMPERATURE There are three factors which increase an air cooler's inlet tem­ perature:

\

UJ

Qx < o2 uJ" X ^

2

*1

_H I" BERL SADDLES

CVJ

o .2

I

-|5j 3 /IS" HOLES

CO 3 £0 CO

I

GLYCOL TO COOLER

Figure 6—7 External giycol stripper reduces moisture in dried gas by two pounds of water per MM SCF.

f Q_j

/uJ(o

_J_i

OO

I

78 TROUBLESHOOTING NATURAL GAS PROCESSING

After expressing his dissatisfaction with an activity that was transparently a waste of time, Little Red complied. To our mutual surprise, several barrels of a dirty, heavy, hydrocarbon liquid was removed. "Mr. Lieberman", asked Little Red, "I don't understand this at all. The volume of oil we have drained from the glycol surge com­ partment is greater then the volume of the entire compartment— even if it was full! But it wasn't full. The liquid level in the sight glass was below the internal baffle. And even now, after we have drained so much oil, there is still a liquid level in the sight glass. Where did all this oil come from?" "Pump a few barrels of glycol back into the reboiler and I'll draw a picture explaining what happened," I answered. Figure 6-8 is a reproduction of the sketch I made. To understand this drawing, you need to understand that the level in the sight glass is hot necessarily representative of the level in the reboiler's surge compartment. If the density of the liquid in the sight glass is greater than the density of liquid inside the surge compartment, the liquid level observed in the sight glass will be less than the actual liquid level in the reboiler's surge compartment. (Recall how a two-phase manometer functions). As the hot oil inside the surge compartment had a lower density than the cooler glycol in the sight glass, the liquid level inside the reboiler was actually above the internal baffle. Apparently, a thick layer of lube oil had backed-up over this baffle and covered the boiling layer of glycol on the upstream side of the baffle. It was this layer of oil that Little Red had drained off into the now steaming barrels. Because of the location of the level taps, the contents of the sight glass (i.e. the ratio of oil to glycol) was not representative of the contents of fluid in the surge compartment. "So what I thought was an accumulation of glycol in the re­ boiler was really just compressor lube oil picked up by the natural gas," concluded Little Red. "1 suppose the dryer gas we now see is a result of better generation of glycol in the reboiler because the boiling glycol is no longer covered with the heavy oil." "I suspect that's part of the answer. But more to the point, you were likely pumping a mixture of glycol and lube oil back to the contactor. You were really circulating less glycol than you had cal­ culated based on the glycol pump's speed; hence the wet gas." Then what happened to those barrels of glycol that we lost," asked Little Red? "That's easy; the heavy hydrocarbon caused the contactor to foam, and liquid glycol was carried over into the natural gas prod­ uct," I concluded.

GLYCOL DEHYDRATION

79

A FINAL WORD In summary, the essence of troubleshooting glycol dehydrators depends on differentiating between capacity and equilibrium prob­ lems. The glycol reboiler temperature and the pressure and gas inlet temperature to the contactor largely control drying equilibrium. The glycol pump, gas rate (on an actual volumetric basis), and the phys­ ical condition of the tower's trays determine the drying system's ca­ pacity limits. REFERENCES 1. Kohl and Riesenfield's Gas Purification is an excellent data source for most types of glycol (Houston: Gulf Publishing, 1974) 2. R.J. Verritt, Manager, Glycol Product, KMCO Inc., Crosby, Texas, private communication to N. Lieberman, January 25 1984. 3. Silvano Grosso, "Glycol Choice for Gas Dehydration Merits Close Study," Oil and Gas Journal, February 13, 1978, pp 107111. 4. Smith Industries Inc., Equipment Manual, "Section E: De­ hydrators," Houston, Texas. 5. P.D. Hall et al., "Analytical Techniques Can Pinpoint Glycol Problems," Oil and Gas Journal, September 24, 1979, pp. 176188.

RECIPROCATING COMPRESSORS

7

EVALUATING LOST COMPRESSION HORSEPOWER The first step in troubleshooting reciprocating compressors is to quantify the extent of the problem. How much compression work has actually been lost? An approximate rule of thumb is: HP = n- & - 1 Pi

RECIPROCATING COMPRESSORS

Sitting in the courtroom in New York, I had been napping for several hours, while the drone of litigation provided a soothing lullabye. Attired in my three-piece suit, I was being compensated quite handsomely as an expert consultant in a gas transportation dispute. Suddenly, my reverie was broken. My client, the operator of a large gas transmission company sat down next to me. "What are you doing here," he said. iEWe have problems in El Gringo, Texas and you're fooling around in New York." "But you told me to be here today," I argued. "That has nothing to do with it. We have compression problems in El Gringo. I want you down there as soon as possible. "I'll be there on Wednesday," I offered. "No," my client glared at me. "I want you there today. Leave immediately!" Hoping for a reprieve, I pleaded, "But 111 ruin my new Italian shoes. I've only got this suit I'm wearing and there aren't any flights from Kennedy International to the El Gringo Ranchers Co-Op Air­ port." Eight hours later, bathed in the blackness of a humid Texas night, I re-materialized at the compressor station south of El Gringo. "At least I'm the best dressed engineer in Hogg County," I decided. It quickly became apparent why my client was upset. The inlet pressure to the El Gringo compression station had increased from 785 psig to 835 psig, while the transported gas rate had dropped from 100 mm scfd to 90 mm scfd. The pressure downstream of the station held constant at 1085 psig. All this had transpired within a period of two weeks. 80

81

520

where n P2 Px Ti HP

= = = = =

MMSCFofgas Discharge pressure, psia Suction pressure, psia Suction temperature (460 + °F), *R A number proportional to compression work

Inserting the data from the El Gringo operation in the above equation I found: H P (current) = 90 (1100/850 - 1) .520/ 520 = 2JL9 HP (two weeks ago) = 100 (1100/800 - 1). 520/520 =37.5 (Note that the station inlet temperature had remained con­ stant at 60°F) No wonder my client had chased me out of that courtroom in New York: useful compression work had dropped by 28% in just two weeks! The next step in my investigation was to decide if the lost com­ pression work was due to an engine deficiency or a compressor prob­ lem. To ascertain t h a t a gas engine driver is not limiting compres­ sion work, the following questions should all be answered in the affirmative: • Are all engine exhaust gas temperatures running below maxium? • Is the compressor running at its rated speed? • Is the fuel gas manifold pressure below maximum? (At a constant speed, the engines torque is linearly proportioned to the fuel gas manifold pressure.) • Are all unloader pockets closed? For the El Gringo station, the answer to the above questions was yes. Hence, it was not the gas engine's fault that I was ruining my expensive Italian shoes. Next, I checked the unloader pockets. An unloader is a mechanical devise used to reduce the capacity of a compression cyl-

RECIPROCATING COMPRESSORS

82 TROUBLESHOOTING NATURAL GAS PROCESSING

83

inder, without reducing the compressor's efficiency. Figure 7—1 illus­ trates the function of an unloading pocket. By increasing the clear­ ance between the piston and the cylinder head, the volume of the gas compressed per stroke is reduced. As the engine was not limit­ ing, and we were trying to move maximum gas, all the unloader pockets were closed.

jobs is that the theoretical temperature increase of gas due to com­ pression is linearly proportional to compression horsepower. An ex­ tremely useful application of this rule of thumb is the following ap­ proximation:

UNLOADER FAILURE Most large transmission compressors are equipped with pneumatically operated, automated unloaders. A mal-functioning un­ loader remains in an open position and thus reduces the capacity of the compressor. To identify this problem, proceed as follows:

where

• Set the compressor to run at a constant speed. • Close the suspect unloader pocket and note the effect on the engine's fuel gas manifold pressure. • If the fuel gas manifold pressure did not increase, the unloader pocket did not really close, and it is probably broken. Using this technique, I discovered that one end of the compres­ sor's two, double acting cylinders had a defective unloader. This fail­ ure reduced the capacity of the effected cylinder end by 40% and hence reduced the compressor's capacity by 10%. I had now accounted for 10% of the 28% missing horsepower I was searching for. My jacket, vest and tie were secure; but my slacks and dress shirt were well splattered with lube oil. And so, in my well-lubricated attire, I proceeded to take a temperature survey across the cylinders.

T 3 - Tj ~ (P 2 / Pi - 1) Tx, T 2 Pi, P2

= =

Suction and Discharge temperature, °F Suction and Discharge pressure, psia.

It is not too much to say that this relationship is the most im­ portant concept in this book in that it is the most useful. Note that the anticipated temperature rise is independent of compressor speed, unloader configuration or gas volume; it is only a function of the compression ratio—and of course compression inefficiency. While Figure 7—2 can be used to calculate the theoretical temperature in­ crease for compressing natural gas, I used the concept in a more di­ rect manner at El Gringo. Table 7-1 shows that the temperature rise for the individual cylinder compression varied from 28°F for the No. 1 cylinder crank end to 42°F for the No. 2 cylinder crank end. The key point of this table is that compression efficiency varies inversely with tempera­ ture rise. As both the suction and discharge pressures were the same for all cylinder ends, the only reason for the variable temperature rise were different efficiencies of compression. Since the work per­ formed by the piston at each cylinder end was about the same, (ex­ cept for No. 2 cylinder head end, which had the bad unloader) the observed temperature increases were inversely proportional to the

COMPRESSION WORK VS. TEMPERATURE RISE A handy rule of thumb to retain for compression troubleshooting

TABLE 7-1 DISCHARGE TEMPERATURES OF A TWO-CYLINDER, DOUBLE ACTING RECIPROCATING COMPRESSOR

DISCHARGE ADJUSTABLE UNLOADING POCKET PISTON CYLINDER EAD

SUCTION

Figure 7—1 An unloading pocket reduces engine load and volumetric capacity.

Compression End No. 1 cylinder crank end No. 1 cylinder head end No. 2 cylinder crank end No. 2 cylinder head end

Suction Temp..°F

Discharge Temp..°F

Temp. Rise. °F

Relative Efficiency

60

88

28

100%

60

95

35

75%

60

102

42

67%

60

90

30

93%

RECIPROCATING COMPRESSORS 85

84 TROUBLESHOOTING NATURAL GAS PROCESSING

gas flows. This means that if the No. 1 cylinder crank end was mov­ ing 30 MM scfd of gas, then the No. 2 cylinder crank end was mov­ ing only 20 MM scfd and the No. 1 cylinder head end was moving 23 MM scfd. CYLINDER TEMPERATURE MEASUREMENT TECHNIQUE It is not necessary to measure the absolute discharge temper­ ature from each cylinder. If individual thermowells are not availa­ ble, one can still use the above technique to determine the relative compression efficiency of individual cylinder ends. A contact ther­ mocouple may be used to measure the surface temperature of the compressor discharge valve. It is the relative temperature rise of the compressed gas that is of interest to us. To approximate the actual gas temperature from a surface metal temperature, a rough rule of thumb is: T 2 = T m + .1 (T g - T a ) where T 2 = Gas temperature T m = Valve cap surface temperature T a = Ambient air temperature The compressor valve inefficiency, corresponding to the exces­ sive discharge temperature from the No. 2 cylinder crank end at El gringo, could have been due to a variety of problems:

• • • •

Suction compressor valve leaking Late suction valve closure Discharge valve leaking High valve losses due to excessive flow

As I pondered these possibilities in the reddening light of dawn, the chief mechanic appeared. "You know of course, Sehor En­ gineer, that we switched compressor valves last week. The new high efficiency valves we installed are designed to reduce compressor fuel consumption," said the chief mechanic. This was a bit of unpleasant news. I responded to this develop­ ment by requesting that a local contractor perform a Beta Scan sur­ vey of the compression cylinders. A Beta Scan (other common trade names are MIT, SEL, DECA, Enthalpy) is a Pressure-Volume Dia­ gram describing the actual compressor cylinder end performance. The pressure inside the cylinder is plotted against the piston posi­ tion. A piston position of 2ero percent corresponds to the piston pos­ ition closest to the cylinder heat. A perfect Pressure-Volume Dia­ gram is shown in Figure 7-3. If the sketch looks familiar, you were probably an "A" student in thermodynamics; Figure 7-3 is the famous Carnot Cycle. Figure 7-4 shows Beta Scan for several maladies A B C D

• Late compressor discharge valve closure • Leaking piston rings

\ DISCHARGE

CYLINDER INTERNAL PRESSURE

RISE F

75

= SUCTION VALVE OPENS « PISTON REVERSES DIRECTION - DISCHARGE VALVE OPENS - END OF STROKE

Figure 7—2 Theoretical temperature rise due to compression.

