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


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


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


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


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.


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



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


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


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



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.


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.


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
The above equation is really of little use to the field troubleshooter because C,n and P R are unknown for partially depleted wells. But,the equation does positively indicate that gas flow will never decrease as the wellhead pressure is dropped. Much to my sur prise, I began to observe that as I dropped the wellhead pressure by speeding-up the wellhead compressors that: 16

"Mendoza, this meter is broken", I complained. "Every time we increase the compressors speed to pull-down the wellhead pressure, the recorded gas flow drops. I just raised the rpm from 375 to 425, and the wellhead pressure fell from 220 PSIG to 15 PSIG. But the metered flow decreased from 180 MSCFD to 150 MSCFD. That's im possible; the meter must be broken". "Yes Sir", responded Mendoza, "you mentioned the same thing last week about that old well down near the river. But when we checked it out, the flow meter was okay". "So you think it's water again", I ventured. Mendoza settled himself comfortably on the trucks tailgate and explained. "Yes Sir, it looks like we're just sucking water into the well. The harder we suck with the compressor, the more water we bring up". "I can see that, but why don't we increase our gas make too". "You know more about these things than I do Sir. But what I've been told is that the gas in the reservoir is floating on top of a pool of brine. Once the gas pressure in the reservoir is pretty much reduced, the brine starts working it's way towards the casing perforations. The lower the pressure at the perforations, the more easily the brine flows up into the gas formation and into the well. That's called "coning", because the water is supposed to be flowing up at an angle to the perforations. Once the water enters the pro duction tubing, gas flow from the wellhead always drops off'. "Yes Mendoza, the water rising to the surface interfers with gas production. This happens because of the following: 1. The average density of the fluid inside the subsurface tubing increases.

18 TROUBLESHOOTING NATURAL GAS PROCESSING


19

TUBING PRODUCTION

2. The downhole pressure increases relative to the surface pressure. 3. The pressure difference between the reservoir and the casing is diminished and hence the flow of gas from the sand formation through the casing perforations slows". "After all", I continued, "the rate of natural gas production is really not a direct function of the wellhead pressure. Rather, the controlling variables are really the reservoir pressure and the downhole pressure:

CASING PRODUCTION

7

Q = C(PR2-PDH2)n where PDH

=

The pressure inside the casing at the level of the perforations.

"Mr. Lieberman", interrupted Mendoza, "aren't you getting off the subject again. What I want to know is what do we do now". "Suppose we get a sample of water from the high pressure separator", I answered. "We could get it analyzed for salt. If the salt content of the water is a lot lower than that of the brine produced when the well was first put on line, we can assume that water is leaking around the outside of the casing. A "squeeze-job" (i.e. forcing more cement around the casing) is supposed to correct this problem. But if, as you say, we are promoting water flow (i.e. coneing) from a water zone below the gas bearing sand formation, we had better just slow the wellhead compressor back down to 375 rpm. After all, the flowing water is probably promoting the formation of channels that will make future coneing of brine into the well even worse". DUAL COMPLETION WELLS By perforating the casing both below and above the packer, as shown in figure 2 - 1 , a lease operator can produce natural gas from two different zones simultaneously. Thus, a dual completion can double the intiial gas flow from a well. If, as often happens, the for mation being drained by the tubing is depleted first, a serious prob lem arises. If the casing pressure substantially exceeds the tubing pressure, the tubing can collapse and gas flow to the tubing side of the wellhead tree will be restricted. If the casing side formation is first to depressure, an attractive opportunity may develop. A small hole, the size of a button, may be shot into the tubing string just above the packer. The flow of high pressure gas from the tubing into

PERFORATIONS FOR CASING PRODUCTION

A ^

PACKER

Figure 2-1

PERFORATIONS FOR TUBING PRODUCTION

A dual completion well.

the annular space inside the casing, will act as lift gas. This lift gas will prevent the casing from loading up with liquids and thus surpress gas production. If this "button hole", is made too large, a re strictive choke may be required on the casing's gas production. This will probably negate the effect of the lift gas, as the restrictive choke will raise the pressure at the perforations above the packer in the same way as would liquid loading.

JET EJECTORS Figure 2—2 shows how high pressure gas from the tubing side of dual completion can be employed to compress the low pressure

2 0 TROUBLESHOOTING NATURAL GAS PROCESSING

ADDITIONAL IDEAS TO ENHANCE GAS FLOW 21

casing gas. An ejector, an apparatus in common use in process plants, acts as a compressor without moving parts. The installed cost of the apparatus pictured in figure 2-2, is less t h a n $10,000, and there are no operating costs. Use of an ejector in this service re quires that both the tubing pressure and flowing gas volume be much higher than the collection header pressure and the casing gas flow, respectively. Note also, that the ejector must be protected against the errosive sand produced form the well. Gas leaking into, and pressuring up, the casing of a partially depleted well must be bled down periodically. A W line connecting the casing to the tubing will permit this gas which slowly accumu lates in the annulus to be recovered for sales instead of being vented to the atmosphere.

worth of natural gas, a portable sand separator may be installed be tween the wellhead tree and the permanent production equipment. While portable sand separator skids may be rented, a sketch has been provided in figures 2-3A and 2-3B for those producers who may wish to build their own unit. MAWP = 2TO0 PSIG ESTIMATED WALL THICKNESS 1 2 VESSEL TO BE STRESS RELIEVED

QUICK-CONNECT

FITTING

QUICK-CONNECT

FITTING

Z\t

2 1.0 STELLITE LINED NOZZLE FITTED FOR TANGENTIAL ENTRY-

THE BIRTH AND DEATH OF A GAS WELL When a well is completed, it must be cleared of sand before it's production can be lined up to the collection laterals. This is ac complished by "flowing-back", or "flaring", the well. For a typical gas well, this requires venting the tubing to the atmosphere for 3 or 4 days at a typical rate of 5 MMSCFD. To avoid wasting $50,000 95UF 2 0 0 0 M SCFD I0O0 PSIG-)

X

MOTIVE GAS ■ 80°F

TUBING

Figure 2-3A Facility to recover wellhead gas during initial flaring.

EJECTOR CASING 2 2 0 PSIG 2 0 0 M SCFD

5 0 0 PSIG MAIN LATERAL

GAS DRIVEN PUMP

DUAL COMPLETION WELL

Figure 2-2

CIse of an ejector to produce low pressure casing gas from a dual completion well using high pressure gas from the tubing string as motive gas.

Figure 2-3B Details of portable sand separator.

22

ADDITIONAL IDEAS TO ENHANCE GAS FLOW 23

TROUBLESHOOTING NATORAL GAS PROCESSING

Towards the end of a well's life, it should probably be placed on an intermittent type operation as described in the previous chap ter. This will keep the well from loading up with liquids. As time goes by, the back-pressure from the collection lateral will be too high to permit the entrainment velocity (or flow point) to be achieved when the well is opened-up, even though it has been shutin for many days. Under such circumstances, the well must be flowed-back to the atmosphere. Addition of a few soap sticks through the wellhead cap twenty minutes prior to venting the well to the at mosphere (really to a pit to contain the brine that will be blown out) is a good procedure. Figure 2-4 illustrates the piping configuration at wellhead required to routinely acomplish the above. It may take 15-30 minutes to successfully blow the brine out of a tubing string. If the procedure is working, the wellhead pressure will climb as the slugs of brine pass up through t h e flow-back connection. Of course, once a well has declined to this point, installation of wellhead com pressor or downhole corrective measures are appropriate.

SOAP STICK LAUNCHER

M

5 ATM. VENT TO PIT

X 1X1

WELLHEAD TREE Figure 2-4

Facilities to unload a depleted well.

NORMAL GAS FLOW FROM TUBING

AN INTERESTING EXPERIMENT If a well has been killed with water—that is, gas will not flow from the well even when the atmospheric vent is left open—an in teresting observation can be made. Drop a soap stick down the well and listen as it hits the joints in the tubing string. Each joint is 30-40 feet apart, and the stick makes a quite audible sound, which can be heard at the atmospheric vent, as it passes each joint. On one 12,000-foot well, I heard the stick splash into water after descend ing past 120 joints (4,800 feet). A well that has this much water accumulation normally can not be resuscitated with soap sticks. It must be cleared of water by being swabbed out, a procedure that mechanically removes water out of the well. The loading up of wells due to condensate and water formation in production tubing is a highly complex subject. This is particularly true in deeper wells. The inter-action between the surface equipment, the reservoir characteristics, and the two or three phase flow occur ring in the tubing string really requires a computer analysis with the input of all the historical data available from the well. The re quisite software to achieve this capability are available from a number of organizations. 1 By way of summarizing the concepts discussed in the last two chapters, the reader may wish to work through the following ex ample which is based on observations made for an actual, flowing natural gas well in South Texas. EXAMPLE: J.B. Smith # 4 is flowing steadily at 1,300 MSCFD with a well head pressure of 815 PSIG and a wellhead temperature of 80° F. The gas specific gravity (i.e. its density relative to air) is 0.60. The tub ing I.D. is 2%" and the well is producing water at a rate of 10 bbl/ MMSCF. An unexpected incident at a downstream pipeline booster station causes the field pressure to increase from 800 PSIG to 870 PSIG for several hours. Later, the field pressure drops back to 800 PSIG. However, the well is now flowing erratically at an average production rate of 420 MSCFD. Calculate the entrainment ve locity, V E and the coefficient, K, in the entrainment velocity equation: V E = K VP T . Answer = 6.3 fUsec.,

- P7 Pv K = 1.37


3

REFERENCES 1. Sim Sci, Simulation Sciences Inc., PLPEPHASE Fullerton, California.

WELLHEAD SURFACE EQUIPMENT

A fully outfitted gas well will be equipped with the following items at the wellhead: • • • • • • •

The wellhead tree with a fixed choke. Heater with an adjustable choke. High pressure separator. Low pressure, three-phase separator. Gas flowrate orifice meter. Condensate tank. Brine tank. Figure 3—1 summarizes the functions and the relationship of these components. Many gas wells are not equipped with low pres sure separators or tanks; the lease operator, may feel that insuffi cient liquids will be produced to justify their expense. Also, once the wellhead pressure diminishes to the 1,000 psi range, a heater (used to retard hydrate formation) is not necessary. THE WELLHEAD TREE My initial impression of the collection of valves sitting atop a gas well was that the assemblage of hardware was unnecessarily complex. This turns out to be a false first impression. Both the casing and the tubing strings terminate at the tree. Figure 3-1 assumes that only the tubing string wiil be used to pro duce gas. This is called "single completion well". The casing below the packer has- been perforated to communicate with a gas bearing sand formation. If the casing has also been perforated to draw gas from a shallower formation, then the well would be termed a "dual completion". The wellhead pressure is shown on a gauge atop the tree. This 25

WELLHEAD SURFACE EQUIPMENT 2 7

pressure does not bear a direct relationship to the critical bottom hole pressure (i.e. the pressure inside the tubing at the level of the perforations). There are a minimum of two valves available on the tree to shut-in the high pressure gas flow from the tubing; the mas ter and the secondary (or wing) valve. The master valve is upstream of the secondary valve. The master valve is intended to last the life of the well, while the secondary valve is replaced when it starts to leak. Whenever a high pressure, flowing gas stream is blocked-in, the valve so used will be subject to the erosive force of rapidly mov ing sand. When two valves are located in series on a gas line, the valve closed first will erode. Alternately, when gas flow is to be re stored, the valve opened last will experience the effect of high vel ocity, erosive sand. This concept applies to casing wellhead valves and liquid drains from high pressure separators, as well as produc tion tubing isolation valves. How does one know when a secondary isolation valve is leaking and requires replacement? Simply close the valve and see if it stops the gas flow to downstream equipment. If a secondary valve (which I like to call the "throwaway valve") is not replaced in a timely fash ion, the master valve (which I refer to as the, "permanent valve") will also start leaking. I leave it to the reader to imagine the dif ficulty and expense of replacing a leaking master block valve on a 4000 psig gas well. CASING PRESSURE Ideally, there should not be any gas accumulation inside the casing of a single completion well. If gas does infiltrate the annular space between the casing and the tubing, excessive pressure will build-up inside the casing. If the casing pressure greatly exceeds the tubing pressure, the tubing will collapse. If you observe the opera tion of a well that has a collapsed tubing string, the only signs will be low wellhead pressure and diminished gas production. Unfortu nately, there are a host of other illnesses that beset gas wells that have identical systems: • Well loaded up with fluids. • Perforations covered with sand. • Low bottom hole pressure. • Production tubing bridged with sand. To prevent the collapse of the tubing string, the well operator's duties include venting off pressure from the casing. A cost effective method to accomplish such venting is shown in figure 3-2. Instead of depressurizing the casing to the atmosphere, the excess gas in the casing is vented into the production tubing downstream of the well head choke. This saves money. For example, venting a 1000 psig

WELLHEAD SURFACE EQUIPMENT 29


casing from a well 10,000 feet deep into a production line operating at 550 psig saves about $60 per venting incident. HEATER OPERATION Why are there two chokes shown in figure 3—2. Certainly, gas flow could be controlled with a single choke. One reason is that the erosion of the choke is reduced by limiting the pressure drop through a single restriction. Note the pressure profile between the wellhead and high pressure separator shown in figure 3 - 1 . The other rationale for utilizing two chokes on high pressure wells is to prevent hydrate formation. A following chapter, presents the causes and cures of pipeline freeze-ups. Suffice it to say here that excessive throttling across a choke will form a water-hydrocarbon solid inside the choke. To pre vent this, the flowing gas is partially reheated as follows: • Gas flows to the surface at 3500 psig and 130° F. • The gas pressure is reduced to 2400 psig across the fixed wellhead choke. As a consequence of this pressure drop, the gas cools to 80° F.