-DISCHARGE PRES.

/y\R

N\/^WORK/ / A E

£

COMPRESSION RATIO

F

SUCTION

^o

-SUCTION PRES.

CYLINDER VOLUME OR PISTON POSITION

Figure 7—3 Camot cycle for a reciprocating compressor.

8 6 TROUBLESHOOTING NATCIRAL GAS PROCESSING

RECIPROCATING COMPRESSORS

effecting compressor valves. Why guess about performance when it is possible to determine precisely what is transpiring inside the cylinder? The Beta Scan plot obtained from the No. 2 cylinder crank end is shown in Figure 7-5. This plot clearly shows that the new valve installed in this cylinder end was experiencing an abnormal 25-30% loss in compression work. INTERPRETING BETA SCANS The area encompassed by the Beta Scan plot is proportional to the compression work performed by the piston. Unfortunately, not all of this work is of use in moving gas down a pipeline. For in­ stance, the top horizontal line shown in Figure 7-5 is the compres­ sor discharge pressure. The area of the plot above this line is wasted compression work caused by: • Pulsation in the discharge line • Discharge valve opening too slowly • Excessive resistance to flow of gas through the discharge valve The bottom horizontal line in Figure 7-5 is the compressor suc­ tion pressure. Area below this line also represents wasted compres­ sion work due to the same problems listed above; except of course only the suction valves are involved. The peaks and valleys indi­ cated on the compression and expansion cycles are due to valve leak­ age and again represent wasted work. There should be no gas flow into or out of the cylinder during the expansion or compression cy­ cles. If both the discharge and suction valves did not leak, the lines VALVE SPRINGS TOO TIGHT

87

on the Beta Scan plot representing the expansion and compression steps would resemble those of the Carnot Cycle; that is, smooth curves. Drawing a curved line tangent to the peaks and valleys of the expansion and compression steps inside the Beta Scan quantifies the extent of wasted horsepower due to valve leakage during these steps. The shaded area shown in Figure 7-5 is then the sum of the compression work wasted due to valve inefficiencies and piping pul­ sation problems. To this lost work must be added the detrimental ef­ fects of piston ring leakage. GOING HOME The chief mechanic was astonished when I instructed him to put the old compressor valves back into service. "Senior Engineer," he gasped, "You do not impress us with your fancy clothes. If everyone was like you, we would still be living in caves." Regardless, the old compressor valves were installed in the machine. The Chief Mechanic argued that he could eliminate the peaks shown on the suction portion of the cycle in Figure 7—5 by changing to weaker springs on the suction valves. Also, he felt that discharge valve plates with a larger open area would minimize the horsepower lost during the discharge cycle. All he wanted was a few days to purchase the new springs and valve plates. He was probably SHADED AREAS REPRESENTS COMPRESSOR INEFFICIENCY

VAU/E SPRINGS TOO WEAK

1085 PSIG CYLINDER PRESSURE

CYLINDER INTERNAL PRESSURE

8 3 5 PSIG

PISTON

POSITION

IN CYLINDER

Figure 7—4 Beta Scan plots are a powerful troubleshooting tool.

PISTON POSITION Figure 7—5 Beta Scan plot for El Gringo pipeline compressor, cylinder # 2 .

8 8 TROUBLESHOOTING NATURAL GAS PROCESSING

right. But the old compressor valves were dropped back into the cy­ linder valve ports; the defective unloader valves were repaired; and the machine was put back on-Une. A new Beta Scan was obtained which showed compressor valve losses had dropped from 25-30% to about 10%. I was pleased to report that evening to my client that the situ­ ation at the El Gringo station had been restored. "Never mind that," he responded, "you're supposed to be in New York in the morning. And make sure you're dressed decently for a change," he concluded. REDUCING VALVE LOSSES One cost effective means of reducing compression valve losses and enhancing compressor efficiency is to replace valve plates with thermoplastic valve plates equipped with additional flow ports (i.e. openings in the plates for gas passage). Modifying valve plates in this manner will reduce horsepower valve losses due to the frictional pressure drop. While modifications of this type will save energy and enhance capacity, they are appropriate only in those cases where in­ creased valve losses are related to increased gas flow. In my experi­ ence, large inefficiencies in reciprocating compressors are most often related to increased compression ratios and not to gas flow rates. Compression leaks through worn piston rings and leaky valves are enchanced at higher compression ratios. Often, an unexplainable temperature rise across a compressor cylinder end, as reflected in a hot discharge valve cap, will moderate to a normal temperature rise, when the compression ratio is only moderately reduced. For exam­ ple, for one machine equipped with plastic poppet valves (i.e. com­ pressor cylinder valves designed for high capacity; but low compres­ sion ratios), valve losses as measured by a Beta Scan were reduced from 25% to 10% when the compression ratio was reduced from 1.42 to 1.28, even though the gas volume moved through the compressor increased by over 50%. Reciprocating compressors may be limited by a third factor (in addition to engine horsepower availability and cylinder volumetric efficiency) which is called rod loading. The piece of hardware t h a t connects the piston to the crankshaft components is called the piston rod. ROD LOADING One frequent cause of downtime in reciprocating compressor operation is rod breakage. A piston rod is not designed with the same philosophy as a bridge: Once the manufacturer's designated rod loading is exceeded, the rod will likely fail. Rod loading is cal­ culated as follows:

RECIPROCATING COMPRESSORS

89

Rod Loading = Ap • P d - (A p - Ar) • P s where Ap Aj. Pd Ps

— = = =

Piston area, square inches Rod area, square inches Discharge pressure, psig Suction pressure, psig

Thus, regardless of the horsepower load or speed, there is a maximum presure increase that a reciprocating compressor can tolerate. While this is simple enough, there is a dangerous com­ plicating factor. The discharge pressure to be used in the above cal­ culation is not the discharge line pressure; it is the peak pressure developed inside the cylinder (i.e. behind the discharge valve). As can be seen from the Beta Scan plot depicted in Figure 7-5, this peak pressure may be drastically higher than the discharge line pressure. Both pulsation problems and inadequate valve lift, or valve speed, raise the cylinder's internal peak discharge pressure. For example, a piston rod failure on one compressor was precipitated when weak valve plate springs were replaced with stronger springs requiring a greater valve plate pressure differential to open. COMPRESSOR PANEL BOARD PROBLEMS If the pneumatic relays on a panel board begin to stick in a closed or open position, the problem is likely failure of the rubber O-ring seals. Traces of olefins in natural gas, as well as H 2 S and C0 3 , will, with time, deteriorate the O-rings. The leaking or swel­ ling of seals that result prevent proper relay operation. To prevent this deterioration dried air, as opposed to natural gas, should be used as instrument gas to the panel board. Of course, if the air is not dried below it's dew-point, the resulting presence of moisture and solids and/or salts or freezing temperature in the in­ struments will do far more damage than traces of olefins.

REFERENCES 1. Bell Valve Company Technical Bulletin, "Compressor Cylinder Capacity Control, Merriam, Kansas. 2. Cooper-Bessemer Performance Calculation Procedures for Gas Engine Compressors, November 16, 1970.

RECIPROCATING ENGINES 91

8 RECIPROCATING ENGINES

One cannot drive very far in an active field without run­ ning into a reciprocating compressor. Machine sizes range from mod­ est 30 horsepower wellhead units to giant 4800 horsepower pipeline booster compressors. Between these two extremes are a variety of machines which cannot be rigorously divided into field or transmis­ sion compression service. Speeds range from 350 rpm (slow speed) to 1000 rpm (high speed). Almost all reciprocating compressors of mod­ ern vintage are driven by a separate reciprocating, natural gas fueled, internal combustion engine. While troubleshooting these ubiquitous engines is a highly complex job—mostly beyond the scope of this book—there are a few concepts which the field engineer should understand. The critical symptom of trouble in a reciprocating engine is ab­ normal cylinder exhaust temperatures. For this reason, I always begin an assignment involving reciprocating compressors by over­ hauling and recalibrating the thermocouples on the gas exhausts from each power cylinder.

ERRATIC CYLINDER EXHAUST TEMPERATURES A typical 1200 horsepower engine may have eight power cylin­ ders. A reasonable temperature spread between the lowest and high­ est cylinder exhaust temperatures is 80"F. If one of the exhaust tem­ peratures is very low, the cylinder is not firing properly. This is a serious matter. When one cylinder mis-fires, the other seven cylin­ ders must work 14% harder to maintain the preset engine speed. This is accomplished automatically by injecting more fuel gas into 90

all eight power cylinders. That is, when an engine slows down, the governor speed controller steps on the accelerator to restore engine speed. -This increases the cylinder exhaust temperature of all the cylinders. A high cylinder exhaust temperature rapidly reduces the horse­ power developed by each power cylinder. Principally, the piston rings experience excessive wear. Really high temperatures sustained for extended period's will also damage the cylinder liners and can crack the cylinder heads. Also, the exhaust valves may become de­ fective and no longer seal properly. As the efficiency of the power cylinders to convert heat to work are reduced due to overheating, more fuel gas is consumed to keep the engine horsepower up to that level required to maintain the gas compressor speed. This causes progressive engine over-heating. Thus, a self-destructive cycle is begun when a single power cylinder begins to mis-fire. Mis-firing is caused by faulty ignition wires, fouled spark plugs, magneto and timing problems, etc. Once a mis-firing power cylinder is identified, a competent mechanic can easily correct the problem. While low cylinder exhaust temperature is a good primary indication of a mis-firing problem, there is a more sophisticated method to continuously troubleshoot reciprocating engines.

TORSIONAL VIBRATION ANALYZER The instrument which owns this fine sounding designation is really a simple tachometer. When one of the power cylinders driving a shaft mis-fires, the shaft momentarily slows down. The torque out­ put from the shaft is reduced for a fraction of a second. The Torsional Vibration Analyzer records this brief period of reduced torque by producing a spike on a recording strip chart. Identifying the mis­ behaving cylinder is then a simple matter. First, one of the power cylinder spark plug wires is disconnected. Next, the strip chart re­ corder produced by the torsional vibration analyzer is checked. If the number of spikes has doubled, the power cylinder with the discon­ nected spark plug is NOT the defective cylinder. By continuing this trial and error procedure, one can determine that the cylinder that is mis-firing will coincide with that spark plug which when discon­ nected, will NOT produce additional spikes on the torsional vibra­ tion analyzer. Retrofitting a reciprocating engine with individual power cylin­ der exhaust thermocouples and a torsional vibration analyzer, is akin to restoring the sight of a blind man. Unless an engine is going to routinely be operated a t less than 70%—80% of it's rated horse­ power, the types of monitoring equipment described above will be re-

92 TROUBLESHOOTING NATURAL GAS PROCESSING

quired to obtain both a high horsepower output and a 95 + % engine on-line factor. HIGH CYLINDER EXHAUST TEMPERATURE Both a deficiency, or an excess in combustion air availability may cause high cylinder temperatures. Leaking engine exhaust val­ ves, worn piston rings, improperly set fuel injection valves all may contribute to a wrong fuel to air ratio. However, as this is not a book on the repair of internal combustion engines, we shall concen­ trate on one extremely common cause of high cylinder exhaust tem­ peratures; that is, turbocharged deficiencies. What is the difference between a supercharged engine and a turbocharged engine? Why does retrofitting an engine with a turbocharger increase its rated horsepower? Note that the horsepower av­ ailable from an engine is ultimately proportional to the pounds of air the engine can force through itself. More air means more horse­ power because more fuel can then be burned without exceeding the metallurgical temperature limits of the cylinder and piston. A supercharger draws power from the engine's shaft to com­ press and blow air into the engine inlet manifold. The supercharger is then consuming a portion of the work produced by the engine. The turbocharger is powered by the hot, pressurized exhaust gases from the engines exhaust gas manifold.

RECIPROCATING ENGINES

the shrouded inducer and exits under pressure from the impeller. The rotor is spun by hot engine exhaust gas passing over the tur­ bine blades. A typical set of turbocharger operating conditions are: Fuel Gas Pressure Ambient Pressure Suction Pressure Discharge Pressure Ambient Air Temperature Discharge Temperature

A turbocharger is simply a small gas turbine driven, single stage, centrifugal air compressor. Figure 8—1 shows the rotor assem­ bly of a typical high pressure turbocharger. Air is drawn through

12.5 14.5 14.3 23.8

PSIG PSIA PSIA PSIA 78°F 194°F

The compressed air delivered by the turbo charger ac­ complishes two functions; first it scavenges the hot residual gases otherwise left in the power cylinder of the exhaust stroke, and re­ places these with cooler fresh air; second, it fills the cylinder with an air charge of higher density at the end of the suction stroke. The provision of a greater amount of fresh air permits the combustion of a correspondingly greater amount of fuel, 1 and an increase in en­ gine horsepower. For a fixed compressor speed, the fuel gas manifold pressure should result in a pre-determined turbo charger speed. This data is

IMPELLER

TURBOCHARGERS

Most modern separable (as opposed to integral) compressor-en­ gine combinations of 700 horsepower and above, are driven by turbo­ charged reciprocating engines. One of the principal reasons for turbocharging an engine is the reduction in nitrous oxides (NOX) in the engine exhaust gas. Even in the remotest wastelands of West Texas, environmental restriction on NOX emissions must be obeyed. Also, turbocharging an existing engine is a cost effective means to up-rate its horsepower. For example, the standard diesel driven sub­ marine engine of World War II has been transplanted to the gas fields and converted to natural gas fuel. The rated horsepower of this six cylinder engine may be increased from 1350 horsepower to 1650 horsepower by retrofitting with a turbocharger. (The last time I saw this done however, the air inlet line to the turbocharger was not increased in size. This error negated the benefits of the turbocharger.)

93

TURBINE BLADES

SHROUDED INDUCER

figure 8-1 A turbo charger rotating assembly. Engine exhaust gases spin the turbine, while combustion air is compressed by the impeller.

RECIPROCATING ENGINES 9 5

9 4 TROUBLESHOOTING NATURAL GAS PROCESSING

available from the turbo charger manufacturer, who can also pro­ vide a custom made tachometer for his equipment. The turbocharger speed should result in a discharge pressure, which again, may be calculated from the manufacturer's data. A deficiency in turbo charger operation is indicated by a lower than calculated speed and discharge air pressure. This inefficiency can result from several problems: • Resistance to exhaust flow such as back pressure from a cata­ lytic converter. • Fouling of the rotor due to dust or dirt passing through t h e air filter. This problem manifests itself by low discharge pressure rather than reduced turbo charger speed. • Fouling of the turbine blades—possibly due to cracked engine cylinder heads permitting engine coolant to enter the exhaust gas manifold. • Partially plugged air inlet filter. • Leakage at the turbine. The turbine to shroud tip clearances should be compared to the original manufacturers specifi­ cations. • Leakage at the impeller. The impeller to casing clearances should also be compared to original specifications. Inefficiencies on the compressor end will correlate with a higher than predicted temperature rise of the air flow through the turbo charger. For example, the discharge temperature of 194°F listed on the preceding page corresponds to a normal centrifugal compressor efficiency of 77%. The correlation to calculate tempera­ ture rise due to compression is summarized in chapter 7 Figure 2.

BETA SCANS More often than I had expected, I find that my engineering education can actually be used in solving problems in the real world. For example, I never imagined that the dull chapter on the Otto Cycle in my thermodynamics text contained information I would some day need. And so surrounded by stunted Mesquite trees and the ubiquitous Prickly Pear Cactus, I sketched in the sun baked caliche earth, for the benefit of a compressor's stations untutored mechanics, a crude rendition of an Otto Cycle, which I have now re­ produced in Figure 8—2. Juan Garza, the compressor station's chief mechanic eyed the Beta Scan machine suspiciously. "Mr. Lieberman, I've worked at this station for six years. Hernando and I, we know when a cylinder is mis-firing. We can hear it. Also, we watch the individual cylinder exhaust temperatures. A low temperature also indicates mis-firing; a high temperature means we have to adjust the air to fuel ratio. We don't really need such an expensive machine. Right Hernando! We don't need a machine to draw us pictures. We can do our job without such pictures."

INTERNAL CYLINDER PRESSURE

A AFTERBURN If you have t h e dubious privilege of observing an engine operating with a hole in the exhaust gas manifold, you are likely witnessing the effects of afterburn. I once saw a 4000 horsepower en­ gine's exhaust system disassembled to repair such a hole and con­ cluded: • One cylinder, which had been running rather lean, supplied enough oxygen to continue combustion in the exhaust manifold. • A localized hot spot was created which burned a hole through the exhaust gas manifold. The turbine end of the turbo charger was apparently also ad­ versely effected by this afterburn.

c

0 M R U S T 1 0 N

Nk

WORK

S \ \

K_ E

N.

VfA CQW^_ KR ESSI5FT-*-

~~^B

CYLINER

VOLUME

Figure 8—2 An idealized Otto Cycle. Side AB represents that instant when the exhaust valves and air intake valves function.

96

TROUBLESHOOTING NATURAL GAS PROCESSING

RECIPROCATING ENGINES

Signifying his assent, Hernando spit some tobacco juice on my boots. The pictures that had upset J u a n Garze were Beta Scan plots. A Beta Scan is a recording of a cylinder's internal pressure plotted against it's piston position. Pointing to my scratchings in the caliche, I began to explain the meaning of an Otto Cycle to J u a n and Hernando. "I think of an Otto Cycle as a n idealized Beta Scan. What I mean by idealized is that the combustion of the fuel gas would take place instantaneously when the piston was closest to the cylinder head (i.e. zero percent on the horizontal axis of Figure 8-2). Further­ more, the exhaust gases would exit from the cylinder completely and instantaneously when the piston was furthest from the cylinder head (i.e. 100% on the horizontal axis of Figure 8—2). I think you all can visualize that any deviation from this ideal situation would reduce the amount of work developed by the piston. These plots that have just been produced by the Beta Scan machine for the two power cylinders (as shown in Figures 8-3 A & B) illustrate how the performance of a real engine deviates from an Otto Cycle". "Excuse, please", J u a n interjected, "This Mr. Otto, does he re­ pair engines too?" "No—I think he's dead, please allow me to continue! Now the area enclosed by the Beta Scan plot is proportional to the work de­ livered by the piston to the crankshaft. Note how the area's enclosed by the Beta Scan plots are smaller than the enclosed area of the Otto Cycle. Actually, the Beta Scan machine has intergrated these areas and calculated that the "A" cylinder (see Figure 8—3A) is de­ veloping 204 horsepower, while the "B" cylinder (see Figure 8—3B) is developing only 142 horsepower. Don't you all agree that "A" Beta 50Q

250

50

CYLINDER

100

0

VOLUME'

50 ■ »

Figure 8—3 Actual Beta Scans for two identical cylinders. Cylinder "B" is suffering from bad valves.

97

"What you think Hernando. Take a close look," suggested Juan. Squirting tobacco juice over my rendition of an Otto Cycle, Hernando moved closer to the Beta Scan plots. The brown caliche was permanently imbedded underneath his fingernails, "The value of the Beta Scan is that you can quantify the re­ lative performance of individual cylinders. For instance, cylinder "B" is producing 62 less horsepower than cylinder "A". This indicates that we need to replace the piston rings and possibly repair the en­ gine exhaust valves", I concluded. Hernando jabbed a stubby and not overly clean finger at the Beta Scans. He began to talk rapidly in Spanish. "What's he saying, Juan. He's getting the plots dirty. I don't understand Spanish!" "I don't understand him either, Mr. Lieberman. He keeps talk­ ing about the peak pressure of cylinder "B", it is only 300 psig and it should be 500 psig, Hernando says that the shape of the Beta Scan plots may indicate inadequate exhaust gas scavenging by the fresh air or that the firing timing is off. He wants to pull "A" 's cy­ linder head off for inspection. Hernando says your interpretation of the Beta Scan plots is an oversimplification. Do you understand any of this—maybe I'm not translating right". "What else does Hernando say", I ventured, as my self-image dwindled. "Hernando says that routine Beta Scan checks of engines run­ ning near their rated horsepower is always a good idea. Especially in hot weather, when engines lose 5% of their horsepower potential for each 10°F increase in ambient air. Checking the actual horse­ power output for each cylinder, is a cost effective method of troub­ leshooting an engine. For routine tuning of an engine, such as ad­ justing the fuel injection valves to each cylinder checking compres­ sion pressure with a special pressure gauge is sufficient. The peak pressure measurement gives some of the same information as the Beta Scan. For example, the peak pressure for cylinder "A", as shown on it's Beta Scan is 500 psig. A low peak pressure is a way of detecting bad valves or faulty piston rings". Hernando hitched-up his baggy pants and J u a n continued to translate. "Hernando wishes to summarize the procedure he uses to troubleshoot reciprocating engines. He suggests that you make a few notes. To start with, he reviews the temperatures measured by the individual cylinder pyrometers. A low temperature indicates lack of combustion, which is not the same as no ignition. A cylinder with a high exhaust temperature may be suffering from retarded firing which results in late combustion.

98 TROUBLESHOOTING NATURAL GAS PROCESSING

Alternately, a hot cylinder may be the result of a high fuel-toair (i.e. rich) mixture. "Next, he checks the voltage and firing timing of each spark plug. Then, using his Statiscope, he checks for ignition from the spark plugs. Of course, an operable spark plug does not guarantee ignition. "Using his BMEP (Brake Mean Effective Pressure) gauge, he measures the average pressure inside each power cylinder. The BMEP reading is roughly proportional to the horsepower developed by each cylinder. Afterwards, he adjusts the fuel gas valves to each cylinder so that they develop the same BMEP reading, within the constraints of maximum exhaust temperature, for each cylinder. "Of course, one can hear severe detonation inside a cylinder by placing one's ear in contact with the cylinder through an interven­ ing steel rod. However, to pick up less dramatic detonations, a Keine Pressure Indicator is required. This instrument measures the peak pressure reached inside a cylinder. A cylinder that exhibits both a low BMEP reading and a high peak pressure is suffering from de­ tonation. Leakage of exhaust gas back into the cylinder through a defective engine valve is one possible cause of detonation. A wrong air/fuel ratio may also result in detonation. "A Beta Scan, which produces an Otto Cycle plot, is as you de­ scribed, quite useful. Hernando would only add that a sign of deto­ nation is when the top of the Otto Scan plot is tall and narrow. By the way, he says, you must read Edward Obert's, "The Internal Combustion Engine (McGraw-Hill)", if you want to become know­ ledgeable in this area. "Finally, he checks the exhaust gas composition using a Teledyne 980. The combustible reading should not be more than 0.2%. The oxygen reading should be between 10% to 12%. Excess oxygen above 12% will waste fuel and reduce the horsepower developed by the engine. More importantly, an oxygen deficiency reduces heat dis­ sipation from the cylinder, leaves exhaust gas behind inside the cy­ linder after the expansion step and thus may promote both detona­ tion and excessive exhaust gas temperature. Compression leaks, such as those caused by bad piston rings or defective exhaust valves, as well as turbocharger problems, are all rather common causes of low oxygen in exhaust gas. Also, external factors which reduce the intake air density diminish the oxygen content of engine cylinder exhaust gas. 2 Hernando also says that it is important too . . . ." But by this time, I was no longer listening to Juan. I began edging away from Hernando, who had just sprayed my boots with a fresh layer of tobacco juice.

RECIPROCATING ENGINES

99

REFERENCES 1. Elliot Company, "Instructions for Installation, Operation, & Maintenance of Type "H" High-Pressure Turbocharges, In­ struction Book TC-30E", Jeannette, Penna. 2. Hudson, F.H., President RO-CIP, Canton, Texas; Private Communications.

LOSS IN CENTRIFUGAL COMPRESSOR CAPACITY

9

101

charge temperature? Why was the temperature rise across Unit # 3 21°F (or 23%) greater than Unit #1?