GAS PRODUCTION FROM TUBING

3/4"TUBING WELLHEAD CHOKE

- / tXl=y

'S/// Figure 3-2

/ ////

CASING VENT

///

A piece of 3/4" tubing can recover gas leaking into the casing of a single completion well.

• The gas stream is reheated to 140° F in the first loop through the heater. • The adjustable choke—which is an integral part of the heater, throttles the gas pressure down to 1100 psig. This pressure reduction again cools the gas to 80° F. It is clear from the above data that attempting to break a 3500 psig wellhead pressure down to the 1100 psig separator pressure across a single choke would cause the choke to freeze up (1100 psig natural gas may form hydrates at temperatures below 70°F) and the gas flow to cease. To illustrate this idea, let's assume that a heater's adjustable choke is freezing up. The heater is operating as hot as possible. To overcome this problem, install a smaller fixed choke in the wellhead. This will permit operating with the heater's adjustable choke in a more open position and hence reduce the temperature drop across the adjustable choke. Inadequate heater capacity can be caused by a low water level. Exposing heat transfer tubes to air also accelerates exterior corro sion of these tubes. Heating natural gas from 80° F to 140° F as described in the above example consumes about 0.2% of the well's gas flow. While this is not much of a loss, always keep in mind that hotter gas re duces compression capacity and creates dehydration problems at downstream facilities. Hence, heaters must be shut down when the danger of hydrate formation expires. HIGH PRESSURE SEPARATOR To prevent metering difficulties, and to reduce corrosion and pressure drop in downstream piping, liquids are removed from well head gas. Water plus natural gasoline condensate are drawn off as a mixed phase. Gas flows out of the separator, through the sales meter, and into the collection (i.e. lateral) piping. The two main problems associated with the operation of high pressure separators are: • Liquid carry-over. • Loss of gas through a leaking liquid dump valve. Only rarely do high pressure separators carry-over due to ex cessive gas rates. The vessel, if properly sized to handle the initial well production, will be adequate to de-entrain liquids from their di minishing gas flow as the well ages. Usually, liquid carry over is due to high liquid levels. The liquid dump valve shown in figure 3-1

3 0 TROUBLESHOOTING NATORAL GAS PROCESSING

is actuated by "instrument gas" (i.e. natural gas) flow from a con nection on the high pressure separator. Once the instrument gas bottle illustrated in this sketch fills with water, the dump valve may become inoperable due to water in the instrument gas. The resulting high liquid level in the separator will keep the instrument gas bot tle liquid full and hence continue to prevent the dump valve from operating and draining the high pressure separator. Installing a larger instrument gas bottle and instructing field personnel to drain it daily is one answer. The ideal solution though, is to supply dry instrument gas from a nearby glycol dehydrator. Dump valve instru ment gas tubing improperly aligned to resist freeze ups is also an . important factor in liquid carry over (see chapter on preventing pipeline freeze ups). The most common cause of high liquid level carry over from high pressure separators is simply that the liquid dump valve be comes mechanically inoperable, or it is calibrated to hold too high a level. If one of the level gauge glass taps are plugged; or the glass has become opaque with dirt, field personnel wil never realize there is a problem. My first assignment in troubleshooting gas field operations was to survey the high pressure separators in a system encompassing four hundred wells for undersized vessels. The dehydration station servicing these wells was being menaced by an ever increasing brine content in the inlet gas. I discovered not a single undersized separator. What I did find was a hundred inoperable liquid dump valves. Almost without exception, the gauge glass isolation ball check valves had become stuck with age and disuse. As these valves could not be opened or closed, field operating personnel had discon tinued blowing down the gauge glass to unplug the taps and clear the glass of fouling deposits. Without being able to visually locate the liquid level in the separator, they could not properly calibrate the liquid level control or know when the dump valve had become inoperable. It is usually pretty easy to find a leaking liquid dump valve on a high pressure separator. Continuous or frequent venting from the low pressure, three phase separator is one tipoff. A cool line down stream of the dump valve, as well as lack of a liquid level in the separator's gauge glass, are other indications of a leaking dump valve. A grain of sand that has become lodged in the dump valve's in strument gas bleed-off port will cause an "Air-to-Open" dump valve to stick open. Oft times, a stuck dump valve can be made operable by manually opening and closing it a few times. Not uncommonly, dump valve internals are damaged by erosive sand. To minimize

WELLHEAD SORFACE EQUIPMENT 3 1

this effect, the usual short stem plug inside the dump valve body should be replaced with a long stem carbide plug. On occasion, I have seen dump valves blowing through because a pebble had be come lodged between the plug and the seat. The only tool required to disassemble a liquid dump valve to rectify such a problem is a large hammer.

LOW PRESSURE THREE PHASE SEPARATOR The high pressure liquid flows into the low pressure separator. Typically the low pressure vessel operates at 30 to 60 psig. Below 20 psig, there will not be enough pressure to push the accumulated liquids into adjacent tanks. Above 60 psig, natural gasoline conden sate will generate excessive vapors when it is introduced to a storage tank. The low pressure separator's purpose is to separate three phases: • Brine • Natural Gasoline Condensate • Evolved Vapors. When the high pressure liquid flashes in the low pressure separator, substantial volumes of hydrocarbon vapor are generated. For example, when one barrel of a typical natural gasoline conden sate is depressured from 1000 psig to 65 psig, roughly 1.3 moles of 28 molecular weight is vented through the low pressure separator's back pressure regulation. A typical composition of this flash gas is: Carbon Dioxide Methane Ethane Propane Butanes Pentanes Plus

3% 53% 22% 13% 6% 3%

The condensate is drawn off to control the separators liquid level, while the brine is withdrawn to hold the condensation-brine interface level. It is quite important that the gas supply used to operate the liquid level dump valves not be withdrawn from the low pressure separator itself. The moisture content of gas withdrawn from a 40 psig vessel will be 18 times higher than gas flowing from a 1000 psig high pressure separator. Also, any surge in the liquid level in the low pressure separator will cause a liquid carryover


into the gas supply to the liquid dumps. For these reasons, the first step in correcting level control problems in low pressure separators is to connect a source of high pressure gas (dried if possible) to the liquid level dump valves. If the dump valves are operating properly, but surges of liquid from the high pressure separator cause natural gasoline to blow out of the low pressure separator's vent, raise the pressure setting on the back pressure controller. This will force liquid out of the low pressure separator at a greater rate. CONDENSATE TANK Maintaining the low pressure separator at too high a pressure can cause the natural gasoline condensate holding tank to over-pres sure. As a rough approximation, about half a mole of gas is vented from a condensate tank for each barrel of condensate collected. This gas evolution rate is based on a 65 psig low pressure separator pres sure and an average vapor molecular weight approximating pro pane. Most often, roofs on condensate collection tanks are ruptured when the upper liquid dump valve on the low pressure separator sticks open. This permits all the low pressure separator flash gas to blow into the condensate tank. On one occasion, I observed an operator by-pass liquid from the high pressure separator around the low pressure separator and directly to the condensate tank. He explained that the upper liquid level dump valve was stuck closed, and that consequently gasoline was blowing out of the low pressure separator's vent. While I agreed that spewing gasoline over a nearby road was dangerous, I also correctly predicted t h a t bypassing the low pressure separator would blow a hole in the roof of the conden sate collection tank. BRINE TANK If the interface level controller on the low pressure, three phase separator malfunctions, a well's entire production of natural gasoline may wind up in an open top brine holding tank. Of course, losses in hydrocarbons will be accelerated due to evaporation. More importantly, the lease operator may lose all the well's condensate. It can happen that the brine disposal truck which empties the brine tank also disposes of the accumulated condensate. The condensate is recovered by whoever operates the local salt water disposal facility. Naturally, this enterprising individual will then keep the conden sate and sell it at a substantial profit. It has been alleged that on rare occasions, t h a t the interface level controllers on the low pressure, three phase separators are en-

WELLHEAD SURFACE EQUIPMENT 33

couraged to malfunction by human intervention. Certainly, the theft of natural gasoline from wellhead storage tanks is not unknown. Dumping condensate to the brine storage tank is one method to foil auditors monitoring production losses in condensate. ORIFICE METERS Permitting a wellhead meter to read high robs your employer. The royalty and severance tax payments made by the lease operator are based on the meter readings. Pulsations in the meter run (such as those induced by wellhead reciprocating compressors) will invaribly cause the meter to read high. Occasionally, field personnel in stall a smaller orifice plate in the meter run and forget to note this fact on the flow chart. This greatly increases the recorded gas flow rate. Incidentally, most meter runs are equipped with facilities to permit change of the orifice plate without interrupting the flow of gas through the meter. This is called a "Senior Meter Run". WELLHEAD FLASH GAS RECOVERY For each barrel of natural gasoline condensate collected in stor age, roughly 1,300,000 BTU's worth of gas is flashed-off from the low pressure three phase separator. This assumes t h a t the high pressure separator is operating at 1000 psig and the low pressure separator is running at 50 psig. In addition to being environmen tally reprehensible, this venting waster $400 per day of recoverable gas on a well that is producing 100 BSD of condensate. Figure 3—3 illustrates a system to recover these vented hydro carbons. Both a volume pot and a suction pressure spill back control loop are needed to even out surges in gas flow produced when the high pressure separator dumps liquid into the low pressure separator. The action on the high pressure separator's liquid dump valve should be slowed down. The compressor net discharge gas is best injected hot into the gas production line. This is done to prevent the recondensation of the recovered vapors in the compressor aftercooler or in the cooler natural gas product. The gas flowing into the spill-back loop must, however, be cooled to avoid overheating the compressor suction. Typically, the compressor suction spill-back is set to open at 20 psig; while the atmospheric gas vent will open at a pressure of 70 psig. It is a little difficult to precisely size these vent gas recovery compressors. A rough rule of thumb is to calculate the compressor horsepower and suction volume based on the average gas rate at 40 psig. Then double both these calculated values for the final compres sor sizing. Remember t h a t this vent gas recovery installation will only be

34


WELLHEAD SURFACE EQUIPMENT

35

needed for a year or two. As wellhead pressure and condensate rates fall, the economics of continued compressor operation will diminish.

COQ.

O

(§>-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.



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


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


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.


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


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.



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.


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


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.


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.


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—

\

• The compressor valves are faulty. • The compression ratio has increased. • High pressure, high temperature natural gas is being produced from the wellhead.

oo o o oo oo o o oo oo oo

%K o o

3 oo

c 'o

UJ (0 0)

OD O

.c to aj

o -a

oo o o (0

oo o o (0

oo oo

XI

c o

+3 CO

a. <

to Q.

c 01

ONTO-PA sIDLE OLE

>

c?5o U_(— CD O

55

For air coolers limited by air flow (as opposed to inadequate heat transfer surface area) a 10°F increase in compressor discharge temperature may increase the air cooler outlet temperature by 5 8°F. The correlation between compression ratio and temperature rise is presented in Chapter 7. "Troubleshooting Reciprocating Compres sors." Temperature rises above those obtained from this correlation indicate bad compressor valves (plates or springs broken) or, less commonly, leakage across the piston rings in a double-acting cylin der. Depending on the compression ratio, a 10°F increase in the compressor inlet pressure will translate into a considerably larger increase in compressor discharge temperature. Thus, it is conceiva ble that the cooler outlet temperature may increase due to the effect of putting high temperature wells on line. GLYCOL DEHYDRATORS INCREASE GAS TEMPERATURE We invariably cool the compressor discharge prior to dehydra tion. Unfortunately, natural gas will be reheated—sometimes by 10°F — in a typical gas field dehydration contactor. This occurs be cause of two factors: • The circulating glycol may be 70° hotter than the contactor gas inlet temperature. • The heat of condensation or absorption of the water vapor contained in the wet natural gas must be dissipated into the dried natural gas.

(T»

1

If the glycol contactor is properly designed (see chapter 6) this temperature rise will not effect dehydration efficiency. However, transmission temperatures will increase.