COMPRESSION HORSEPOWER PROPORTIONAL TO TEMPERATURE RISE A few useful (but thermodynamically not prescise) rules of thumb for field troubleshooting compressors are:

LOSS IN CENTRIFUGAL COMPRESSOR CAPACITY

.BHP =* ( £*_ - 1 .BHP ^ A T x Q where AT .BHP

Why is it that three identical centrifugal compressors, aligned in parallel were performing so differently? My client's Chief En­ gineer had fortunately already solved the problem. He explained t h a t the compressor at the end of the piping header was being "starved for gas". That was why the gas flow through that particular compressor was so low compared to the other two machines. The Chief Engineer's solution to this problem was to connect a new gas line to the far end of the existing compressor suction piping. Table 9-1 shows the operating data for the three centrifugal compressors. The pressure readings were taken with a single pres­ sure gauge so as to eliminate relative errors. Note that the suction pressure on Unit # 3 (i.e. the comprssor at the far end of the suction header) had a two PSIG lower pressure than Unit # 1 . The Chief En­ gineer took this as proof that Unit # 3 was "starved for gas". Was he right? Could a two PSIG pressure drop in the suction piping account for the difference in flow of 21 MMSCFD of natural gas shown in Table 9-1? The answer to this query is contained in Figure 9 - 1 . P 2 /Pi is the compression ratio. If you calculate the com­ pression ratios for Unit # 1 and Unit # 3 from the data in Table 9 - 1 , you can see t h a t the loss in flow predicted from Figure 9-1 for Unit # 3 versus Unit # 1 is only about 1.0 MMSCFD! I explained these calculations to my client's Chief Engineer. "Why then the difference in flow", he mused. "It must be t h a t the flow meters need recalibration". Examine the temperature in Table 9-1 to see why it was ob­ vious that the flow meters were correct. The suction temperatures were, of course, all the same; but why the large variance in dis100

= =

Discharge minus suction temperature. Work or horsepower delivered to the compressor shaft. P 2 = Discharge pressure, PSIA P x = Suction pressure, PSIA .Q = Gas flow, SCF or moles It is a characteristic of gas turbine driven compressors that the driver horsepower is a function of the combustion air compressor speed. For Unit # 1 and Unit # 3 , as shown in Table 9—1, the com­ bustion air compressor speeds were identical. Hence, the horsepower delivered to both gas compressors were about the same. Note also from Table 9 - 1 , t h a t (AT x Q) for Unit # 1 and U n i t # 3 were within 5% of each other: Unit # 1 = 90°F x 90 MMSCFD = 8100 Unit # 3 = H I T x 69 MMSCFD = 7660 TABLE 9-1

OPERATING DATA FOR THREE CENTRIFUGAL COMPRESSORS RUNNING IN PARALLEL Flow, MMSCFD Suction Pressure, PSIG Discharge Pressure, PSIG Suction Temperature, °F Discharge Temperature, °F Gas Compressor Speed, RPM Combustion Air Compressor Speed, RPM

Unit#l

Unit # 2

Unit # 3

90 605 1015 88 178 11,600

87 604 1015 88 181 11,700

69 603 1016 88 199 12,400

13,000

13,000

13,000

LOSS Di CENTRIFUGAL COMPRESSOR CAPACITY

102 TROUBLESHOOTING NATURAL GAS PROCESSING

The Chief Engineer concluded from this analysis that the horsepower being absorbed by the compressor per SCF of gas moved, was greater in Unit # 3 than Unit # 1 , by 23%—that is, COMPRES­ SION WORK PER SCF OF GAS MOVED IS PROPORTIONAL TO THE TEMPERATURE RISE OF THE COMPRESSED GAS. This rule,. is an important concept for the troubleshooter to remember. This rule of thumb explained how Unit # 3 could absorb the same amount of horsepower as Unit # 1 , while only moving 75% as much gas as Unit # 1 . "I understand from everything you said, and the observed tem­ perature and pressure data, that for some unknown reason, the com­ pression EFFICIENCY of Unit # 3 , relative to Unit # 1 , has deterior­ ated", said the Chief Engineer. To quantify the Chief Engineer's thoughts, the following ap­ proximation for relative compressor efficiency is applicable:

where R.E.

=

Of course, the above relationship cannot be applied when inter­ stage coolers are in service. To summarize why Unit # 3 was moving less gas than Unit # 1 : • Driver horsepower was the same. • External piping problems were insignificant. • The diminished flow through Unit # 3 was real, and not a simple meter error. Therefore, the problem had to be an internal compression prob­ lem. There are two factors which cause loss in flow through a com­ pressor accompanied by an abnormal temperature rise: • Leakage of the gas back across the rotor wheels. • Rotor fouling. LABYRINTH SEAL LEAKAGE

(s-0

=±-J—-— AT Relative compressor efficiency (only useful when comparing the operation of two similar machines). R.E.

103

1.75

Figure 9—2 is a simplified sketch of a three stage centrifugal compressor. The labyrinth seals serve the same function for a com­ pressor that a wear ring serves for a centrifugal pump—that is, it reduces leakage from the high pressure side of each wheel (i.e. im­ peller) back to the low pressure side. Leaking labyrinth seals result in increased internal recycling and recompression of gas, with a con­ sequent heat build-up. The erosive action of frac sand or formation sand, carried into a compressor by natural gas, may cause labyrinth seal leakage. More commonly, compressor surging or rotor vibration induced by bearing damage are the culprits which lead to labyrinth seal leak­ age.

1.73

P'2 Pi

ROTOR FOULING

1.71 1.69 1.67

_l 65

I 75

I 85

MMSCFD Figure 9—1 Operating curves for a centrifugal compressor.

L. 95

The gas turbine driven compressor described in this chapter is the common split shaft design. Figure 9—3 illustrates this arrange­ ment. Note that the turbine wheel driving the gas compressor is not mechanically coupled to the combustion air compressor. Firing more fuel gas in the turbine will speed-up the combustion air compressor, which in t u r n drives the gas compressor faster. However, there is no particular reason for both the combustion air compressor and the gas compressor to run at the same speed. Referring to Table 9—1, note that the combustion air compressors for Unit # 1 and Unit # 3 are both spinning at identical speeds. In contrast the gas compressor end of Unit # 3 is running quite a bit faster than Unit # 1 .

LABYRINTH SEAL SUCTION BEARING

DISCHARGE

SHAFT DIFFUSOR OR

DIAPHRAGM

Figure 9—2 A greatly simplified sketch of a 3-stage centrifugal compressor.

EXHAUST

PRODUCTS OF COMBUSTION

AIR

t-/COMBUSTION ZONE

DISCHARGE

I 5

BEARING

BEARING

SHAFT

COMBUSTION AIR COMPRESSOR

TURBINE (NOTE SPLIT SHAFT)

GAS COMPRESSOR

Figure 9—3 A natural gas fueled gas turbine driving a gas compressor of the split shaft design.

106 TROUBLESHOOTING NAT0RAL GAS PROCESSING

Figure 9—1 illustrates the principle that the faster a centrifugal compressor rotates, the more gas it will move at a given pressure ratio. The data in Table 9-1 seems to contradict this principle. The Chief Engineer noted this abnormality, and observed, 'Terhaps the speed indicator is wrong. How is it possible! We have two identical compressors running in parallel, the faster of which is pumping less gas". It is a characteristic of split shaft gas turbine driven compres­ sors to develop a disproportionately high gas compressor speed when the gas compressor's rotor fouls. The fouling deposits which adhere to the rotor effectively reduce the centrifugal force imparted to the gas by the rotor's impellers. This reduction permits the gas compres­ sor to spin with less resistance and hence t u r n faster for a given combustion air compressor speed. Naturally, the fouled rotor's re­ duced capability to impart centrifugal force to the gas reduces the gas compressors capacity and efficiency. "You're talking in riddles", gasped the Chief Engineer. "What you mean to say is that when a gas compressor rotor fouls, it will spin faster but move less gas at a reduced compression efficiency". "As a matter of fact", I added, "these are the factors which lead me to believe that the cause of the reduced efficiency in Unit # 3 is not labyrinth seal leakage, but fouling of the gas compressor rotor's impellers".

TYPES OF FOCILING DEPOSITS "What types of material do you think could have deposited on the rotor. We do a pretty good job of removing drilling mud. and sand from our gas prior to compression", said the Chief Engineer. "Some of the fouling deposits I have seen consist of: • Sulfur • Salt • Biological wastes produced from the action of bacteria which live inside transmission pipelines and thrive by metabolizing sulfates and the iron pipe. • Paraffin • Corrosion inhibitors, injected at the wellhead to protect the gathering system piping" The Chief Engineer concluded t h a t the time had come for ac­ tion. He ordered that Unit # 3 be shut down and the suction and dis­ charge piping be disconnected. When the suction pipe spool piece was removed, we were able to see the entrance to the compressor.

LOSS IN CENTRIFUGAL COMPRESSOR CAPACITY

107

It was absolutely clean. The Chief Engineer's eyes gleamed with a trace of hostility. However, when the discharge piping section was removed, the tension melted away; the exit of the gas compressor was fouled with a thick, black, greasy substance, commonly called paraffin. This black, greasy, waxy material is insoluble in water or methanol, slightly soluble in natural gas condensate and quite sol­ uble in aromatics. One method of preventing it's build-up is to inject a high boiling point aromatic solvent into the suction of the com­ pressor. Normally, injecting several pints per MMSCF of a solvent obtained from Chemlink Chemicals minimized the accumulation of paraffin inside a compressor. (See chapter on Corrosion and Fouling.) SALT DEPOSITS We disassembled the rotor on Unit # 3 , sand blasted each com­ ponent, and after installing a solvent injection system on the suction line, returned the compressor to service. Table 9—2 summarizes the results of this procedure. The Chief Engineer noted with gratifica­ tion that Unit # 3 now had a smaller temperature rise than Unit # 1 , thus indicating it had a higher compression efficiency. A month went by before I was called back to the compressor station. The Chief Engineer informed me that the same thing had happened again. Unit # 3 had lost capacity, and was exhibiting a high discharge temperature. Inspection of the compressor discharge did not indicate any fouling deposits. Even though the solvent in­ jection program was working, we had not yet licked the problem. "I know what's wrong", stated the Chief Engineer". The gas compressor speed has increased relative to the speed of the combus­ tion air compressor. This has coincided with a gradual reduction in capacity of Unit # 3 . Everything now indicates fouling of the gas TABLE 9-2 DATA AFTER CLEANING UNIT # 3

Flow Suction Pressure, PSIG Discharge Pressure, PSIG Discharge Temperature, °F Gas Compressor Speed, RPM Combustion Air Compressor Speed, RPM

Unit#l

Unit # 3

90 608 1010 176 11,500

93 606 1012 174 11,400

13,000

13,000

108 TROUBLESHOOTING NATURAL GAS PROCESSING

LOSS IN CENTRIFUGAL COMPRESSOR CAPACTTY

compressor rotor. However, it doesn't appear to be a paraffin deposit this time. What else could it be"? We.proceeded to disassemble the gas compressor. Inspection of the internals showed that:

NOT BLASTING

• The stationary components inside the compressor case were reasonably clean. • The first stage impeller on the rotor was clean. • The second stage impeller was slightly encrusted with a gray­ ish deposit. • The third stage impeller was 70% plugged with the same deposit. This deposit was rock hard, and could only be removed from the impellers by sand-blasting. It was somewhat soluble in water, but insoluble in gasoline. I tasted it to confirm my suspicion—It was salt.

DEW POINT SOLID DEPOSITION Almost all natural gas production contains entrained brine. Passing natural gas through a filter-coalescer prior to compression will reduce the brine content. However, to quantitatively exclude brine from entering a compressor, the gas must be scrubbed. This is done by dehydration in a triethylene glycol-to-gas trayed tower. However, in the facilities we are discussing, the glycol dehydrator was located downstream of the centrifugal compressors. One can usually assume gas exiting from a vapor-liquid separator, such as a filter-coalescer, is at it's saturation point in re­ gard to water. As the gas is compressed, it is also heated. The en­ trained droplets of brine thus dry out as they pass over the rotor's impellers. When the gas is heated by compression above it's dew point (i.e. dry point) temperature, the salt previously dissolved in the brine, turns into a solid which then adheres to the rotor. If this dry point is reached after the second stage of compression, then most of the salt deposits will be found on the third stage impeller. After we had cleaned the rotor and put Unit # 3 back on-line, the Chief Engineer inquired, "Why are we getting salt deposition on Unit # 3 , but not on Unit #1? "We probably are getting some salt in Unit # 1 " , I answered, "but the piping configuration is such that entrained particules will preferentially flow into Unit # 3 . Regardless of the cause of the salt deposition, I think I know a method that will permit us to live with the problem".

109

The crushed hulls from walnuts or pecans have a wide variety of use in cleaning process equipment. Most often they are used to remove scale deposits, on-stream, from the exterior surface of tubes inside a fired heater. The crushed nutshells may also be used with great effect in cleaning hard deposits from the internal parts of cen­ trifugal compressors in natural gas service. Figure 9-4 illustrates the mechanical details of facilities used for routine nutblasting of a centrifugal compressor. The procedures employed are: • Shut-down the compressor and isolate the discharge and suction. • Remove the 4 inch suction plug and screwed discharge cap shown in Figure 9—4. • Bring the compressor up to about 70% of normal operating speed. Vibration at this point indicates deposits have unevenly broken off the impeller. Nut blasting may eliminate the vib­ ration by removing residual deposits. • Slowly pour the crushed hulls into the opening on the suction line with a sugar scoop. • Observe the grey dust blown out of the discharge as a guide for the amount of nut hulls to use. Typically 10-100 pounds of hulls are required. The above procedure was, and still is, successfully used on the compressors described in this chapter. The Chief Engineer faithfully monitors the:

(LD AT

factor for each compressor. When the calculated value drops below DISCHARGE 4 PLUG

"

SUCTION — J 7 1

!

£ ^ 0 f

-*-

)

Figure 9 - 4 Connections for nut blasting.

ifi

BLIND 8 SCREWED CAP

110 TROUBLESHOOTING NATURAL GAS PROCESSING

LOSS IN CENTR1FCIGAL COMPRESSOR CAPAOTY

a certain point, the compressor is taken oif-line for nut blasting. Each compressor rotor has been nut blasted for salt deposit removal a dozen times in the past two years. After each treatment, the com­ pressor is restored to it's clean efficiency and capacity. No erosive effects on either the rotating or stationary parts of the compressor internals have been noted.

EFFECT OF ANTI-SURGE CONTROLS ON ROTOR FOULING "I can't argue that our piping configuration is not part of the problem", he said, "but don't you think there is more to the rapid loss in compression efficiency of Unit # 3 than that". There is another factor which we have not discussed. It has to do with the anti-surge spillback control, and the effect of this control on the third stage impeller operating temperature. Do you want to hear about this; it's rather complex a subject", I ventured. "If it's pertinent, III have to listen", allowed the Chief Engineer. "Do you know what the term surge means", I began, referring to Figure 9 - 1 . "It is a characteristic of a centrifugal compressor equivalent to an airplane stalling at slow speed. When a centrifugal compressor surges, it's rotor is stalling due to low gas flow. This con­ dition is brought on by low suction volume. Each time a compressor surges, it's rotor slides across it's radial bearings and impacts on it's thrust bearing. Eventually, the labyrinth seals and bearings will be damaged". "So Unit # 3 has sustained damage to the labyrinth seals due to surging; and this damage has resulted in reduced compression ef­ ficiency", concluded the Chief Engineer. "A perceptive, but incorrect observation", I noted, "actually, as I20°F

135°F

Figure 9—5 Anti-surge control may reheat gas being compressed.

111

you can see in this sketch, (Figure 9-5), your compressors are pro­ tected from surging by anti-surge spill-back controls. Recall that surge is initiated by the compressor suction volume falling below a certain rate. The anti-surge controls permit gas to recirculate from the discharge to the suction to increase suction volume. All evidence indicates that the anti-surge controls on Unit # 3 are, and have been functional. "Unfortunately, as you can envision from the temperatures shown in Figure 9-5, whenever the anti-surge valve opens, the in­ ternal compressor temperatures will rise. This increases the rates of fouling on the rotor impellers. As a rotor fouls, it's compression ef­ ficiency drops. This in turn cuts the compressor's capacity to move gas and forces the anti-surge valve to open in an attempt to move the machine away from it's surge point". "So, if you are running three centrifugal compressors in paral­ lel, here is what can happen: • Due to wellhead problems, the flow of natural gas from the field is diminished. • The suction pressure to the three machines falls and/or the suction volume is reduced. • The gas flow to the least efficient compresor is lowest. The anti-surge valve on this machine will open before the others. This increases the rate of impeller fouling on the wheels of the least efficient machine and hence makes it even less efficient". The Chief Engineer sighed, "Why do you have to make every­ thing complicated. Don't you have simple explanations for any­ thing".

GAS TCJRBINE DRIVEN CENTRIFUGAL COMPRESSORS

10 GAS TURBINE DRIVEN CENTRIFUGAL COMPRESSORS While the majority of natural gas field and transmission com­ pressors are reciprocating machines, a sizable minority are cen­ trifugal compressors driven by gas turbines. Only on rare occasions can electric, steam or deisel oil drives compete with natural gas as compressor fuel in pipeline service. A gas turbine works on the same principle as a jet engine. Air is compressed (typically to 110 PSIG), and discharged into a combus­ tion zone. Fuel gas is also injected into the combustion zone. The pressurized, burning gas expands as it passes across the blades of a turbine. The turbine serves two functions: • One or more wheels of the turbine drives the combustion air compressor (as shown in Figure 9-3 of the previous chapter). • One or more wheels of the turbine drives the gas compressor. The major part of the horsepower developed in a gas turbine is consumed by the combustion air compressor. The gas compressor absorbs about one third of the gas turbines power output. Work done by the combustion air compressors is recycled back to the turbine blades via the pressurized combustion air. An important feature of the gas turbine driven compressor shown in Figure 9—3 is that the two ends of the machine are not mechanically coupled. This is called a split shaft design; which means that the combustion air compressor and the gas compressor operate at different speeds. This permits the air compressor end to run at a speed consistant with developing full horsepower, while the 112

113

gas compressor end may be running at a lower speed due to factors such as high discharge pressure.

GAS TURBINE DRIVES VS. RECIPROCATING COMPRESSORS It is instructive for the Troubleshooter to understand why a centrifugal gas turbine driven compressor, rather than a reciprocat­ ing engine driven compressor was selected for service at bis particu­ lar booster station. One reason is mechanical simplicity. My operat­ ing experience indicates that the reliability and ease of maintenance for centrifugal machines is preferable to that of reciprocating com­ pressors. While the compressor end of a reciprocating machine is re­ latively simple, a reciprocating engine contains a wide array of mov­ ing parts subject to fouling and wear. A gas turbine centrifugal compressor requires, in theory, about 15% more fuel per brake horsepower than a gas driven reciprocating compressor. As fuel is the largest cost incurred by natural gas trans­ mission operators, this is a matter of considerable importance. In practice though, the energy efficiency advantage of reciprocating over centrifugal compressors is often reduced. A 4,000 horsepower reciprocating engine can have sixteen power cylinders. Each re­ quires careful adjustment to achieve a proper fuel/air ratio. The pis­ ton rings of each cylinder are subject to variable rates of wear, or firing timing may be off. These problems, plus a host of other po­ tential difficulties inherent in internal combustion engines can re­ duce a reciprocating engine's fuel efficiency by 10%—20%. On the other hand, if the rotating assembly of a gas turbine driven com­ pressor is kept clean, it will likely run at its design fuel efficiency. In practice then, the actual gas usage per brake horsepower for many facilities is about the same for both centrifugal and reciprocat­ ing machines. Hence, at least for manned stations using natural gas as a compressor fuel, centrifugal rather than reciprocating compres­ sors are often employed.

TROUBLESHOOTING GAS TURBINE DRIVERS A centrifugal compressor driven by a gas turbine at a pipeline booster station is moving 80 MMSCFD of natural gas. It used to move 95 MMSCFD. What's wrong? As the troubleshooter, consider whether the problem is with the driver or the compressor. Actually, there are three primary components involved: • The natural gas compressor.

114 TROUBLESHOOTING NATURAL GAS PROCESSING

GAS TURBINE DRIVEN CENTRIFUGAL COMPRESSORS

• The combustion air compressor. • The turbine blades. First, plot the current operating condition for the gas compres­ sor on the curves supplied by the manufacturer. A typical family of compressor curves is shown in Figure 10—1. Point "A" shown in this figure falls on the curve for 12,500 rpm. If you had measured a gas compressor speed of about 12,600 rpm, you would conclude t h a t the gas compressor was all right. On the other hand, if you had observed a speed of 13,400 rpm, you could be reasonably positive that some­ thing was amiss with the gas compressor. The preceeding state­ ments assume t h a t the actual gas specific gravity, suction temper­ ature, compressibility, as well as the diameter of the impellers (wheels), match the parameters stated in Figure 10—1. The effects of deviations from these assumptions will be quantified later. Having proved t h a t the gas compressor end of the machine is performing properly, next decide if the driver is delivering as much horsepower to the gas compressor as can be expected at current amM.W. -18 1200 SUCTION TF_MP = 90°F

115

bient conditions. Assume the rated horsepower of the gas turbine is based on an ambient temperature of 90*F. As a rule of thumb, for each increase of 10°F in ambient conditions, the horsepower of a gas turbine drops by 5% (only assuming that neither the gas or combus­ tion air compressors are operating at maximum speed). Thus, a 110°F air temperature cuts the engine horsepower 10% below de­ sign. After accounting for the effects of ambient temperature (barometric pressure, while also important, does not change very much) compare the gas compressor horsepower indicated on the manufacturer's curves against the rated gas compressor horsepower, after derating for ambient temperature. Let's say that the turbine is rated for 3,000 horsepower. After derating by 10% for 110°F air the turbine should be providing 2,700 horsepower to the gas compressor. Unfortunately, based on the cur­ rent suction pressure, discharge pressure and flow you only calculate 2,500 horsepower. We have already decided that the gas compressor section of the machine is okay. What factors account, then, for the reduction in driver horsepower from 2,700 to 2,500? EXHAUST TEMPERATURE LIMIT

SUCTION PRES.= 500 PSIA

Gas turbines are limited, as are all rotating assemblies, by either speed or power. For an electric motor, the power limit is man­ ifested by maximum amperage, (more precisely, the maximum per­ missible winding temperature). The situation with gas turbines is similar. The ultimate amount of power (i.e. work, horsepower), t h a t can be developed by the turbine blades, is limited by the turbine exhaust temperature. A typical maximum turbine exhaust temperature is 1,100°F. This limit is imposed by the metallurgy of the turbine's blades. Con­ tinuous operation above the turbines design exhaust temperature will lead to accelerated deterioration of the blades and a consequent reduction in engine horsepower. When neither end of the centrifugal compressor is running at its peak speed, and the turbine exhaust temperature is below it's de­ sign limit, there are two other possibilities which may be limiting horsepower output:

100tO

o_

to

1000-

bj

a. UJ ID

< X o

900-

to

1000

1200

1600

1400

FLOW, ACFM XIO"

3

Figure 10—1 Actual speed vs. the predicted speed based on compression ratio andflowis a measure of centrifugal compressor efficiency.

• Fuel gas firing is limited by a faulty over-ride on the temper­ ature controller. That is, the exhaust temperature is artifically surpressed by an instrument malfunction. • The fuel gas flow control valve is wide open; or it is partially plugged by natural gas hydrates.

116 TROUBLESHOOTING NATURAL GAS PROCESSING

When the turbine exhaust temperature is at it's limit, and horsepower output is deficient, other possible causes are: • Excessive wear to turbine blades. • Air/fuel ratio problems. • Carbon deposits on turbine blades. Periodic detergent washing of the combustion air compressor will help reduce this effect. • Lack of proper flow from the combustion compressor.