HYDRAULIC DRIVEN COOLIMG FANS As electricity is normally not available in remote locations, the use of hydraulic powered fans is not uncommon. Normally, a cir culating hydraulic oil pump is powered by a belt drive from an en gine driving a compressor. The pressurized oil flows to an hydraulic motor which is used to rotate the fan blades, Any reduction in the discharge pressure of the circulating hydraulic oil pump will reduce the fan's speed. Other t h a n reduced engine speed, increased clear ance between the pump's impeller and wear ring due to erosion, is the usual cause of a decrease in hydraulic oil pressure. ENGINE COOLING WATER The finned tube bundle used to dissipate engine heat is nor mally placed in the same structure as the gas cooling bundle. Hence, troubleshooting engine cooling problems are similar to those difficul ties encountered in gas cooling; with two exceptions: • On start-up, you may find that it is impossible to adequately cool the circulating engine water. One 4000 horsepower recip rocating machine that I was attempting to bring on-line re peatedly tripped-off due to high engine water temperature. I was at the point of concluding that there was something rad ically wrong with the water circulation through the cooler, when a more experienced operator corrected the problem. By opening the vent on the header box shown in figure 5—3, he re stored the air cooler's heat exchange capacity. The tube bundle had become "vapor bound"; air was trapped in the header box and the upper rows of tubes. This trapped air prevented the cir culation of hot engine water through the majority of the tube bundle. • Increased impeller tip to wear ring clearance inside the engine cooling water circulation pump can cause high engine water outlet temperatures. Lower than normal pump discharge pressures, accompanied by a low air cooler water outlet temp erature, is indicative of this type of pump defficiency. TURBOCHARGER DISCHARGE COOLERS A turbocharger is nothing more t h a n a small, single stage, cen trifugal air compressor powered by the engine exhaust gas. If a re ciprocating engine is limited by the power cylinder exhaust temper ature (as most are), reducing the turbocharger discharge tempera ture by after-cooling will expand the engine's horsepower rating. This can be accomplished by passing the turbocharger discharge (i.e. compressed combustion air) through a shell and tube cooler. Lack of


57

cooling water circulation, through the tubes, as indicated by a high water outlet temperature, is one common difficulty. A high water inlet temperature is a sign of a problem with the air cooler used to remove the heat picked-up by the cooling water circulating through the turbocharger after-cooler. Note that the shell side pressure drop for the compressed air should be only a few inches of water. A high air pressure drop through the turbocharger discharge after-cooler will reduce a reciprocating engine's horsepower output.

Section

6 Troubleshooting At The Dehydration & Compression Station

"Even so-called 'complex questions' are not complex but rather a composite of simple questions. If you break it down, it becomes a series of simple questions; you solve one at a time, and then you put them together" Paul Treen, Inventor of the Automobile Thermostat, and the Bicycle Kickstand.

GLYCOL DEHYDRATION

Natural gas transported through common carrier pipelines must meet a moisture specification of 7 pounds of water per MMscf. Gas is usually dried to meet this requirement by scrubbing with a concentrated glycol solution. Figure 6-1 shows a standard glycol contactor tower, regenerator, and pump. Gas flows into the bottom of this tower where entrained water and naphtha drop out and are withdrawn under level control. The upflowing gas is contacted with the circulating glycol and dried. The glycol is pressured from the contractor to the regenerator, where it is heated to its boiling point to drive off water. Typically, 100 pounds of circulating glycol absorbs 3—4 pounds of water. After cool ing, the reboiled glycol is pumped back to the contractor tower. On the surface it would not seem possible that much could go awry with such a simple system. But, of course, the experienced pro cess operator knows that it is only a matter of time for anything that can go wrong to go wrong. As a case in point, consider the op eration of the glycol circulating pump. This ingenious positive displacement pump is driven by ex panding gas withdrawn along with the wet glycol, from the contac tor tower (see Figure 6-1). The speed of this pump is set by a small valve that controls the amount of expanding gas emitted into the pump. An operator judges the amount of glycol circulation based on the audible strokes made by the pumps internals. The quicker the strokes, the greater the glycol circulation. But suppose the pump has developed mechanical problems that reduce the volume of glycol normally pumped per stroke? Or perhaps the pump internals have deteriorated to the point that 59


GLYCOL DEHYDRATION

61

glycol circulation has stopped. Since glycol drying units are not nor mally equipped with flow meters on the circulating glycol, how can the process operator of the troubleshooting engineer recognize the problem. GLYCOL PUMP DEFICIENCIES Our company's natural gas dehydration station was located in a picturesque section of the desert just south of El Gringo, Texas. I arrived there one evening to consult on excessive moisture prob lems in our gas shipments. The dehydration station consisted of six drying towers, each served by a dedicated glycol reboiler and pump. For the past two weeks the combined effluent gas from these six towers had become progressively wetter. Finally, the owner of the pipeline who received our gas drew the line: either we dried our gas to the 7 Ib/MMscf specification within two days, or we would have our connection to the pipeline blocked in. I had no idea which of the six parallel con tactor towers was not drying the gas. INDICATIONS OF REDUCED GLYCOL CIRCULATION The first oddity I noticed was the noise from the vents as sociated with the individual reboilers. As Figure 6-1 shows, the ex panding gas, used to drive the glycol pumps is also used as fuel to reboil the glycol. The excess gas not burned in the reboiler is vented under pressure control to the atmosphere. When the efficiency of the glycol pump is reduced due to mechanical problems, two factors act to increase excess gas venting: • The reboiler firing rate drops because less glycol must be re heated. • The amount of gas flowing from the tower to the glycol pump increases because there is less glycol liquid to restrict the flow of gas. Hence, the net result of a reduction in glycol circulation rate due to reduced pumping efficiency is increased venting of excess nat ural gas. Of the six vents (one for each reboiler), only one was blow ing hard. I also observed that the main burner on this particular re boiler was rarely on. Note: Temperature control on glycol reboilers works hke your home heater—either full on or full off. Lack of firing on a glycol reboiler—that is, low reboiler heat duty—is another in dication of a low glycol circulation rate. The usual cause of glycol pump failure is deterioration of the O ring seals. Next morning, I requested that the suspect pump be


overhauled. While this work proceeded, I continued my investiga tion. GLYCOL REGENERATION TEMPERATURE The gas exiting the top of the contactor in Figure 6-1 can be assumed to be in equilibrium with the reboiled—i.e., dry—glycol. The higher the glycol reboiler temperature, the dryer the glycol. The dryer the glycol, the dryer the treated natural gas. For most of the year in El Gringo, critical control of the glycol reboiler temperature gas was not vital. Relatively cool ambient temperatures maintained the top temperature of the contactor towers below 110°F. But now, in mid-July, this temperature was peaking at 122°F every afternoon. I checked my gas purification data book 1 and calculated that, for the 1,020 psig operating perssure of the contactors, it should be possible to meet the required moisture specification. My calculations were based on a reboiler temperature a t 375°F. For triethylene glycol, which is the work horse of the gas drying industry, the maximum recommended reboiler temperature to prevent thermal degradation of the glycol is 400°F. The six El Graingo dehydrator reboilers were all set to hold 375°F. But by checking the actual reboiler temper atures with a calibrated thermometer, I determined that one of the reboilers was actually operating at 350°F as opposed to 375°F. This reduced temperature was sufficient to greatly increase the water concentration of the "dry" glycol, so that the moisture content of gas treated with this glycol stream was doubled. A simple recalibration of the reboiler temperature controller rectified this problem. Incidentally, operating a triethylene glycol re boiler at 375°F-400°F does not necessarily result in a noticeable in crease in glycol degradation. The trick is to keep the glycol filters in good repair. Dirty glycol fouls the reboiler heat-transfer tube. This in turn causes hot spots on the heat-transfer surface, which ac celerates thermal decomposition. LEAKING FEED-EFFLUENT EXCHANGER The hot glycol from the reboiler is cooled by heat exchange with the wet glycol from the contactor. This heat transfer typically takes place in a double-pipe or plate-type exchanger. On one of the double-pipe heat exchangers, I noticed that the reboiled glycol was being cooled to a rather low temperature. I suspected that this could be an indication of a leaking feed-effluent exchanger. That is, cooler (120°F) wet glycol might be leaking into warmer (165°F) dry glycol. To verify my suspicions, I blocked in the dry glycol at the reboiler and at the suction to the pump. The appearance of a steady stream of liquid at an intervening bleeder confirmed that the feed-effluent

GLYCOL DEHYDRATION

63

exchanger was leaking, hi effect, wet glycol was bypassing the re boiler and flowing straight back to the contactor tower. After fixing the leak, this reboiler and the units that had suf fered from an inefficient pump and a faulty temperature controller were put back on-line. The treated natural gas was checked and found to meet pipeline moisture specifications. FURTHER IMPROVEMENTS As a follow-up to the above .problem, several other modifica tions were made to the El Gringo operation. To extend the life of the glycol pumps' O-ring seals, an aerial cooler, constructed from a section of finned-tube piping, reduced the dry glycol temperature by 20°F. Pumping the cooler glycol halved the amount of maintenance required on the glycol pump. The composition of the glycol was also altered. A 50-50% mix ture of tetraethylene-triethylene glycol was substituted for the 100% triethylene glycol. This mixed glycol, while equally as effective for drying as its predecessor, is quite a bit cheaper than 100% triethylene glycol. 2 More important, it can be reboiled at a higher temperature to improve gas drying without encountering thermal decomposition. 3 Note that using pure tetraethylene glycol, while ef fective in a process sense, is much more costly than triethylene glycol. FLOODING DEHYDRATOR TOWERS The field supervisor's first indication of a flooded contactor tower is usually a report of excessive glycol loss. A check of a lowpoint bleeder on the gas pipeline downstream of the tower will show glycol. After refilling the glycol reboiler, the level in the reboiler gauge glass noticeably decreases after a few hours. This is a further indication of flooding. Of course, a dehydration system loosing glycol this fast cannot dry natural gas on a continuous basis. One simple explanation of such glycol losses is a leaking dry gas to dry glycol heat exchanger (Figure 6-2). Note that the glycol pressure in this heat exchanger will be slightly higher than the gas pressure. To check for leakage, shut off and block in the glycol pump, block in the dry glycol at the contactor tower, and open an intervening bleeder between the pump and the tower. If gas does not blow out of the bleeder, the exchanger is not leaking. FOULING VS FLOODING A distillation column can flood due to dry damage, undersized liquid downcomers, high liquid level in the bottom of the tower, foul-

64


GLYCOL DEHYDRATION

ing, or excessive vapor velocity. Only the latter two difficulties are commonly encountered in natural gas conditioning. The troubleshooter should first check for flooding due to excessive vapor ve locities. The following correlation may be used for trayed columns 2 feet or more in diameter with a standard 2—foot tray spacing: All. scfd

=

1/2 DS 2 . 4 8 / z Pa \ \ s g Ta /

65

This equation is not intended for design purposes; rather it is based on field observations for towers exhibiting noticeable but tollerable glycol looses. These towers had been in service for some time and had been exposed to a moderate amount of fouling. If the actual volume of gas exceeds the allowable volume as calculated above, you may be confident that an intolerable glycol loss is due to an ex cessive vapor velocity. Note that for sizing a new contactor tower, a coefficient of 2.0 in the above equation would be suitable.

where Z sg Pa Ta D All. scfd

DRY GLYCOL FROM REBOILER 2psig

,^370°F

compressibility, typically 0.9 for most natural gas drying operations Specific gravity of gas relative to air; an 18 molecular weight gas has a specific gravity of 0.62 Absolute pressure, psia Absolute temperature (°F + 460) Tower inside diameter, ft Maximum volume of gas that can be dried before glycol losses become excessive, ft 3 /day at atmospheric pressure and 60°F 250°F

— TO WET GLYCOL FLASH DRUM

-70 psig , GLYCOL HEAT EXCHANGER

I60°F-75 psig ■120° F psigGLYCOL-DRIVEN PUMP 1/050 psig-

DRY GLYCOL FROM CONTACTOR

•(,000 psig WET GLYCOL FROM CONTACTOR

Figure 6—2 A leaking exchanger permits wet glycol to bypass the reboiler.

PLUGGED TRAYS Drying towers in natural gas service can become rapidly fouled with drilling mud or formation and frac sand. The sand appears in the wellhead gas when the rate of gas production becomes excessive, and the sand is thus sucked out of the formation and into the well's tubing. Drilling mud is found in natural gas for two reasons: 1. A new well is not properly circulated and flowed-back to clear the drilling mud out of the production tubing prior to commis sioning. 2. During the drilling operation, excessive mud pressures are accidentally applied to the well, and the drilling mud is thus inadvertently forced into the producing formation. Some of this mud must eventually reappear in the downhole production tubing. Not infrequently, a dehydrator loses its ability to dry gas from a field in which a new well has been put on-line. When this occurs, the culprit is invariably drilling mud plugging the contactor inter nals. For remote locations, one procedure that has proved to work is as follows: 1. A large water truck equipped with a pump to deliver about 50 psig, is sent to the site. 2. The dehydrator tower is blocked in and depressured. Both the tower inlet and outlet are disconnected from the gas piping. A special flange attachment, designed to mate up with a hose connection, is installed on the gas outlet line. 3. A two-inch hose from the discharge of the truck's pump is con nected to the dehydrator tower gas outlet line. 4. The pump is started and adjusted so that the pressure at the top of the tower—i.e., the water inlet—is about 5 psig. It is important not to apply too great a pressure because the trays could collapse. 5. Once the water draining from the bottom of the contactor tower

6 6 TROUBLESHOOTING NATCIRAL GAS PROCESSING

appears clear, switch the water inlet to the bottom gas inlet. Over-flow the tower until the water is again clear. The water overflow rate must be substantially higher than the normal glycol circulation rate to obtain enough liquid traffic to effec tively wash the trays. Why, you might ask, it is necessary to initially wash a badly fouled tower from the top, down? A tray plugged with mud will se verely restrict the flow of water. The resulting pressure drop may be sustained by the tray when it is pressed down onto the tray sup port ring when applied from the bottom of the tray. In more accessible locations, it is a good practice to acidize a contactor tower after water washing. Acidizing consists of circulat ing an inhibited hydrochloric acid solution (typically 5% HCI) to the bottom of the tower with an acid truck. This is an effective method to clean contactors without promoting channeling of the gas flow through the trays. Acidizing is especially effective when iron scale deposits make up a portion of the fouling deposits. Including the acid disposal expense, acidizing a drying tower can cost between $20,000-50,000. When hydrocarbon deposits consisting largely of polymers formed in the glycol reboiler are the major fouling compo nent, a caustic wash, as opposed to acidizing, is in order. In the caustic washing procedure, a degreaser is also employed. A more elaborate, but thorough, procedure is summarized in Table 6 - 1 . TABLE 6-1 CHEMICAL CLEANING A DEHYDRATOR CONTACTOR 1. Circulate a solution of 9% sulfamic acid plus 1% citric acid plus 6% degreaser in hot water. 2. Circualte a 5% soda ash solution dissolved in water. 3. Circulate a 1% solution of whichever glycol is being employed. 4. Drain down and refill with concentrated glycol to normal liquid level. After G.R. Daviet et al., "Switch to MDEA Raises Capacity." Hydrocarbon Processing, May, 1984.

BLOWN SEAL A sudden surge in gas flow, or a sudden loss in glycol circulation can cause a serious reduction in dehydration efficiency. This happens because the glycol liquid seal on the dehydration contactor tower's trays is lost. When this occurs, and gas starts flowing up the downcomers shown in figure 6—1. In effect, gas is now by-passing the efficient

GLYCOL DEHYDRATION 67

contacting that takes place on the tray deck. The glycol cannot refill the downcomer pipes and displace the up flowing gas until the end of the downcomer pipe is resealed (i.e. submerged) in the glycol on the tray decks. Once unsealed, it is necessary to slow down, or even stop, the gas flow to the contactor to permit the downcomer pipes to refill with glycol. A blown seal in a glycol dehydration contactor is also indicated by glycol carry-over into the effluent gas stream. Depending on the configeration of the glycol reboiler, a low liquid level will be observed in either the gas-wet glycol separator or the dry glycol surge compart ment of the reboiler. To re-establish the glycol seal on one six bubble cap tray dehyd ration tower, I observed an operator block in the gas flow to the tower and then continue normal glycol circulation for thirty minutes before re-establishing natural gas flow.

DEHYDRATION CAPACITY VS TEMPERATURE Three process requirements must be met for gas to be dried in a standard glycol dehydration unit: 1. The gas velocity through the contactor tower must not be great enough to entrain glycol into the dried gas. Theoretically, the entrainment of glycol does not interfere with drying. In practice, the continuous loss of glycol will knock a drying plant off-line as the unit's inventory of glycol disappears. Incidentally, it is not possible to measure the water content of gas containing a glycol mist. 2. The glycol pump must have the capacity to circulate enough glycol to absorb the water vapor contained in the natural gas. Of course, hotter gas can contain more water vapor. Increasing the gas temperature from 80°F to 100°F may double its water content. 3. The glycol reboiler must have a sufficient heat-duty capacity to regenerate the glycol at a high enough temperature to adequately dehydrate the gas. As the temperature of the gas flowing through a dehydration contactor tower rises, its capacity will decrease as follows: C 2 = C1f

% + 460 V

\

2

T2 + 460 J

where C2 Cj

= =

Contactor capacity at temperature T 2 , °F Contactor capacity at temperature T l f "F


GLYCOL DEHYDRATION

If a tower temperature increases from 80°F to 120CF, a tower's capacity will decrease by barely 3V2%. On the other hand, the amount of glycol circulation may or may not greatly increase as the gas inlet temperature rises. Figure 6-3 clarifies this point. A large booster compressor is serving a con centrated gas field. The gas produced from the wells enters the com pressor's suction scrubber at a temperature independent of seasonal fluctuations. However, the aerial cooler on the compressor's dis charge cools the gas to 80° in the winter versus 120°F in the sum mer. Question: How much more glycol circulation is required to dry the gas? The requisite data to perform the calculation are given in Figure 6-^4.

SUCTION SCRUBBER

SATURATED GAS 700 FROM , PSig WELLS 70 Q F

I5CTF 1,030 psig COMPRESSOR

-e

AERIAL COOLER

T

VWW OfO

80 F-WINTER I20°F -SUMMER

DRY G A S r -

DRY GLYCOLy-

69

At first glance, it would appear that three or four times as much glycol circulation is required. But remember that the 120°F compressed gas is not saturated with water vapor; it is really superheated. The compressed gas will have the same water content until it is cooled by the aerial cooler to below its dewpoint, in this case 79°F. If a contactor tower with 10—15 trays were employed, there would likely be no effect at all on glycol circulation require ment. For the typical 6-tray contactor, industry correlations indicate that a n additional 10-30% of glycol circulation is needed; that is, far less that the 300—400% required if the gas were saturated with water at the compressor discharge temperature. 4 Suppose, however, that the gas coming out of the ground is hot, perhaps 110°F. This gas, after compression and cooling to 1,000 psig and 120°F, would be saturated with moisture. Then, during winter operation, when the gas is cooled to 80°F, only one-third as much glycol circulation would be required as in the summertime. The con densed water corresponding to the difference in water content of 110°F, 700 psig gas vs 80°F, 1,000 psig gas would drop out in the bottom section of the contactor tower.

,000 psig

/^\ 160

CONTACTOR

140 WET GLYCOLr-

uu

t 120 100 CD

80

v^

LJ

-z. 60 o o cc 401 UJ

I 20[ 60 Figure 6—3

Superheated gas requires less glycol circulation than saturated gas.

70

8<>

9(5

lOO"

SATURATED GAS TEMPEPATURE^F Figure 6—4

The water content of saturated gas.

HO"

rfo


INCREASING GLYCOL CIRCULATION The minimum circulation rate for a glycol dehydration contac tor is determined by the temperature and pressure of the natural gas at the station inlet. Locating a compressor upstream of the de hydration tower does not particularly change the required glycol cir culation rate. I have observed on several occassions that once the glycol circulation rate fell below two gallons of glycol per pound of absorbed water, the moisture content of the dried gas would sub stantially increase the amount of water in a natural gas stream (making the proper assumption that the gas is saturated at the sta tion inlet) may be calculated from Figure 6-4. In one instance, I was troubleshooting a glycol contactor that was drying gas to only 8.5 lbs. of water per million SCF. I calculated the glycol rate and determined that only 1.5 gallons of glycol per pound of water was being circulated. When I asked the station operator to increase the circulation rate, he reported that the gas driven glycol pump was already running with it's speed control valves wide open and hence there was no way he could increase the pump's speed beyond it's current 27 strokes per minute. To rectify this defficiency, I made the following operating changes (refer to Figure 6-1):

GLYCOL DEHYDRATION

71

tower may use 15 gpm of glycol flow, whereas a distillation tower of the same size may have 300 gpm of liquid flowing across its trays. Doubling or halving the glycol circulation rate does not appreciably affect the depth of liquid on the trays, and hence, it does not alter the trays' capacity. In simplest terms, a drying tower cannot be made to flood by speeding up the glycol circulation pump unless the glycol downcomers are partially plugged. TRAY DESIGN To accommodate low liquid rates, trays of the design pictured in Figure 6-5 are widely used in drying towers. The depth of liquid on the tray deck is such that the slots in the bubble caps are sub merged. This forces the upflowing vapors to bubble up through the glycol. The depth of liquid on the tray is maintained by the height that the dual downcomer pipes protrude above the tray floor. The edges of these pipes are the equivalent of the straight outlet weir used on conventional distillation trays; the main difference is that there is very little height of liquid over the weir in glycol service due to the extremely low liquid rates.

• The heat exchangers downstream of the net glycol side of the gas driven glycol pump were by-passed. • More significantly, the pressure in the wet glycol flash drum was reduced from 80 psig to 30 psig. (Note that one cannot reduce the pressure in this drum below that required to provide adequate fuel gas pressure to the reboiler burner.) The above steps reduced the back-pressure against the expend ing gas used to drive the glycol pump. The pump speed increased from 27 to 36 strokes per minute and the glycol circulation rate rose to two gallons per pound of water absorbed. Concurrently, the dried gas moisture level dropped to it's required pipeline specification of 7.0 pounds of water per million SCF. GLYCOL CIRCULATION VS TRAY CAPACITY If a 300% increase of glycol circulation is truly needed due to hotter saturated gas, will not this increased liquid rate affect the contactor's tray capacity? After all, in distillation column design, liquid flow rate over the tray weir is an important correlating parameter. A glycol drying operation uses very small liquid rates in com parison to a distillation column. A typical 6—foot diameter drying

Figure 6—5 A bubble cap tray with pipe downcomers (courtesy Smith Industries).


Valve trays are used in leiu of bubble-cap trays in some drying columns. Valve trays are less expensive than bubble-cap trays and generally exhibit about 10% more capacity. In a practical sense, these advantages are outweighed by the superior turndown ratio of bubble-cap trays. I once had an occasion to run a field test on two drying towers operating in parallel. Both towers had the same number of trays. The bubble-cap trayed column dried its natural gas feed to 7.5 lb H 2 0/MMscf at a flow rate varying from 70-95% of de sign. The valve tray column produced 9.8 lb H 2 0/MMscf a t 65% of design capacity and 8.4 lb H 2 0/MMscf at 90% of its design gas flow rate. I attribute this improved performance of the valve tray to re duced glycol leakage through the valves as the gas flow is increased. By contrast, a bubble-cap tray deck is leakproof.

GLYCOL DEHYDRATION

contact dry glycol twice while transversing the paired towers. The result of this modification was to reduce the moisture con tent of the dried gas from nine pounds to six pounds of water per MM SCFD, without any reduction in drying capacity. DRY GLYCOL

WET GLYCOL

DRY GLYCOL WET GLYpOL ORY GAS

CONVERTING TO PARALLEL DEHYDRATOR OPERATION A large dehydration station was servicing an area of declining pro duction. As gas flow was reduced, both the gas field and dehydration glycol contactor pressures spiraled down. After five years of opera tion, the contactor pressure and flow had declined from an initial 1050 psig and 335 MM SCFD respectively to 650 psig and 195 MM SCFD. Due to the location of a large number of wellhead compres sors, the summertime gas inlet temperature to the glycol contactor towers would peak in the late afternoons at 125°F. At 650 psig and 125°F inlet temperature, the gas could not be dried to pipeline specifications. The operating supervisor noted that reducing the gas flow and increasing the glycol flow to individual towers did not im prove the situation. Increasing the glycol reboiler temperature from 390°F to 420°F made a positive reduction in the moisture content of the dried gas. Unfortunately, the 420°F reboiler tempreature caused excessive rates of glycol degradation and consequent plugging of the glycol filters. One day the operating supervisor noted that one of the five towers that operated in parallel was producing pipeline specification dried gas. This tower was equipped with eight bubble cap trays; whereas the other four towers had only four trays. The evidence all indicated that the dehydration operation was limited by equilibrium considerations and not by gas through-put rates. Based on these observations, the operating supervisor decided to re-arrange the contactors in a series configeration. This revised flow scheme is shown in Figure 6-6. Each of the two, four bubblecap tray towers were paired-off, so that the natural gas flowed through eight bubble-cap trays. The circulating glycol was left to op erate in parallel on each pair of towers. This permitted the gas to

73

I-

HJ L

J L

T

T

TO CONDENSATE TANKS

WET GAS Figure 6—6 Retrofitting for series operation to enhance drying.