AIR COMPRESSOR PROBLEMS One way of looking at a gas turbine centrifugal compressor is that the combustion air compressor must pump sufficient air to sup­ port combustion across the turbine blades as needed to spin the gas compressor at its required speed. Any factors which reduce the flow delivered by the combustion air compressor will reduce horsepower available to the gas compressor. The factors which reduce air flow are identical to those parameters which reduce the capacity of any centrifugal compressor: • High suction temperatures due to elevated ambient temperature. • Mechanical damage. • Low suction pressure due to plugging of the air filter suction screen. A pressure drop of 4 inches of water will reduce the air compressor capacity by roughly 2% • Dirt accumulation in the rotors internals due to inadequate suction filtration and dusty air. • Slow speed due to the problems listed above with the gas turbine driver. To remove dirt and dust accumulations from the air compressor rotor, detergent water washing is required. An aqueous detergent solution is squirted into doors provided on the air intake ducting. The machine is running at a reduced speed during this period, and the natural gas process piping is isolated from the compressor. In addition to washing the air compressor rotor, some of the detergent solution may carry-over to the turbine blades and promote some cleaning. During detergent washing, the turbine is powered in the normal fashion—i.e. by firing natural gas. Frequent cleaning or replacement of the air intake filters will also improve air flow availability for combustion. To simplify this procedure, a so called "Huff & Puff', self-cleaning air filter may be retrofitted into existing equipment. Such a self-cleaning filter should

GAS TURBINE DRIVEN CENTRIFUGAL COMPRESSORS

117

operate for two years without manual maintenance. Also, it repor­ tedly reduces air filter pressure drop by an average of five inches of water over this two year period for an effective increase in engine horsepower availability of 2-3%. The combustion air compressor should develop a certain dis­ charge pressure (110 PSIG is typical) as specified by the manufac­ turer's data. After correcting for suction pressure, suction tempera­ ture and speed, (see manufacturer's correlations), if the indicated air discharge pressure cannot be achieved, the combustion air compres­ sor should be washed. If washing fails to correct the shortcoming, the rotor should be checked for mechanical damage. Keep in mind that not only will problems connected with the turbine blades slow down the combustion air compressor, but that deficiencies with the combustion air compressor will indirectly be re­ flected in lower combustion air compressor speed.

GAS COMPRESSOR PROBLEMS Referring back to Figure 10—1, remember that we have com­ pared the actual gas compressor speed to the speed indicated by the curve that passes through point "A". We calculated point "A" from the natural gas flow, and the observed suction and discharge pres­ sure. We said that if the measured gas compressor speed exceeded the speed indicated by point "A" on Figure 10-1, then the gas com­ pressor was deficient. This is not quite true. The following factors all raise the actual speed as compared to the speed calculated from Figure 10-1: • • • •

Increased suction temperature. Increased gas compressibility Lower gas specific gravity Reduced impeller diameter

It is a relatively simple matter to reduce the diameter of the gas compressor impellers; they can be turned down on a lathe. For instance, on one centrifugal compressor, the impellers were trimmed down from a 12" to an 11" diameter. Other factors being equal, the speed of the gas compressor end of machine increased from 11,000 rpm to 12,000 rpm, while the speed of the combustion air compressor held constant at 13,200 rpm.

GAS PROPERTIES EFFECT COMPRESSOR SPEED As the molecular weight of natural gas drops, it's compressa-

118 TROUBLESHOOTING NATURAL GAS PROCESSING

biiity factor (Z), increases. This will increase the required rotor speed as compared to the manufacturer's operating curves. While the variabil­ ity of compressability with molecular weight is small, the correlation between gas specific gravity and molecular weight is linear. More to the point, specific gravity has a large effect on the speed required to move a given volume of gas at a fixed pressure ratio. The specific gravity of natural gas is calculated as follows: S.G. = M.W. 29 where M.W.

=

Molecular weight of the liquid free natural gas, pounds per mole.

An approximate rule of thumb is that each decrease of one pound in molecular weight will require the gas compressor to spin 2% faster to maintain the same natural gas flow and pressure ratio. High suction temperature also reduces the density of natural gas. For each increase of 22°F, the density of gas is reduced about 4%. This is equivalent, as far as the compressor is concerned, to a reduction in molecular weight of about 0.75 pounds per mole.

TEST YOCIR COMPREHENSION Troubleshooting split shaft, gas turbine driven, natural gas compressors is certainly a complex subject. You may wish to re-read this material if you cannot answer the following questions: 1. The machine is running at it's maximum turbine exhaust temperature. The molecular weight of the natural gas drops. The compressor discharge pressure is fixed. Will the suction pressure increase or decrease (1)? Will the gas flow increase or decrease (2)? Will the gas compressor speed increase or de­ crease (3)? Answers: (1) increase, (2) decrease, (3) increase. 2. The machine is running at it's maximum turbine exhaust temperature. The ambient temperature increases. Will the combustion air compressor speed increase or decrease(l)? Will the gas compressor speed increase or decrease (2)? Will the natural gas flow increase or decrease (3)? Will the amount of fuel gas burned in the turbine increase or decrease (4)? Answers: (1) decrease (2) decrease (3) decrease (4) decrease. In addition to all the other complexities, centrifugal gas com-

GAS TURBINE DRIVEN CENTRIFUGAL COMPRESSORS

119

pressors in natural gas service are also subject to fouling of the rotor's impellers. The tip-off that reduced gas flow and/or compres­ sion ratio could be due to rotor fouling is an unexpected increase in the compressed gas exhaust temperature. The incident described in the preceding chapter amplifies the all too common effect of fouling on a centrifugal compressor's capacity.

LIGHT HYDROCARBON DISTILLATION

11 LIGHT HYDROCARBON DISTILLATION Whether one is troubleshooting a distillation tower in a natural gas liquids recovery facility, or in a petroleum refinery, the compo­ nents of the problem causing inadequate fractionation are the same: • • • •

Damaged tower internals Low reflux rates Erratic control Flooding

ciency does not noticeably increase, or even decreases as reflux is raised, flooding is indicated.

FLOODING There are two commonly accepted terms describing flooding in a trayed distillation tower: • Liquid flood • J e t flood Figure 11—1 shows the effect on tower pressure drop as the re­ flux rate and reboiler duty are increased. The liquid flood point is characterized by a sudden increase in measured delta P. At this point, the capacity of the downcomers to drain liquid pouring over the outlet weir is insufficient. The height of liquid in the downcom­ ers shown in Figure 11-2 increases until the top of the weir is reached; at this point liquid begins to stack-up on the tray deck and drainage from the downcomer on the tray above is reduced. Thus, all trays above a tray that is flooding, will also begin to flood. Fully developed downcomer flood will always greatly reduce fractionation efficiency.

CONTROL PROBLEMS There is a very straight-forward method to determine if a con­ trol problem is leading to the production of off-spec products. This method is based on the following premise: "If you can't run it on manual, you'll never run it on auto". Certainly, for the relatively simple operations of concern here— (i.e., deethanizers, debutanizers, propane-butane splitters and deisopentanizers)—LPG and gasoline fractionation specifications are achievable with manual control. If you cannot succesfully operate a distillation column on hand control for a few hours, then check to see if the control valves in the field are properly responding to the control center valve position signal. Next, increase the reflux rate and the tower bottoms heat input (reboiler duty). An unexpectly large improvement in the separation between the light and heavy key components indicates poor vaporliquid contacting due to dumping liquid through tray decks or vapor channeling in packed beds. On the other hand, if separation effi120

121

5% -

4% S gal of solution grains of H?S gal of solution cu ft of CO, gal of solution cuftofCO? gal of solution Percent H 2 S (by weight)

X

X

X

X

X

0.00323 wt%MEA 0.00557 wt%MEA 1.91 wt%MEA 3.28 wt%DEA 1.8 wt%MEA 3.1

= molesofH2S/moleofMEA = moles of H2S/mole of DEA

RICH AMINE FROM SCRUBBERS

X

= molesofCCymoleofDEA = molesofH2S/moleofMEA

VAPOR VENT TO SOUR FUEL GAS SYSTEM

RETROFITTING A RICH AMINE SURGE DRUM

MANUAL DRAIN

REGENERATOR FEED

Figure 12—4

Hydrocarbon skimming. The single biggest problem in operating a Clans sulfiir recovery plant is hydrocarbons in acid gas feed. When the rich amine charged to the regenerator contains light liquid hydrocarbons, coking of the sulfur plant catalyst is almost certain. The hydro­ carbons will distil overhead in the regenerator and com­ bine with the acid gas product.

= moles of CCVmole of MEA

= molesofH2S/moleofDEA wt%DEA Percent C0 2 (by weight) x 0.72 = cu ft of C02/gal of solution Percent H2S (by weight) x 558 = grains of H2S/gal of solution

Percent H 2 S (by weight)

147

TO REFINERY SLOP SYSTEM

A properly designed rich amine surge drum can protect a sulfur plant from plugging with coke deposits.

If naphtha is accumulating in the regenerator reflux drum, exces­ sive concentrations of propane and butane will occur in sulfur plant feed. A commercially proven method to eliminate this problem is de­ tailed in Figure 12—4. The rich amine surge drum is retrofitted with baffles. Figure 12-4 is roughly drawn to scale. This baffle arrangement will automatically skim off the hydrocarbons. The first compartment separates amine from hydrocarbons. A residence time of ten minutes is about right.

SULFUR PLANT OPERATION

13 SULFCIR PLANT OPERATION

149

from these measurements: 1. Add the parts per million of H 2 S plus S 0 2 2. Add 2,000 ppm to the preceding (this allows for COS, CS 2 , sulfur vapors, and entrained sulfur droplets). 3. Divide the total parts per million of sulfur as obtained above by 300,000. 4. Express this result as percent. 5. Subtract this percent from 100 percent. Poor conversion is 95 percent for a three-stage unit, 90 percent for a two-stage unit, and 80 percent for a single stage plant.

WRONG AIR RATIO Natural gas, while valuable, has an unsatisfying etheral and intangible quality. When properly treated, it is largely invisible, weightless (compared to air) and odorless. Sulfur, one of the princi­ ple by-products of natural gas production, is of a much more sub­ stantial nature. Sulfur, is recovered in its elemental form from the hydrogen sulfide produced in natural gas—especially gas flowing from deeper formations. The yellow product is kept in it's liquid form by maintaining it at about 300°F. At this temperature, sulfur is about 80% denser than water and it has a low viscosity. Sulfur, or claus plant feed consists of H 2 S, C 0 2 , moisture and traces of miscellaneous light hydrocarbons, which have been dis­ solved or entrained in the rich amine used to scrub the sour natural gas. The presence of carbon containing compounds, especially hydro­ carbons, promotes the formation of carbon disulfide (CS2) and carbonyl sulfide (COS), in the initial reaction stage. These compounds, to an appreciable extent, carry through downstream reaction stages and reduce the percent of sulfur recovered from the feed gas (i.e. the conversion) as liquid sulfur. Both C 0 2 and hydrocarbons also reduce sulfur plant capacity.

Using too much air is the easiest way to lose conversion. For best conversion, the ratio of H 2 S/S0 2 is 2:1. This ratio is measured in the tail gas from the final condenser. Sulfur plants are best run on closed-loop tail gas analyzer control. In practice, other methods are often needed to adjust air to the reaction furnace. If air flow to the reaction furnace is much too high, S 0 3 will be formed in the incinerator and a white plume will result. A yel­ lowish plume indicates insufficient air to the front end of the sulfur plant. Incinerator temperature can also be used to indicate air re­ quired in the reaction furnace. A high incinerator temperature, coupled with low incinerator fuel use, is a sure sign of insufficient air to the reaction furnace. Alternately, if large amounts of fuel are required to. maintain incinerator temperature, air to the reaction furnace is in excess. If the tail gas analysis showed SOg equal to H 2 S, one could cut sulfur losses by 5 percent just by reducing air. A complete treatment on the effect of air ratios on conversion has been reported by Kerr. 1

PLENTY OF CATALYST MEASURING SULFUR LOSSES To measure sulfur losses, check for H 2 S and S 0 2 in the final condenser effluent. Drager tubes are a simple and reasonably accu­ rate way to get this data. Don't submit sulfur plant tail gas samples to the lab for analysis. The H 2 S and S 0 2 will react in the sample container to form solid sulfur and water. To calculate conversion 148

Sulfur plants usually have excess catalyst. Typically, the catalyst bed will be 3 feet deep. For catalyst in good condition, equilibrium conversion is reached in the top 6 inches. This is shown in Figure 13-2. The operating engineer, when troubleshooting a conversion problem, can depend on the following: overall conversion does not decrease noticeably with higher throughput. Plant tests on one unit, conducted over a range of 30 to 120 percent rate showed little dif-

150 TROUBLESHOOTING NATURAL GAS PROCESSING

ference in conversion. Therefore, you start your troubleshooting program by assuming that cutting throughput will not help.