GLYCOL DEHYDRATION


THE CRITICAL VARIABLE—REBOILER TEMPERATURE Even if gas is superheated so that it does not contain any more moisture than a colder stream, it is much harder to dry. On one tower that was drying gas to 10 lb H20/MMscf, I tried to improve drying by doubling the glycol rate and halving the gas rate. The ef fect was nil. Only when I raised the glycol reboiler regeneration temperature by 10°F did the moisture content of the tower effluent gas diminish. It is all a matter of top tray equilibrium. That is, the moisture content of the dried gas cannot be any lower than the par tial pressure of water in the glycol leaving the reboiler. The temperature at which this equilibrium limit applies is the mixed temperature of the dried glycol and the wet gas plus the heat of condensation of the moisture removed with the glycol. Note that in this calculation of the temperature of the gas is typically 25 times more significant than the temperature of the glycol. As a rule of thumb, the glycol reboiler temperatures should be increased by 10°F for every 5°F increase in the equilibrium top tray temperature of the contactor tower. Therefore, if you are drying gas from the discharge of an aerial cooler, you must raise your reboiler temperature by 10°F when the ambient temperature rises by 5°F to maintain a constant moisture specification in your dried gas. And remember, this is true regardless of the water content or flow rate of the wet gas. The capacity of a contactor tower drying natural gas is not sig nificantly reduced during hot weather, If, as the weather gets warmer, an operator neglects to increase the glycol circulation rate, it may appear to him t h a t he must cut the tower's gas rate to main tain on-spec gas. Or he may run out of the reboiler heat duty re quired to heat the glycol sufficiently in hotter weather and also at tribute this deficiency to excessive tower throughput. The fact of the matter is, however, that given sufficient glycol circulation of the proper moisture content, a contactor will properly dry natural gas until the trays in the tower flood. OVERHEATING GLYCOL The maximum recommended glycol reboiling are: Diethylene Triethylene Tetraethylene

temperatures for

continuous

340°F 400°F 430°F

Exceeding these temperatures is a self-defeating process. The glycol will begin to degrade. In this state it tends to foam in the contactor

75

and cause premature flooding. A black, viscous glycol solution indi cates that heavy hydrocarbons are carrying over in the gas to the contactor. A sweet, burnt-sugar smell, accompanied by a low pH and a dark but still transparent solution, signals that thermal degrada tion is occurring in the reboiler. 5 Salt laydown on the reboiler heater surface also produces the sweet smell indicative of glycol degrada tion. The best way to improve drying when limited by the contactor top tray equilibrium is to use stripping gas in the reboiler. This is a patented process (U.S. Patent No. 4,179,328) and involves the in jection of natural gas into the boiling liquid phase of the glycol re boiler. A horizontal sparger pipe is used to distribute the stripping gas, which reduces the partial pressure of steam in the reboiler and hence results in a drier glycol. The moisture content of the dried gas can be reduced by several lb H 2 0/MMscf using stripper gas. Several scf per gallon of glycol circulated is a typical stripping gas rate. Un fortunately, all of the striper gas is vented off the reboiler to the at mosphere and lost. Figure 6-7 shows an alternate design for injecting stripping gas into a glycol reboiler. A mini-stripping tower is welded onto the back end of the over-flow baffle inside the reboiler. The "tower" con sists of a box packed with one foot of 1/2" ceramic berl saddles. The required cross-sectional area of the box is calculated as if it was a packed column. A support grid is attached to the bottom of the box, the reboiled glycol pours into the box across the over-flow baffle. The entire assembly may be purchased as a retrofit kit from Smith In dustries. Field tests have shown that stripping gas injected into a glycol reboiler, fitted with this type of facility, produces drier glycol than adding stripping gas through the sparger pipe described above. LOBE OIL IN GLYCOL An operator once asked me to inspect his dehydrator to deter mine the cause of excessive moisture in dried gas. All the normal parameters checked out O.K.: • • • •

Reboiler temperature high enough to regenerate the glycol. Adequate glycol circulation. Stripping gas on. Contactor temperature and pressure adequate to achieve proper dehydration. What could the problem be? I asked the operator, a quick witted fellow called Little Red, if he was experiencing unusual glycol losses. Sometimes severe flooding and carry-over of glycol into the dried gas will cause an increase in the gas moisture's content.


GLYCOL DEHYDRATION

77

"Not only are we not losing any glycol", he responded, "but we actually seem to be gaining. I've noticed that my liquid level in the surge compartment at the end of the glycol reboiler (see Figure 6-8) has come up recently." My first thought on hearing his comment was t h a t a large quantity of compressor lube oil had leaked into the gas stream and commingled with the circulating glycol accumulated in the reboiler. I checked the amount of oil in the reboiler sight glass and noted an inch or two of brownish oil floating atop the glycol. "There doesn't appear to be much oil in the reboiler," I ob served; "but to be safe, let's open up the skimming valve (see Figure 6-8) and drain off the oil that is there." T <

VENT T0

o

REBOILER

"o

u _>,

l'/2" GLYCOL FROM REBOILER 600 G/H>

*1

_H I" BERL SADDLES

CVJ

o .2

I
a.

STRIPPING GAS 1300 SCFH

M

*

en ja CO

a>

-|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


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


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-



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


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.



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 .


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:


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-


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


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



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.


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.


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:


.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


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.


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


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


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.


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.


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


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-


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-


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% <7o BUTANE IN WITH PROPANE PRODUCT

3%

2%

JET t

i

2000

3000

FLOOD^ i

i

4000

5000

REFLUX, BSD Figure 11—1 Reduced separation at higher reflux rates indicates flooding.

122 TROUBLESHOOTING NATCIRAL GAS PROCESSING

Downcomers can flood at even relatively low liquid rates if the bottom edge of the downcomer is not submerged in the liquid on the tray deck. Unsealing the downcomer in this manner permits upflowing vapor to interfere with liquid flow in the downcomer, thus re duces downcomer liquid handling capacity. Downcomers will also flood at low liquid rates due to high pressure drop across the tray decks. After all, the height of liquid in the downcomer must be suf ficient to overcome the pressure differential between trays. Thus, fouling deposits on tray decks, which reduce the open area available for vapor flow, can precipitate downcomer back-up and liquid flooding. The downcomers do not have to be over-flowing for excessive tray loads to reduce tower efficiency. Figure 11—1 shows data col lected on one NGL propane-butane splitter. The cause of increased butane content of the tower overhead at the higher reflux rates was excessive entrainment of liquid between trays. Factors, such as in creased reflux rates, which raise the liquid level on the tray decks, promote entrainment which, when excessive, is called "Jet Flood'.

JET FLOOD Of course, flooding induced by downcomer back-up will also raise the liquid level on the tray decks; while liquid entrainment in-


123

creases downcomer loading. Hence, the terms jet and liquid flood are somewhat a matter of semantics. Flooding—as far as operational personnel are concerned—is indicated by the following: • The temperature spread between the reboiler outlet and the tower overhead is reduced as the feed rate is raised. • The concentration of the heavy key component increases as the reflux rate is increased. • With the reboiler heat duty fixed, increasing the reflux rate does not result in a proportionate increase in the bottoms product rate. Tray loading which corresponds to the type of incipient tray flooding described above is characterized by the following: AP .> 20% CS.G.) (TN) (TS) where AP S.G.

= =

TN TS

= =

Pressure drop in inches of water Specific Gravity of the liquid on the tray at the appropriate temperature Number of trays Tray spacing, inches.

MEASURING TRAY PRESSURE DROP To obtain an accurate pressure drop measurement across the trays in a low pressure fractionator (less than 15 psig) a single pres sure gauge can be used. However, for most services involving pro pane, butane and natural gas condensates, a delta P gauge such as a Magneholic must be employed. Magneholic gauges are available for pressures up to 500 psig. For troubleshooting purposes, it is best to locate the Magneholic gauge as shown in Figure 11-3, rather then rely on inert gas purging of the pressure taps to prevent liquid condensation in the pressure drops which distort the true measured tray delta P.

CONFUSING INCIDENTS

Figure 11—2 The bottom edge of a downcomer should extend 1/2" below the top of the weir.

Process plant troubleshooting is characterized by a decent realism. As a proof of this axiom, consider that measuring a tower pressure drop does not prove the tower is not flooding, t h a t measuring a high tower pressure drop does not establish

into lowand that



the trays (or tower packing) is overloaded. For example, the operators at one NGL plant noted an unusually high butane content in their depro'panizer overhead product. To rectify the problem, they increased the reflux rate by 20%. This only seemed to degrade the fractionation further. The operators checked the rectification section pressure drop, expecting to find the trays flooded. To their surprise, the measured pressure drop per tray was quite low. Did this mean the tower was not flooding? When I inspected the tower, I found an absolutely positive in dication of floodings; a vent line on the tower overhead line emitted liquid when cracked open. This observation, coupled with the low

DELTA V GAUGE

OVERHEAD REFLUX

125

measured pressure drop per tray, indicated that only the top tray was flooding. When we opened the tower for inspection, we found the deck of the top tray encrusted with corrosion products. These de posits had caused a high pressure drop on only the top tray and had caused the downcomer on only the top tray to back-up.

HIGH LIQUID LEVEL INDUCES FLOODING Figure 11—4, illustrates the operation of a debutanizer equip ped with a kettle reboiler. The liquid level in the bottom of the tower is determined by the pressure difference between the reboiler and the tower (As the reboiler vapors vent back to the tower, the reboiler must be at the higher pressure). The plant operators observed that when they increased the reboiler heat duty beyond a certain point, the tower's delta P gauge reading would dramatically increase, indicating flooding. They therefore erroneously concluded that the trays were overloaded. However, the tower flooding was being induced by a high tower bottoms liquid level. As the reboiler duty was increased, the reboiler

H *

VAPOR INLET

BOTTOMS

BOTTOMS Figure 11—3 Installation of a Delta "P" gauge with self-draining is vital to detect tray flooding.

Figure 11—4 Increased AP in the vapor line will raise the liquid level in the bottom of the tower to the vapor return nozzle, at which point the bottom tray will flood.



VAPOR

pressure also increased. This raised the level in the tower bottoms. When this level reached the reboiler vapor return nozzle, the tower flooded due to e n t r a p m e n t of liquid from the bottom of the tower up to the bottom tray. The operators had noticed that the liquid level rose when the reboiler duty was increased, but they thought that the bottoms liquid level would not cause tray flooding until this level reached the bottom tray. This point deserves emphasis:

T ^REFLUX

When the tower bottom's liquid level rises to the vapor inlet or reboiler return nozzle, the bottom tray begins flooding. The flooding spreads up the tower until liquid is carried overhead. However, even at this point, the indicated liquid level in the tower is still at the level of the vapor inlet nozzle. A careful pressure drop survey indicated t h a t there was a n in explicably high pressure drop in the liquid inlet line. When the tower was opened for inspection, the carcass of a dead rat was dis covered lodged in the reboiler liquid inlet nozzle. Inadvertenly, this r a t casued the tower to flood as the reboiler rate was increased. If the rat had expired in the vapor outlet line, the effect would have been the same.

FEED*

VERTICAL TEMPERATURE SURVEY One of the most powerful tools available to identify tray flood ing is a radiation scan. A vertical survey of a column using a radioactive source measures hydrocarbon density inside the column at various elevations. Such a survey will reveal both foam and liq uid levels in downcomers and tray decks. Unfortunately, this is a rather expensive procedure; $25,000 per tower survey being a typ ical cost. The objective of a radiation scan is to pin point the particular tray that is initiating flooding. This tray acts as a pinch point in the column. That is, the trays above the tray which is flooding will also flood (but to a somewhat lesser extent). The trays below the pinch point tray will not be particularly effected. A "poor man's" method of locating the "pinch point" tray is the vertical temperature survey. This is accomplished as follows: • Using the tower vessel sketch as a guide, locate the position of the downcomers. • Cut a 1" diameter hole in the tower's insulation in line with the center of each downcomer.

-268°F

297°F

BOTTOMS Figure 11—5 Temperature inversion is a definite indication of flooding.

127


• Using a surface pyrometer (find a probe with a flat, flexible head) carefully and accurately measure the external temper ature of each downcomer. Figure 11-5 shows the results of one such survey. If a tower is functioning properly, the tray temperature will always decrease a t higher tray elevations. Even when tray efficiency is low, there will still be a temperature gradient of constant direction. However, the data shown in Figure 11-5 indicates a temperature inversion in the stripping section of the column. There are two possible explana tions for this inversion:


129

the tower's bottom level settles out below the vapor inlet nozzle and the flooding and excess rates of amine carry-over stops. To the operators, the cause of the flooding appears inexplicable. It has apparently started and stopped by itself. However, it is pos sible to locate the level in the bottom of an amine natural gas scrub ber by touch. The liquid outlet normally is 20°F to 40°F warmer t h a n the vapor inlet. This temperature difference, when noted on the outside of the tower's shell, corresponds to the true bottom's liquid level. To prevent this situation from developing, hydrocarbon skim ming taps should be provided in the bottom of natural gas amine H 2 S scrubbing towers.

• Tray flooding. • Upset tray decks. If the observed pressure drop across the trays is small (in terms of equation 1 above) the cause of the temperature inversion is upset trays. On the other hand, if an increased reflux rate enhances a temperature inversion between trays, flooding may be predicated with confidence.

TWO PHASE BOTTOM LEVEL PROBLEM When does the level indicated in a gauge glass not correspond to the liquid level in a vessel? Assuming the level taps are unplugged, is it possible for the liquid level in the bottom of a distillation tower to be higher than the level in the gauge glass? Figure 11-6 illustrates a rather common occurrence in a nat ural gas amine H 2 S scrubber. A light hydrocarbon with a 0.7 specific gravity is floating atop amine with a 1.0 specific gravity. Due to the location of the level taps, the liquid in the gauge glass is only amine. If we think of the gauge glass and the bottom of the tower as the two legs of a two-phase manometer, it's apparent why the liquid (i.e. hydrocarbon) level inside the tower is above the level in the gauge glass. This phenomenon is a common cause of flooding in gas scrub bers. Due to an erroneous level indication, the liquid hydrocarbon is permitted to rise to the vapor inlet. The liquid is then entrained by the upflowing gas onto the bottom tray. The mixing of the liquid hy drocarbon with the aqueous amine solution promotes foaming and hence flooding of the bottom tray. The foaming/flooding spreads up the tower until gross quantities of amine are carried overhead with the sweet natural gas. Once the accumulated liquid hydrocarbon in the bottom of the tower is flushed overhead by the flooding trays,

VAPOR INLET

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FOAMING Equation 1 above, states that a tray will become less efficient due to incipient jet flood when the pressure drop per tray, expressed in inches of liquid, equals 20% of the tray spacing. The inches of liquid term assumes the liquid is deaerated. Of course, the liquid in the downcomers and on the tray decks is closer to a froth t h a n to a flat liquid. The more highly aerated the liquid is (i.e. the more foam-like it becomes), the greater will be the depth of liquid corres ponding to a measured external pressure drop. Hence, liquids which foam in distillation columns (such as dirty amine and ethane rich fractionators) reach their incipient jet flood at pressure drops below the 20% indicated in equation 1. Ordinarily, this foam cannot be observed in the column's bot tom sight glass. Even if the bottom of the tower is retaining a foam level above the vapor inlet (or reboiler return nozzle), the fluid in the sight glass is a flat, deaerated liquid. To observe a high foam level in the bottom gauge glass proceed as follows: • Block in the bottom gauge glass level tap. • Open completely the top tap. • Crack open the gauge glass drain valve.

131

trays. Maximize the number of caps or sieve holes on the tray decks. Oft-times, a minor change in a downcomer dimension or the width of a tray ring can accomodate an additional row of valve caps or many more sieve holes. Use a valve-cap retainer assembly that does not restrict vapor flow. This, and the following items, all add slightly to the cost of a tray. Install tray decks fitted with venturi openings. This will reduce tray delta P. Slope the downcomers so that the outlet area is 65% of the top downcomer area. Use swept-back weirs as described in the KOCH tray design manual. This will reduce the height of liquid over the weir. Install recessed sumps under the downcomer outlets. In effect, this modification increases the open area under the downcomer and this reduces downcomer pressure drop. Reduce the height of the outlet weir on each tray. Many trays come with adjustable weirs, and if a tower is flood ing due to liquid backing-up out of the downcomers, (which is indiNON-RESTRICTIVE VALVE CAP RETAINER

Assuming the foam is above the top tap, the foam will slowly start running down the gauge glass and hence can readily be ob served.

EXPANDING TRAY CAPACITY SLOPED DOWNCOMER

The capacities of existing towers can best be expanded by changing from trays to structured type packing. Although this is an expensive modification, increases in tower capacities of up to 35% can be achieved. Unfortunately, one study showed that the internals for one 8'-0" I.D. isobutane-normal butane splitter would cost $45,000 for trays and $290,000 for structured packing. A less ambitious plan to expand distillation capacity is illus trated in Figure 11—7. Combining the ideas shown in this sketch with some other common tray features can easily increase capacity by 25% in many instances: • Convert from single, to dual-pass (or even four-pass) trays. Never use three-pass trays as poor vapor-liquid distribution will surely result. • Use "anti-jump" baffles on the center downcomer of two-pass

RECESSED SUMP ROUNDED DOWNCOMER OUTLET

Figure 11 —7 Methods to enhance tray capacity without sacrificing fractionation efficiency.


12

cated by a step increase in tray delta P, as the reflux rate is in creased), reducing the weir height may significantly enhance tower capacity. Ordinarily, the top edge of the weir is ¥2 in. above the bot tom edge of the downcomer. This dimension keeps the downcomer sealed in liquid so as to prevent vapor blowing up through the down comer. However, this seal height may be changed to zero (for small diameter towers where the trays have been carefully and accurately leveled). A zero seal depends on the hydraulic height of liquid over the weir to submerge the downcomer outlet. Reducing the weir height by ¥2" will drop the liquid level in the downcomer by one inch. Decreases in weir heights should be undertaken with the knowledge that, on occasion, rather unpleasant reductions in tray ef ficiency have been observed after such decreases.

AMINE REGENERATION AND SCRUBBING

DAMAGED TRAYS Most often, tower packing supports are dislodged, or distillation trays upset, when a tower is operated with an excessive bottom liquid level. Forcing heat into a tower, when the liquid level is sev eral feet above the bottom tray deck, often results in dislodging the bottom few trays. Occasionally, trays are mis-assembled during a turn-around. The result of either of these mis-adventures is di minished fractionation efficiency. While x-ray pictures of tower internals easily detect most type of tray damage, this can be a cumbersome and expensive trouble shooting procedure. A simplier way to obtain almost the same infor mation is by a pressure survey. Tower pressure drops of less than one inch of water per tray typically indicate tray damage.

Figure 12-1 is a process flowsheet showing how amine solution is circulated to various refinery scrubbers to absorb H 2 S and C 0 2 in the scrubbers. The resulting rich amine is stripped in the re generator. Released acid gases (H 2 S and C0 2 ) are charged to the sul fur recovery plant. Amines are an organic base. When mixed with water, they turn pH paper blue. The two most common forms of amine used are MEA and DEA. Monoethanolamine (MEA) is the most powerful and reactive. DEA and a host of other less-reactive amines are also used in the industry. Unfortunately, MEA is the most corrosive of the amines. It is this corrosive aspect of amine solutions that makes the operation of amine systems a challenging job. DIRTY AMINE Symptoms of a dirty, corrosive amine system are: • • • • •

Carry-over of amine from the scrubbers. Dilution of the amine system with water due to reboiler leaks. Plugging of instrument taps with particulates in the amine. Loss of amine to the sewer because of leaks. Rich amine leaking into lean amine in the cross exchanger. Problems related to improper operation of the regenerator are:

• Too much H 2 S in sweet gas. • Excessive energy use in the regenerator reboiler. • Flooding in the regenerator tower. 133



135

The operating engineer troubleshooting an amine system should first draw a sample of lean amine into a glass container. If the unit is in trouble, the amine will be dirty. Determining what has caused the build up of dirt and what can be done to clean up the amine is the main subject of this chapter. THE SEEDS OF DESTRUCTION Take a glass quart sample bottle and fill it with unfiltered lean amine. You can rate your amine. quality as follows: Bright and clear. Amine is in excellent shape. A blue or green tinge indicates the presence of cyanides, but this is of no great consequence, except that excessively rich amine can then promote hydrogen blistering in H 2 S absorbers.

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Grayish cast. Solution is a pale, dull gray. Objects can be seen through the bottle without difficulty. This is okay; however, do not let the amine solution get dirtier. Translucent black. Objects can barely be seen through the bottle. Upon standing ten minutes, a small amount of sediment is visible. You are now in trouble. Erosioncorrosion is generating particulates faster than they can be removed. Opaque black. Give the bottle a good shake. If you can't see through it, start polishing up your resume. You will notice a lot of particulates settling in the bottle. A similar fouling process is proceeding in the plants equipment. If the amine looks brownish, air is getting into the system. Oxidized amine is corrosive. Submit a sample of unfiltered lean amine to the lab to deter mine quantitatively the wt% particulates. A good solution should be less than 0.01 wt%. DIRTY AMINE RUINS OPERATION

(0

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Running a sulfur recovery operation with dirty amine is analogous to deficit spending. You are borrowing against the future, but the day of reckoning will surely come. The insidious aspect of circulating dirty amine is its erosive na ture. Carbon steel is corroded by clean amine. However, the sulfide products of corrosion stick to the metal surfaces and inhibit further attack. Particulates in the circulating amine erode this protective layer. New metal is exposed to corrosion, then more particulates are generated as the corrosion-erosion cycle perpetuates itself. This en-


vironment is manifested by several signs. Foaming. Dirt reduces the surface tension of liquids. Particulates will cause amine to foam. Foaming in regen erators results in high amine concentrations in the regen erator reflux water. Foaming in the scrubbers causes amine to be carried overhead with the hydrocarbon being scrubbed. Plugged instrument taps. Flow rates in dirty amine systems tend to be erratic. Orifice taps on flow meters and level taps on float chambers often plug. Level control in the bottom of the scrubbers becomes unreliable and massive carry-overs of amine are frequent. Condenser fouling. Rich amine regenerator feed splashes overhead. Particulates accumulate in the regenerator condensers, heat transfer is impaired to a certain extent, and the reflux temperature rises. Reboiler tube failures. Enhanced corrosion rates are most evident in the regenerator reboilers. Dirty amine has caused tube failures after six months of service. Filter plugging. The dirtier the amine, the shorter the filter life. The shorter the filter life, the dirtier the amine. For really bad amine, filter pressure drop can increase one psi per hour. Regenerator flooding. Eventually, dirty amine plugs the regenerator trays and the massive carry-over of liquid which follows shuts down the sulfur plant. CLEANING OP AMINE The iron sulfide particulates circulating in a dirty amine sys tem have built up from a combination of factors. Foremost among these is inadequate filtering. There are three common types of filters: rotary precoat filters, cartridge filters, and stacked paper plates. In practice, cartridges and paper plates are best. In particular, Sparkler stacked filters are easy to maintain. Operation of rotary precoat filters is complex. Car tridge filters are good, except that the cartridge cost can be high when frequent change-outs are necessary. Stacked paper plate filters are quite simple: the paper is discarded after each use. On one unit it was estimated that 1,000 lb of particulates had accumulated in one 50-plate Sparkler filter. The trick to successful filter operation is always to filter 10


137

percent of the circulating amine. In practice, two filters are piped up in parallel. When one filter cannot pass 10 percent of the flow with.out exceeding 50-psi pressure drop, switch filters. Then immediately change the paper in the spent filter. For a clean, well-designed unit, switching on a one-month cycle is typical. When amine is black, one may be switching filters every day for a month before solution cleanliness is improved. It will take two men three hours to renew a large paper-plate unit. The operating engineer needs to convince the unit superintendent on the necessity of investing this maintenance manpower to change filters regularly on a priority basis. CORROSION INHIBITORS To clean up amine, the rate of particulate generation must be slowed and the iron sulfide already in the amine filtered out. Reduc ing corrosion rates is the way to do this. In one midwestern location, the amine solution was thick with iron sulfide. Within two weeks, the solution was restored to a light gray by constant filtering, maximum reclaimer operation (see follow ing section), and use of a corrosion inhibitor. Twenty-five percent MEA was being circulated. A high molecular weight film-forming amine corrosion inhibitor was slugged into the regenerator reboiler inlet. Corrosion rates, as monitored by a probe on the reboiler outlet, fell from 50 mil/yr to 3 mil/yr. REBOILER CORROSION Hot rich amine eats carbon steel tubes. To minimize corrosion rates, the operating engineer must be sure t h a t incompletely stripped rich amine is not reaching the reboiler. If substantial reflux is provided, one can be sure that the amine is well stripped before it is drawn off the reboiler trapout tray. The regenerator reflux rate (lb/hr water) should be 10-30 per cent of the reboiler steam rate. To double-check stripping efficiency, pull samples of lean amine and reboiler feed. Both should have the same H 2 S concentration. Remember, H 2 S must be stripped out of the regenerator trays, not in the regenerator reboiler. This is important enough to repeat: keep a decent reflux rate in the regenerator to prevent reboiler tube corrosion. Make sure t h a t the steam condensate level in the reboiler channel head is below the bottom row of tubes. Also check that the reboiler steam supply has been completely desuperheated with clean steam condensate. Preventing water submergence of tubes and using desuperheated steam results in cooler reboiler tubes. This slows down corrosion and particulate generation.



139

REGENERATOR FEED TEMPERATURE Rich amine is heated in the cross exchanger (see Figure 12-1). Over-heating causes acidic vapors to flash out of the rich amine. These wet acidic vapors will corrode the cross exchanger. Keep the rich amine below 190°F by diverting the lean amine around the ex changer.

RECLAIMER OPERATION Only MEA solutions can be reclaimed at ordinary regenerator pressures. Twenty-five percent MEA has been successfully used when accompanied by a consistent reclaimer operating program. MEA is the most reactive of all amines, and hence most subject to degradation. For MEA service, the reclaimer can be the most im portant piece of equipment on the unit. Figure 12-2 shows a prop erly operating reclaimer. MEA exposed to oxidizing agents (COS, S 0 2 , 0 2 ) reacts to form soluble products of degradation. These prod ucts are corrosive and must be removed from the circulating solu tion. The reclaimer is simply a pot boiled with a steam coil. Vap orized MEA solution is vented back to the regenerator. The products of degradation remain behind. When soda ash is added to the re claimer, the MEA tied up in the products of degradation are re leased. Reclaimer duty should be maximized consistent with avail able heat transfer capacity. However, don't overheat the amine— 300°F is the maximum temperature limit. Reclaimer duty may be defined as pounds per hour of solution vaporized. This is equal to the steam flow to the reclaimer. If the steam meter isn't working, the operating engineer can measure the duty as follows: • Mark the amine liquid level on the reclaimer gauge glass. • Block in the amine feed to the reclaimer, keep the steam flow constant. • Measure the time it takes for the gauge glass level to fall 4 in. • From the reclaimer geometry, calculate the volume of liquid boiled off in Ib/hr. This is the reclaimer duty. A reclaimer duty equal to 1 percent of the regenerator feed is acceptable. A more rigorous, method is to analyze the lean amine for thiosulfate. The thiosulfate level is a measure of the products of de gradation in amine. Keep its level below 0.05 wt%.