REACTOR PROBLEMS It's hard to do much harm to sulfur plant catalyst without first causing excessive pressure drop. If you suspect reduced recovery be­ cause of lost catalyst activity, check the temperature rise across each reactor. For example, for a three-stage Claus unit:

Reactor 1st 2nd 3rd

AT f nutlet-inlet) 125°F 40°F 5°F

StlLFOR PLANT OPERATION

151

pounds can significantly contribute to S 0 2 in the incinerator. One can essentially destroy both COS and CS2 by operating the first reactor at a n outlet temperature of 650°F. At this temperature the compounds are hydrolized to H 2 S and C 0 2 . An increase in S 0 2 emissions, accompanied by a lower t h a n normal first reactor inlet temperature, is likely due to COS and CS 2 .

LEAKING REHEAT EXCHANGER Some multistage sulfur plants reheat third-stage reactor feed with first-stage reactor effluent. If your plant has one of these heat exchangers, check it for leaks, which contribute to lost conversion. A large increase in the third-stage inlet temperature indicates this type of reheat exchanger is leaking.

SCILFUR FOG This is a good profile. If one day you find the heat of reaction has shifted downstream, you may see the following: AT Reactor

Sulfur plants have the peculiarity of converting less hydrogen sulfide to sulfur as the unit charge drops. One of the reasons for this is sulfur fog is formed.

fniitlpt-iTilft^

1st 2nd 3rd

90°F 55°F 20°F

This temperature shift means the effluent from the first stage is not reaching equilibrium. Sulfur formation in the first reactor has decreased 30 percent. In this overall catalyst effectiveness has de­ clined. The problem may be due to catalyst deactivation caused by sul­ fur precipation. This is a result of low reactor feed temperatures. Check the operation of the reheat exchanger upstream of the reactor with the reduced temperature rise. Raise the reactor inlet temper­ ature 30°F. After a few days, this will dissipate the offending sulfur deposits. If catalyst activity has been irreversibly lost, you may want to change the catalyst. A following section describes a procedure to help make this decision. Reduction of catalyst activity with time on stream, baring unusual incidents, is unlikely.

/ \ LOW PRESSURE STEAM

LOW PRESSURE STEAM

(2S)£

RST REACTOR

fNCINER4T0R FUEL GAS

TAIL GAS

C O S AND C S 2 The presence of hydrocarbons and C 0 2 in the acid gas promotes the formation of COS and CS 2 in the reaction furnace. These com-

HIGH PRESSURE STEAM

Figure 13—1

A single stage Claus plant

152 TROUBLESHOOTING NATURAL GAS PROCESSING

SULFCIR PLANT OPERATION

This fog does not drop out of the end of the condensers. Even­ tually, much of it appears as SOg in the incinerator. Damage to the final condenser demister may also allow entrained sulfur to escape to the incinerator. This demister can be extensively damaged from sulfur fires during start-up. COLD REHEAT GAS Hot gas from the high-pressure boiler (Figure 13-1) is often used to supplement the reheat exchangers. This hot gas contains sulfur vapors. About 65 percent of the H 2 S in acid gas is converted to sulfur vapors in the reaction furnace. Therefore, this hot reheat gas increases the partial pressure of sulfur in the reactor. When reheat gas is used, equilibrium in the reactor is ad­ versely affected. At reduced plant charge, the gas outlet temperature from the high-pressure boiler drops. This means more reheat gas is needed to compensate for its lower temperature. This is another reason why you may see low conversions at reduced through-puts. In practice, a change in reheat gas temperature has a notice­ able effect on conversion only when hot reheat gas is used in the last reaction stage. WHEN TO CHANGE CATALYST A favorite question put to an operating engineer by the sulfur plant supervisor is, "Do we need to change catalyst during the unit

turnaraound?" With a little luck, he may remember to ask you be­ fore the plant is shut down. If pressure drop is normal through the catalyst beds, this will be a tough question. With adequate instrumentation, you can obtain a vertical temperature profile through the first catalyst bed and then develop data to make a firm decision. Figure 13-2 illustrates the method. For catalyst that is in good condition, 90 -f- percent of the heat of reaction is released in the top 6 in. If catalyst activity is impaired, the reaction is shifted down the bed. Damage to catalyst and reduced conversion can be a conse­ quence of many other factors besides lost activity: carbon deposits, leaking condenser tubes, damaged support screens, sulfuric acid for­ mation, operation at the sulfur dew point. These problems are, how­ ever, invariably associated with increasing pressure drop. The most common cause of lost catalyst activity is reversible—that is, sulfur deposits due to low bed temperatures. PRESSURE DROP It is of utmost importance to watch for high sulfur plant pres­ sure drop. Sulfur plants don't suddenly plug without a prior pressure drop increase. Troubleshooting a sulfur plant requires foresight. The operating engineer will want to have the data plotted, as in Figure 13-3, for his unit. This figure illustrates the use of the capacity ratio parameter, calculated as follows:

,. 650 °F RE AC'TOR TEMPEFIATURE (F

=XC

^PD

=X

D

X c / X D = CAPACITY RATIO

550 °F 500 °F

where

8A0 CATALYST

AP C

450 °F

0.5

1.0

1.5

2.0

2.5

DISTANCE FROM TOP OF BED (FEET)

Figure 13—2

4Pc (F c ) 2 (F D ) 2

GOOD CATALYST

600 °F

153

Vertical temperature profile shows condition of catalyst

3.0

Fc AP D FD

Current pressure at the reaction furnace inlet, psig Current air flow to reaction furnace, scf/hr Design pressure at the reaction furnace inlet, psig Design air flow to reaction furnace, scf/hr

Pressure drop in a sulfur plant is proportional to the square of the throughput. When you find your plant not adhering to this rule, there is something gone awry with your unit.

154 TROUBLESHOOTING NATURAL GAS PROCESSING

CARBON DEPOSITS The data plotted in Figure 13—3 were, in truth, not assembled until after the catastrophic pressure rise. The plant operators had not noticed the increase in reaction furnace pressure. Only when they tried to increase acid gas charge and ran short of air blower capacity, did they realize something was amiss. An abnormality had been reported on the 30th day. A quantity of light hydrocarbon was skimmed off the amine regenerator reflux drum. When a sample of this hydrocarbon was drawn, it bubbled in the sample container. Light hydrocarbons had accidentally entered the amine re­ generator, along with the rich amine. The hydrocarbon was stripped overhead. Some was condensed in the reflux drum; the rest re­ mained as a vapor and was charged, along with H 2 S, to the sulfur plant. Ten times more air is needed to oxidize a mole of propane than a mole of H 2 S. When the light hydrocarbon vapors reaced the sulfur plant, carbon black was made in the reaction furnace: C 3 H 8 + 20 2 » 3C(S) + 4 H 2 0 The carbon black was deposited on the top of the first catalyst bed. Gas flow was restricted, and high prssure drop resulted. Pro­ viding sufficient combustion air to the reaction furnace could have prevented this incident. The operating engineer can determine if increasing pressure drop is due to carbon accumulation on catalyst by making the fol­ lowing observations: • Is the S 0 2 concentration in the sulfur plant tail gas very low (less than 1,000 ppm)? Low S 0 2 is a sign of insufficient air to the reaction furnace. • Are light hydrocarbons accumulating in the amine regenerator reflux drum? Having determined that the catalyst bed is plugged with car­ bon, the engineer will want to correct the situation. Over a period of time, the carbon will react with SO2. Unfortunately, this reaction proceeds slowly at low temperatures. Maximizing reactor inlet tem­ perature and S 0 2 levels will help. Significant (10 percent) reductions in pressure drop can take weeks. Shutting down and changing out t h e catalyst may be more practical. The best solution to his incident would have been to keep car-

156 TROUBLESHOOTING NATURAL GAS PROCESSING

bon black from forming in the first place. This could have been done by alert operators raising air to the reaction furnace. One might even have hoped that the tail gas H 2 S to S 0 2 ratio -analyzer, would have automatically increased air flow. In the real world, there is only one reliable way to prevent such situations? Liquid hydrocarbons must be separated from the rich amine upstream of the amine regenerator.

SOUFOR PLANT OPERATION

157

2. Keep all boiler tubes submerged in water. Watch the steam drum liquid level closely. For forced circulation boilers, circu­ late 10-15 pounds of water for each pound of steam generated. Your boiler treating chemical supply vendor is a good source of information on preventing boiler tube corrosion. CONDENSER LEAKS

LEAKS CAUSE PRESSURE D R O P A tube leak in the high-pressure steam boiler can lead to diaster. The high-pressure water will erode the metal, and the flow of water into the hot gas stream will rapidly increase. Water quenches the sulfur bearing gases. If the direct reheat line is open, sulfur pre­ cipitates on the catalyst. This stops gas flow through the plant. The worst thing that can happen to a sulfur plant is a crash shutdown. Sulfur plants should be cleared of sulfur by burning nat­ ural gas instead of H 2 S before a shutdown. Continue natural gas fir­ ing until the amount of liquid sulfur overflowing from the seal legs is reduced to a trickle. When the plant suddenly shuts down, pre­ cipitating sulfur solidifies in the catalyst beds. Then flow through the unit cannot be re-established. An alert operating engineer must identify boiler tube leaks be­ fore it is too late. The capacity ratio plot (Figure 13-3) is the key. A gradual increase in pressure drop is an early warning sign. When this happens, check for low steam production rates from the highpressure boiler. Another tip-off is a low gas outlet temperature from this boiler. If both steam production and outlet temperature are low and pressure drop is high, shut down the plant. There is a tube leak. On one unit, high pressure drop was observed. The operators suspected a plugged condenser sulfur seal leg. They opened a drain on the condenser with the intent of drawing off excess sulfur. Steam, not sulfur, discharged from the drain. Six days later, the plant shut down with a giant leak in the high-pressure boiler tube sheet. Water (steam) leaks also reduce conversion of H 2 S to sulfur. The Claus reaction shows that equilibrium is shifted to the left as the water partial pressure increases. PREVENTING BOILER LEAKS There are two simple rules to minimize boiler leaks: 1. Keep total dissolved solids (TDS) in the boiler blowdown below 2,500 ppm;

Tube leaks may also occur in the low-pressure steam conden­ sers. The leaking condenser-is identified through a pressure drop survey. Measure the pressure drop across each condenser. The first condenser in the train exhibiting a disproportionately high pressure drop is the leaker. If the leaking tubes are found in the bottom of the condenser, formation of sulfuric acid may be the cause (see fol­ lowing section on start-up tips). Often a sulfur plant t h a t has been idled for several months will come back on line with condenser tube leaks, due to attack by H 2 S 0 4 formed while the unit was off-line. ROUTINE PRESSURE SURVEYS The preceeding experiences illustrate the need for routine pres­ sure surveys on sulfur plants. A single 0-15 psig gauge is used. Sul­ fur will plug pressure taps very quickly. They can be drilled out or melted with a propane torch. Do not open bleeders with a welding rod. Take a complete pressure survey just after the unit comes onstream after a turnaround. This will give you a base point from which to judge future problems. When comparing pressure drops at different throughputs, normalize the data by: AP is proportional to (air flow)2 PLUGGED SEAL LEGS Liquid sulfur is drained from the condensers through seal legs submerged in sulfur to prevent gas in the condenser from blowing through. Required seal depth is: Seal depth (ft) =

condenser pressure (psig) X 2.31 SG of sulfur at condenser temperature

The specific gravity of sulfur between 250°F to 350°F is normally about 1.79 When a seal leg plugs, liquid sulfur backs up in the condenser.