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WASHING THE RECLAIMER A reclaimer first put on-line will have a vapor outlet temper ature of about 270°F. When this temperature reaches 295°F, the re claimer should be taken off-line and cleaned. You can delay remov ing the reclaimer from service by adding steam or water to the shell side. Regenerator reflux water is the usual source of water. The water dilutes the amine salts in the reclaimer, thereby re ducing the boiling point. If regenerator reflux water has been used, the amine system water balance remains unchanged. Unfortunately, the pounds per hour of dilution water added must be subtracted from the reclaimer duty. When the reclaimer duty is 40 —50 percent of its clean duty, it should be washed. The heavy ammonia odor emitted from the reclaimer as it is steamed and washed is normal.

HOW MUCH SODA ASH TO USE Soda ash or caustic may be used interchangeably to neutralize the acid products of degradation in a reclaimer. To calculate the moles per day of N a 2 C 0 3 or NaOH required, measure the reclaimer feed rate (assume it is equal to reclaimer duty in lb/hr). Multiply this by 24 hours. Next, submit a sample of lean amine to the lab oratory for thiosulfate concentration analysis. From the volume and normality of KOH used in the lab to titrate for thiosulfate, calculate the equivalent pounds of NaOH or N a 2 C 0 3 needed to titrate one pint of lean amine. Soda ash will neutralize twice as much thiosul fate per mole as does caustic. Finally, multiply the reclaimer duty (lb/day) by the previously calculated value. Add the required amount of soda ash or NaOH on a batch basis once per day. A typical value for a unit circulating 1,500 gpm is 1 0 40 lb/day of soda ash. Precise regulation of soda ash addition is not necessary. EXTENDING RECLAIMER TUBE LIFE Reclaiming MEA is a tough service for carbon steel tubes. Cer tain stainless steels cannot be used in most applications because chlorides concentrate in the boiling liquid and cause stress corrosion cracking, (316 S.S. is one of the better materials used for bundle retubing in this service.) Retubing bundles every two years is not unusual. To prevent excessive tube failures, keep the tube bundle submerged in liquid. Place a prominent red line on the level gauge glass to show the operators the height of the tube bundle. A pattern of tube failures near the top of the bundle indicates the operators are often running at too low a liquid level. Use superheated 60-90 psig steam to reboil the reclaimer.

AMINE REGENERATION AMD SCRUBBING

141

Check this with a thermometer and pressure gauge. If the steam is not saturated, your condensate supply to the desuperheater is not working. The chemistry of MEA degradation and reclaiming is dis cussed in detail by Polderman et al. USING A RECLAIMER INSTEAD OF A FILTER In one large treating facility, filtering the MEA solution had been temporarily discontinued. The amine had turned black. Consis tent use of the reclaimer alone effectively cleaned up the solution. Twenty gpm of the 1,400 gpm lean amine circulation was charged to the reclaimer. To extend reclaimer washing cycles, steam was injected directly into the shell side of the recleaimer. This diluted the amine and re duced the reclaimer temperature. To maintain the system water bal ance, only 100 percent MEA was used as make-up to the lean amine storage tank. When the reclaimer contents had noticeably thickened (usually after two weeks), it was washed out. After three such cy cles, the particulate content of the lean amine had been reduced by 80 percent.

FOAMING Most large amine spills are a consequence of scrubber foaming. The amine solution froths up on the trays and is carried overhead with the sweet gas. Foaming in a scrubber can be stopped by reducing the amine flow to the scrubber. Install a Delta P cell across the scrubber trays to observe when the scrubber is foaming over. If the indicated pres sure drop (in feet of water) equals 40 percent of the height between the top and bottom trays, the scrubber is foaming over. Use a strain gauge to connect the delta P cell to the scrubber, which eliminates the problem of plugged pressure taps. Have the pressure drop read out activate an alarm in the control room.

CAUSES AMD CURES OF FOAMING Dirt reduces the surface tension of amine; this is the principal cause of scrubber foaming. Especially in MEA systems, products of degradation precipitate foaming. Consistent filtering and reclaiming can eliminate these problems. Corrosion inhibitors cause foaming. Pour some freshly made amine solution into a clean bottle. Add a typical concentration of inhibitor and shake vigorously, then see if any unusual foaming appears. Sometimes, the paper

142

THOuBLESHOOTTNG NATURAL GAS PROCESSING

used i n filters is coated with a chemical than can cause foaming. Tear off a piece of this paper and shake it with amine to see if the solution foams up. Silicone antifoam agents, when used i n excess, cause foaming. A squirt of silicone defoamer will temporarily stop foaming; too much will make the problem worse. Charcoal filters need to be changed. You should be passing several percent of the circulating solution through a charcoal bed. The charcoal removes surfactants. Change the charcoal a t the first indication of foaming, but be sure not to let charcoal fines enter t h e regenerator and scrubbers, as these fines also cause foaming. Hydrocarbons condense in cold amine. The lean amine temperature must be 10°F above the dew point of t h e sweet gas. Cooler amine will condense liquid hydrocarbons and initiate foaming. Cold amine (70°F) will in itself have a tendency to foam. Detergent cleaners may have been used during a unit turnaround. When the unit is put back on line, the deter gent finds its way into the amine system. The charcoal filter should absorb this detergent. DECLINING AMINE STRENGTH To determine why amine strength is weakening, send a sample of lean amine to the lab for total dissolved solids (TDS). Also, submit the water used for amine system to make-up for TDS. A high TDS for t h e amine sample indicates a leaking amine water cooler. For each cooler check the inlet water pressure and the outlet amine pressure. If the water pressure is higher, proceed as follows:


If none of these steps has identified the problem, it is likely there is a regenerator reboiler tube leak. When the regenerator has one reboiler, it cannot be taken off-line for leak testing. In this case, inject a small qualtity of a tracer chemical into the steam supply. Then check the regenerator bottoms by chemical analysis for the tracer. Sulfur hexafluoride or lithium bromide can be used.

RETROFITTING TIPS A few changes can reduce the amine unit's potential to corrode: Velocities. Revamp process piping so that velocities are less than 10 ft/sec. For exchangers, hold velocities below 3 ft/sec. Remember, rapidly flowing amine is erosive. Rich amine flow control. Locate the regenerator feed control valve downstream of the cross exchanger. This will minimize vaporization of corrosive gases in this ex changer. The control valve internals and piping down stream of the control valve should be 300-series stainless steel. Reflux water D H . TO protect the regenerator condensers from the corrosive effects of low pH water, a small amount RE GENERATOR LEAN, AMINE'

RICH, AM1NE?"

0-1 SPMflEAN ) * AM(NE

RELOCATE VALVE 7 i90°F JL"A*-7

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304 5TA1NLES5 STEEL -MAX. VELOCITY = 10 FT./SEC

• Block in the cooling water inlet and outlet valves (warm amine to a scrubber won't hurt for a few minutes). • Open the water drain valve on the exchanger. • When the exchanger is almost drained down, check the drain with pH paper. If it turns blue, the exchanger is leaking. Alternately, a low TDS result for lean amine shows that steam or condensate is entering the amine system. Verify that the conden sate make-up valve is closed. Then block in any cross connections between the amine system and sour water pump-out lines, etc. Next, block in t h e reclaimer vapor outlet and amine inlet. A leak in this exchanger will then manifest itself by the presence of amine in the channel head drain.

143

~n 0-10 GPM

DEHYDRATION LINE

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REMOVE ROW 5 OF TUBE

Figure 12—3 Retrofit tips to cut corrosion.

144 TRCXIBLESHOOTING NATURAL GAS PROCESSING

of amine entrainment is needed. The reflux water must have at least Vi% amine. To ensure this concentration, tie a 1-in. line from the lean amine pump to the inlet of the condenser. Incidentally, ammonia often accumulates in the reflux water and can be accidentally titrated as amine by the lab. This will not hurt anything. Reboilers. Remove tubes to form vertical or diagonal vapor passageways through the bundle. This reduces turbulent boiling in the shell. Retubing with 304 stainless tubes will reduce corrosion if the amine is low in chlorides. Regenerator internals. Replace all carbon steel trays and tray parts with 304 stainless steel. Use teflon gaskets. Remove all copper and copper alloy equipment from rich amine service. Amine dehydration. A steam or water leak into the sys tem will dilute the amine. Weak, rich amine becomes acidic and corrosive. To increase amine concentration, reflux water can be diverted to a closed drain. This will require piping the reflux water to a place where H 2 S can be safely flashed off. Do not drain this water to an open sewer; it is supersaturated with deadly H 2 S. This is one mistake nobody makes more than once.

COT REBOILER STEAM USAGE The principal energy requirement in a sulfur recovery complex is the amine regenerator reboiler steam. The operating engineer can significantly reduce energy usage through some simple field work. All he needs is a test kit to measure H 2 S and C 0 2 concentrations from 0.01 to 10% (Drager or equivalent): 1. Make a list of the scrubbers in the plant. Determine the per missible H 2 S concentration for sweet gas from each scrubber. 2. Multiply each scrubber's top pressure (psia) by its sweet gas H 2 S spec (ppm). Use the same calculation for liquid propane treaters. 3. Divide the value obtained above by a temperature correction factor use only between 75°F tol30°F): 4. The scrubber with the smallest SR factor is your critical oper ation. Let's call this the critical scrubber. 5. With your H 2 S test kit, measure the H 2 S concentration in the sweet gas from the critical scrubber. 6. Your regenerator reboiler duty should be controlled on the basis


145

of pounds of steam per gallon of lean amine circulated (lb/gas); proceed by cutting reboiler steam 0.1 lb/gal. Note: Scrubber sweet gas purity is controlled by the regenerator stripping steam rate, not by the amine circulation rate to the scrubber. 7. Repeat steps 5 and 6 until the H 2 S in the sweet gas from the critical scrubber reaches the maximum specification. 8. Using the test kit, measure the H 2 S and C 0 2 concentrations in the sour and sweet gas at each scrubber. Calculate the moles per hour of H 2 S and C 0 2 picked up by the amine. 9. Calculate the amine circulation required at each scrubber to btain 0.5 to 0.6 moles of acid gas (H 2 S + C0 2 ) per mole of amine circulated (See Table 12-1 for conversion factors). 10. Reduce the actual amine flow to each scrubber to the calculated value. The 0.5 to 0.6 molal ratio includes a reasonable safety factor. Don't forget to reduce the steam to the regenerator reboiler again, as per step 6. However, never reduce reboiler duty below the amount needed to maintain a minimum regenerator reflux rate. This is 10% of the reboiler (plus reclaimer) steam usage, in lb/hr. Correction factor = 1.5 x scrubber top temp. (°F) - 90 For example, for a fuel gas scrubber with a tower top pressure and temperature of 70 psig and 110°F: SR =

150

PPm x (70 psig + 14.7 _ (1.5 x 110°F) - 90

where SR

=

Scrubber rating factor

OTHER PROBLEMS Poor sweetening. If scrubbed fuel gas is off spec(high H 2 S), raise the regenerator reboiler steam. Check for excessive acid gas loading by calculation (as discussed before). If this doesn't help, check the cross exchanger for leaks. Brown amine. Exposure of amine (especially MEA) to oxygen will produce high concentrations of degraded amine. A strong ammonia odor and a browm tinge is the tip-off that the amine is exposed to an oxidizing agent. Check the inert gas or kerosene blanket on the lean amine storage tank.

16Q

146 TROUBLESHOOTING NATCJRAL GAS PROCESSING

AMINE REGENERATION AMD SCRUBBING

TABLE 12-1 CONVERSION FACTORS grains of H>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-


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


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.


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-


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.


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'


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.


• 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


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

165

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-

Ld £UJ 6?

o

QuJ Z O O Z

oo

v a. v

in

DIRECT REHEAT LINE 660°F-

usoc

/ T \ REHEAT \
-o«

c

*L—440°F

CO

a:

FIRST REACTOR

n SP

BOILER

uJcc

AIR

o ac-i o<

UJ

TO SECOND STAGE CONDENSER

3 ^ UJ z

(0

-a

a>

"a

u to

tn

U

370° F

1

ACID GAS SULFUR

Figure 13—5

Direct reheat bypass line increases capacity.

2>< UJlO

i


166 TROUBLESHOOTING NATORAL GAS PROCESSING

boiler temperature by 6°F. Because the reboiler tube metallurgy was carbon steel, this increased temperature was of concern in regard to decreased reboiler tube life. To avoid accelerated corrosion, a corro sion inhibitor was injected into the reboiler inlet line. As indicated by a corrosion probe, the inhibitor effectively controlled rates of cor rosion at the higher reboiler temperatures.