158 TROUBLESHOOTING NATURAL GAS PROCESSING

This restricts gas flow and results in high pressure drop. Again, the best indication of this problem is a routine pressure survey. Having determined that a condenser has excessive pressure drop: • Locate the condenser tube-side drain connection. • With suitable breathing protection from H 2 S (i.e., Scott Air Pac), unplug and open the drain. • If a steady flow of liquid sulfur is observed, the seal leg is plugged. Do not try to keep the condenser drained down in this manner. Sooner or later, H 2 S-rich gas will blow through and create a poten­ tially fatal hazard. Plugged seal legs must be unplugged. Packing glands, used with valves that bolt onto the seal leg flanges, can be used to drill out seal legs on stream. Plugged seal legs are often a problem just after start-up. Minerals in the refractory are leached out by the moisture and acid produced during heat-up. These minerals, as well as corrosion products, ac­ cumulate on the liquid sulfur surface in the seal legs. A steady in­ crease in pressure drop, shortly after start-up, is often caused when these deposits solidify in the seal legs. Loss of steam to the jacketed piping can also plug a seal.

CATALYST SUPPORT SCREENS Sulfur plant catalyst is supported by thin flexible screens. These screens are lapped and folded over to keep catalyst from leak­ ing through the support grating. Improper installation of screens oc­ curs frequently when catalyst is changed. The catalyst may wash down into a seal leg and plug it. When you find normal-sized catalyst balls in the condenser drains, you can count on a shutdown to repair the support screens. Don't forget to seal the screens to the walls of the reactor. One one unit, small but intact catalyst balls were found in the seal legs. This indicates poor quality control in the manufacture of the catalyst. START-(JP TIPS Most damage to sulfur plants occurs during start-up. You can reduce troubleshooting activity later by closely monitoring the fuel gas firing phase during heat-up. Keep 0 2 levels in flue gas at about 1 percent. Excess 0 2 will form sulfuric acid when mixed with sulfur and moisture in catalyst beds. The H 2 S 0 4 disintegrates the catalyst. Low conversion and in-

SOLFCIR PLANT OPERATION

159

creased pressure drop result. The acid may also attack the catalyst support screens. This leads to plugged seal legs. Even worse, the lower tubes in the condensers will get a diluted sulfuric acid bath, and con­ sequently corrode. AVOID DEFICIENT OXYGEN Burning a hydrocarbon with insufficient air produces sooty smoke. The soot deposits on the first catalyst bed. To do a thorough job of plugging a bed with this technique takes about 8 hours. A foolproof way to make sure you are not badly oxygen defi­ cient is to connect a piece of tubing to the back end of the high-pres­ sure boiler. Then attach the other end of the tubing to a bottle filled with clean, damp cotton. Observe the cotton. If it starts turning black after a few minutes, you are running oxygen deficient. Person­ nel who have been unable to master other analytical techniques find this method useful. START-UP ATMOSPHERIC VENT Putting a cold sulfur plant on line, when done properly, can take almost two days. During the initial portion of the start-up, fir­ ing must be carefully controlled to avoid damaging the refractory in the decomposition furnace (i.e. the thermal reactor) due to a too rapid heat-up. Therefore, only a small volume of flue gas exits from the decomposition furnace and the high pressure steam generator, during the first 12 hours of the start-up. This amount of flue gas is really not sufficient to appreciably warm the large weight of catalyst in the fixed bed reactors. Hence, the water in the flue gas, produced by the combustion of hydrogen in the decomposition furnace, may condense on the catalyst beds. In the presence of sulfur (which is al­ ways present in the reactor beds after the unit is commissioned), and oxygen, sulfuric acid is formed. This acid leaches out minerals from the reactors' refractory walls, corrodes the condenser tubes, forms a pressure drop producing crust on the top of the catalyst beds, and may result in seal leg pluggage. By exluding excess oxygen from the combustion gases, the for­ mation of sulfuric acid can be minimized. Of course, one then en­ counters the danger of converting the front end of the Claus train into a Carbon Black Plant, and plugging up the catalyst bed in the first fixed bed reactor with coke. All of these invidious possibilities may be easily avoided by in­ stalling a removable start-up stack. For one unit, a 12" diameter, 20'

160 TROUBLESHOOTING NATURAL GAS PROCESSING

length of pipe was bolted onto the manway entrance to the backend of the fired tube boiler. The large butterfly valve at the outlet of the Claus train was closed and the decomposition furnace was heated in a normal manner but without taking care to minimize excess oxy­ gen, as the entire flue gas stream exited from the new temporary stack. Once the decomposition furnace had been heated to 1400°F, the tem­ porary stack was removed and normal Claus plant warm-up proce­ dures were followed. However, by now, the rate of natural gas firing did not have to be controlled carefully to avoid over-rapid heat-up of the bricks in the decomposition furnace. Thus, a large volume of flue gas could be generated which rapidly heated the catalyst beds past the water dew point temperature. Also, excess oxygen of several percent was tolerable, until sulfur fires were ignited in the catalyst beds. However, this condition was readily apparent from the reac­ tors' temperature profile and corrected by pinching back on the com­ bustion air to the decomposition furnace.

MAXIMIZING PLANT CAPACITY Innovative changes in the design and operation of some exist­ ing sulfur recovery plants can produce large increases in capacity. The capacity of the majority of sulfur plants is limited by front-end pressure (the acid gas pressure at the reaction furnace). While in theory conversion of hydrogen sulfide to sulfur liquid is slightly re­ duced at higher gas throughputs due to reactor and condenser limits, in practice such effects are quite small. For example, the temperature profile of one lead fixed-bed reactor on a Claus plant (Figure 13-2) shows almost all the reaction taking place in the top 30% of the bed.

SULFUR PLANT OPERATION

• N 2 from combustion air • H 2 0 (vapor)—contained in the acid gas from the amine regen­ erator reflux drum • Miscellaneous hydrocarbons and mercaptains OXYGEN ENRICHMENT The use of oxygen to enrich process air for combustion purposes is a common practice. For instance, oxygen has been added to the air blower discharge of fluid catalytic cracking units in many re­ fineries. 2 Enrichment concentrations of 30% to 40% oxygen are typ­ ical. Oxygen enrichment of the air supply to one 50 ton/day Claus plants was initiated to reduce the amount of nitrogen flowing through the reaction train. The overall Claus reaction for a typical acid gas stream having the composition shown in Table 13—1 will yeild an effluent with the following composition (in mole%). N 2 , 60; H 2 0 , 30; C 0 2 5; H 2 and other, 5. Because the capacity of a Claus plant is essentially propor­ tional to the volume of the effluent gas, substituting oxygen for air will result in a large capacity increase. For the 30 ton/day Claus plant discussed in this chapter, an oxygen enrichment of up to 31% was demonstrated. Naturally, the use of enriched air resulted in an increase in reaction furnace temperature. Both the calculated increased capacity and the theoretical temperature rise in the reaction furnace have previously been published. 3 The observed changes in capacity and temperature for the 50 ton/day Claus plants are summarized in TABLE 13-1

The parameters which limit maximum front-end pressure are: • • • •

Seal leg depth Air blower maximum head Reaction furnace design pressure Acid gas supply pressure.

Front-end pressure will vary with the square of the moles of air plus acid gas that enters the reaction furnace. The principle constituents of these streams are: • H 2 S from natural gas • C 0 2 absorbed from natural gas • 0 2 from combustion air

161

TYPICAL ACID GAS COMPOSITION MOLE % C02 Hydrocarbons' H20 H2S Other TOTAL

*Average molecular weight of hydrocarbon is typically equal to propane.

12 1 8 78 1 100

SCILFCIR PLANT OPERATION

162 TROUBLESHOOTING NATURAL GAS PROCESSING

Table 13—2. Further information on oxygen enrichment in Claus plant operations can be found in other publications. 4 ' 6 ' 7 TABLE 13-2 OBSERVED EFFECT OF OXYGEN ENRICHMENT ON A 50 T/D CLAUS UNIT Oxygen Concentration *Thermal Reactor Temperature *Front End Pressure *Temperature Rise Across Three Fixed Bed Reactors

21% 2050°F 14PSIG

29.5% 2170°F 10PSIG

151°F

169°F

*Equates to an increase in capacity of 18%.

FAIL-SAFE WITH 0 2 The hazards of oxygen or enriched air are well known in the industry. The unique safety problems associated with use of en-

163

riched combustion air on a Claus unit were evaluated. The results of this study are summarized in Figure 13-4. The safety system • shown was installed and functioned satisfactorily on the 50 ton/day Claus plants at oxygen concentrations of up to 31%. The principle features of this system were: • Reaction furnace temperature monitored by an optical pyrometer. • High reaction furnace temperature trips off oxygen flow. • High oxygen concentrations trips off oxygen flow. • Low flow of acid gas trips off oxygen flow. • Low oxygen supply temperature, indicating possible liquid oxygen in the supply gas, trips off oxygen flow. • Low air supply pressure trips off oxygen flow. • Oxygen flow control on flow recorder reset manually based on concentration of oxygen in air supply to the reaction furnace. • Oxygen pressure to preceeding FRIC set by a pressure recorder. • Oxygen flow could be shut-down from either the control room or the field.

BYPASS REHEAT EXCHANGER

P L A - P R 6 S S U 0 £ LOW ALABM F B C - F L O W RECOSDEB M L S - M A N U A L LOAO STATION AB - A N A L Y Z E * R E C O B M B H T T = H I G H TEMPEHATUR6 T R I P L T T . L O W TEfctPEBATUBE TBIP P R C I P R O C E S S BECOSMB

Figure 1 3 - 4 Safety controls for O2 enriched air in a claus unit

The feed to the first fixed bed reactor must be reheated from 370*F to 440°F. On many sulfur units, this is accomplished by a heat exchanger utilizing high-pressure steam (Figure 13-1). While this type of "indirect reheat" exchanger is a fine way to expedite sulfur plant start-ups, it does very little to improve conver­ sion of H 2 S/S0 2 to liquid sulfur. For the 50 ton/day Claus unit, a bypass to direct reheat gas to the first fixed bed reactor was in­ stalled. Figure 13-5 illustrates the location of the bypass. The partial bypassing of both the reheat exchanger and the first stage condenser reduced the Claus train front-end pressure from 10.2 psi to 9.2 psi. This reduction in front-end pressure ex­ panded capacity by 5%. Theoretically, the increase of sulfur vapors to the first reactor would reduce conversion. In practice, a small shift in the reactor temperature rise from the lead reactor to the second and third reac­ tors was noted. The theoretical reduction in conversion was too small to observe with a Drager tube analysis of the sulfur plant tail gas. The use of oxygen-enriched air and the partial bypassing of the first stage condenser and reheat exchanger resulted in a combined capacity increase of 24%. However, these two operating parameters were only used during periods of limited sulfur recovery capacity.

SCILFUR PLANT OPERATION

164 TROCIBLESHOOTINQ MATORAL GAS KlOCESSiriG

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Enriched air was limited because of oxygen cost. Use of the re­ heat bypass line required frequent and inconvenient adjustments to the reheat valve, shown in Figure 13-5, in order to control the first fixed bed reactor outlet temperature.

INCREASED FRONT-END PRESSURE The 50 ton/day Claus unit was designed for a maximum operat­ ing pressure of 15 psig for vessel mechanical integrity and air blower discharge pressure. Unfortunately, the front-end pressure was limited to 10 psig by the depth of the sulfur seal leg drains. Above 10 psig, the process gas in the reaction furnace would blow out through the sulfur drain leg, and toxic vapors would be emitted to the atmosphere. To permit a 14 psig front-end operating pressure, the seal legs were "cascaded" as shown in Figure 13-6. Sulfur drains from the boiler and the first stage condenser were looped into the second stage condenser. This prevented a seal leg blowout from occurring until the second stage condenser reached a pressure of 10 psig. The effect of this change, which allowed an operating front-end pressure of 14 psig, was to up plant capacity by 23%. The 4 psi increase in the reaction furnace pressure increased the acid gas pressure by an equivalent amount. This pressure rise backed up through the amine regenerator and raised the amine re-

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