HYDROCARBON IN ACID GAS A single mole of propane will consume as much sulfur plant ca pacity as 10 moles of H 2 S. Propane dissolved or entrained in the amine regenerator feed will appear in the acid gas feed to the Claus train. To minimize the hydrocarbon content of the acid gas, the rich amine flash drum (i.e., the amine regenerator feed drum) was mod ified to operate at 10 psig instead of 50 psig. The resulting reduction in the hydrocarbon content of the acid gas was difficult to gauge be cause of its normal variability. The average reduction approximated 0.5 mole % which rep resented a 5% gain of sulfur recovery capacity.

years of use will note the crust deposited on the top of the reactor bed. This crust may account for a large portion of the pressure drop build-up seen as a run progresses. Figure 13—7 illustrates one method to mitigate this problem. Baskets, partially filled with catalyst support balls, are inserted in the Claus plant catalyst bed. The depth of the baskets are sufficient to double the exposed surface area at the top of the bed. While the effect on the initial reactor pressure drop is small, during the course of a 1 year run, the average reduction in pressure drop was esti mated to be 30%. The baskets shown in Figure 13-7 were only in stalled in the first reactor, as encrustation at the top of the second and third reactors is less of a problem. The loss in overall conversion of H 2 S to liquid sulfur due to the shorter average catalyst bed depth of the first reactor was too small to observe. Also, no shift in reactor temperature rise from the first to second reactors was observed. This too indicated that the shorter average reactor bed did not adversely affect conversion. The average 30% reduction in the first reactor pressure drop resulted in an ap proximate increase in Claus capacity of 2%.

IMBEDDED BASKETS REDUCE PRESSURE DROP

WATER VAPOR AND CARBON DIOXIDE Reducing the water vapor content of acid gas to a minimum also increased Claus capacity. During periods when one of the two sulfur trains was out of service, the amine regenerator reflux drum temperature was reduced from 135°F, to 110°F. This was achieved by spraying treated water on the exterior of the amine regenerators' overhead fin fan tube bundles. This reduced the water content of the acid gas from 10% to 5% and thus increased sulfur recovery capacity by 2%. By changing the feed location of the lean amine (MEA) to the gas scrubber, the rejection of C 0 2 to sweet fuel gas was increased from 5% to 60%. The C 0 2 content of the acid gas dropped from 12% to 6%. This resulted in an increase of 2% in overall sulfur plant capacity. The feed point change on the natural gas scrubber consisted of dropping the MEA inlet nozzle down from tray 20 to tray 5. Note that an even greater reduction of C 0 2 to sweet fuel gas may be achieved by substituting MDEA for MEA. 5

REACTOR INLET BASKETS Anyone who has ever inspected a Claus reactor after several

167

INLET

BASKET U

rm-t-nrm..

fccoeaoaal

BALLS pwfv«TTWMi"»yyiini

nmmsmmnm

~M OUTLET Figure 13—7 Imbedded baskets reduce pressure drop.



OTHER MODIFICATIONS A few other changes which supported the increases achieved above by increasing the process air pressure to the reaction furnace were: • The air blower check valve internals were modified to elimi nate a substantial pressure drop. • The air blower suction filters were altered to reduce pressure drop. • The automatic vent on the blower discharge was overhauled to prevent unintended leakage of process air.

169

that if you put out such a fire with water or nitrogen, the pyrophoric iron will reignite when it dries out and is again exposed to air. The nitrogen purge on the reactors also prevents the infiltration of air and moisture into the catalyst during a unit outage. Air, moisture, and sulfur make sulfuric acid, which causes catalyst deterioration and eats condenser tubes. A typical three stage claus train, showing a normal tempera ture and pressure profile, is illustrated in figure 13-8. Pressure drops or temperature differences, which vary widely from the parameters shown, are likely indicative of a process problem. STEAM REHEAT EXCHANGERS

Table 13-3 summarizes the net capacity gains achieved by the process modification detailed above. 4

PYROPHORIC IRON During a sulfur plant outage, quantities of S 0 2 may be ob served emanating from open manways. Also, a blue fire can some times be seen in cold process vessels and lines. Pyrophoric iron is the cause of these phenomenon. When dry, it spontaneously ignites after exposure to air. The heat evolved from pyrophoric iron combus tion in catalyst beds can lead to high reactor temperatures. Also, ir ritating S 0 2 vapors interfere with maintenance personnel working to repair the unit. A small nitrogen purge, connected to the top of each reactor, will effectively suppress pyrophoric iron fires. Remember, however, TABLE 13-3 COMTJLATIVE EFFECT OF MODIFICATIONS TO INCREASE CLAUS PLANT CAPACITY * 1. Oxygen Enrichment 2. Direct First Stage Reheat 3. Cascaded Seal Legs 4. Minimize Hydrocarbons in Acid Gas 5. Minimize Water Vapor Content of Acid Gas 6. Minimize C 0 2 Content of Acid Gas 7. Reactor Baskets

18% 5% 23% 5% 2% 2% 2% 171%*

*Items # 1 through # 7 were multiplied together to arrive at the cumulative effect.

777777" SULFUR CONDENSERS

AIR

SLOWER

Rgure 1 3 - 8 Typical temperature and pressure profile for a gas field sulfur recovery train processing acid gas with 85% of H2S through a Three State Claus Plant

170 TROUBLESHOOTING NATURAL GAS PROCESSIMG

REFERENCES 1. Kerr, E.K., "The Claus Process". Energy Processing/Canada, , July-August, 1976. 2. Hansen, T.S., "Oxygen/Resid Relationships in FCC Operations", 0 & GJ, August 15,1983. 3. Gray, M.R., "The Profitability of Oxygen Combustion Air Use In Claus Sulfur Plants", M. Eng. Thesis, University of Calgary, 1980. 4. Linde, Union Carbide, "Claus Plant Oxygen Enrichment", Technical Bulletin, 1983. 5. Daviet, G.R., et. al, "Switch to MDEA Raises Capacity", Hydro carbon Processing, March, 1979. 6. Fischer, H., "Sulfur Costs Vary With Process Selection", Hydro carbon Processing, March, 1979. 7. Fischer, H., "Here's How the Modified Claus Process Treats Low Sulfur Gas", O & G International, July, 1971. 8. Goar, B.G., et. al, "Claus Plant Capacity Boosted By OxygenEnrichment Process, O & GJ, September 30, 1985.

Section

Pipeline Problems

"Malfunctioning mechanical devices combine passive resistance with malicious obediance. You have to conquer them with your persistence. It's not a matter of luck; but a matter of pride." Norm Lieberman

HYDRATES

14 HYDRATES

173

water and light hydrocarbons) will form at temperatures well above the freezing point of water. Actually, freezing of the water produced at the wellhead is relatively unlikely because this water typically contains appreciable quantities of salt. Figure 14—2 summarizes the effect of an adibatic expansion of natural gas. Reducing the pressure of flowing gas across a restriction causes the gas to cool. It is this phenomeon that accounts for the tendency of gas lines that have be come partially plugged with hydrates, to maintain the pluggage after ambient conditions have returned to a relatively warm state.

MAIN UNE COMPRESSION

I first realized how serious a freeze-up in a natural gas field can be on a cold, cloudy morning in December, 1983. During the night, the temperature had dipped below 20°F, and our gas flow had fallen by 30%. By the time 1 had my first cup of coffee, the situation had become even more serious; one of our competitors was offering to buy gas from us at $2.00 per MSCF above our normal price. With an inducement such as this, our V.P. of Production did not hesitate to order our engineering staff into the field with instructions to re store the lost production. The freeze-up had effected many areas of our operation: • • • • •

Wellhead compression Separation of water, condensate and gas at the wells Gas collection (lateral) piping flow Dehydrator glycol losses Main line compressors

On this December morning, our most immediate problem was the inability of the operating crews to keep the pipeline booster com pressors on line. These gas turbine driven centrifugal compressors were mysteriously slowing down. Our investigation revealed t h a t the problem was low fuel gas pressure. Once the fuel gas control 6000

PSIG

As I investigated these various manifestations of hydrate for mation, I drew two general conclusions: • The "ice" plugs did not melt when the ambient temperatures rose above 32°F. • Once formed, an "ice" (really a hydrocarbon hydrate) plug would not melt, even when ambient temperatures had returned to normal. Figure 14-1 shows that solidified hydrates (a compound of Figure 14—2 172

Hydrate formation is favored by high pressure and molecular weight


HYDRATES 175

valve to the turbine was wide open, the turbine would begin to slow as the flow of fuel diminished. Figure 14r-3 depicts the fuel gas sys tem. Note t h a t the take-off for the gas turbine fuel was upstream of the dehydrator. The pressure let-down through the pressure re ducing "Big Joe" valve produced a temperature drop sufficient to bring the flowing gas below it's hydrate formation temperature. As shown in Figure 14—2, dropping gas pressure from 800 psig to the normal fuel gas pressure of 150 psig (which is preset by ad justing the threaded bolt on top of the "Big Joe" pressure regulator) theoretically reduces the gas temperature by 44°F. The fuel gas con sumed by the subject turbines had an eighteen molecular weight (i.e. a specific gravity relative to air at 0.62). As one can see from Figure 14-1, gas of this gravity will form hydrates at 36°F, assum ing entrained liquid water is present. Hence, one can calculate that if the gas temperature at the takeoff for the gas turbine fuel dropped below 80°F (i.e., 36°F + 44°F). solidified hydrates would form as the fuel gas passed through the "Big Joe" pressure regulator. Once the

I B to i—

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% O I -

*■

tflui,

(

o

a.

CO

3

UJ Q_

O

o o

J2 3

oo

I \Lw

In

m

1$

ao

30 40

so

JO

TO

TEMPERATURE Figure 14—2

eo

so

IOO

no izo

REOUCTION^F —

Joules - Thompson expansion cools flowing gas.

130

i4o

i:o

Q(J>

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CD

E

HYDRATES


flow of gas was restricted by the newly formed solids, hydrate for mation would be accelerated by the fuel gas pressure dropping below 150 psig. To thaw a line plugged with hydrates, it is best to depressure the line and apply an external source of heat to the "Big Joe" valve. The difficulty of implementing this suggestion is a consequence of the problems in depressuring that portion of the fuel gas line up stream of the "Big Joe" pressure regulator. If the "Big Joe" valve has plugged completely with hydrates, the high pressure gas be tween the fuel gas take-off and the "Big Joe" is trapped. With no flow through the line, this trapped fuel gas rapidly cools to ambient conditions. As the hydrate formation temperature of wet, eighteen molecular weight gas at 800 psig is only 58°F, hydrate crystals will quickly accumulate inside the fuel gas line when the ambient tem perature is hovering at a chilly 45°F. On our particular gas turbines, we noticed that thawing the "Big Joe" valves only restored gas flow for a few seconds. Upon dis assembling the "Big Joe" valves we found ice crystals solidly packed into the upstream side of the valve. Only by unbolting the flanged sections of the fuel gas line were we able to gradually depressure and eventually melt the accumulated hydrates. To avoid a reoccurance of this long and costly defrosting pro cedure we eliminated the problem at it's source. Hydrates will only form in the presence of free, liquid water. Gas dried to pipeline moisture specifications in a glycol dehydrator is not subject to hyd rate formation, except in the most frigid conditions. Hence, we sim ply relocated the fuel gas take-off to our gas turbines downstream of the glycol dehydrators. Of course, as oft times happens in gas pipelining, solving one problem created another. The new dry fuel gas source, while eliminating the low fuel gas pressure problems to our turbine driven compressors, was found to contain entrained glycol. To our dismay, this glycol mist fouled the firing mechanism (i.e. the "spark cells") on a reciprocating engine, which was served by the same fuel gas supply. We researched the problem, and discovered that our pre decessors at this compression station had located the fuel gas take off upstream of the glycol dehydrators to avoid this very problem. But that is another story.

GLYCOL LOSSES For the reasons just described it is vital to dry gas to pipeline specifications during the winter. Common carrier pipelines cannot be expected to accept wet natural gas which will form hydrates

177

when depressured in their customers equipment. Unfortunately, t h e glycol losses in our gas drying facilities had increased dramatically with the on-set of cold weather. Figure 14—3 shows that upstream of our glycol drying towers we had installed knock-out drums to re move entrained liquids (primarily natural gasoline condensate). If liquid hydrocarbons enter a glycol tower, they will mix with the circulating glycol and promote foaming on the tower's bubble cap trays. The foaming glycol is carried out the top of the dehyd ration tower along with the dried gas. When the glycol inventory in the circulating system falls below a minimum level the flow of dried glycol back to the tower becomes erratic. This results in inadequate drying of the natural gas. When we investigated the cause of our glycol losses, we found that the liquid level in the knock-out drum upstream of the largest glycol dehydrator tower, had risen to the gas inlet nozzle. When the condensate reached this level, it was re-entrained into the up-flow ing gas. The reason for the high liquid level was apparent; the liquid dump valve used to control this level was frozen. The condensate flashing from 800 psig down to 50 psig (i.e. the pressure of the low pressure separator) auto-refrigerated sufficiently to freeze the dump valve with hydrates. To eliminate this problem we installed a "flameless heater" around the dump valves on each knock-out drum. The flameless heater consists of a sheet metal box which is de signed to enclose a wide variety of valves. A small stream of natural gas is oxidized to produce a small amount of low level heat. A source of electricity (normally obtained from a twelve volt car battery) is needed to start the heater. This device is intrinsically safe in that it will not provide a source of ignition for natural gas. The installed cost of a typical flemeless heater is roughly $1,000.

GATHERING SYSTEM FROZEN With the situation at the dehydration and compression station under control, our engineering staff went into the gas fields to assist the production personnel in restoring the diminished gas flow. We found that many of our wells had developed a high wellhead pres sure, but that the metered gas flow had greatly been reduced. It was mostly the older wells that were effected in this manner, because the wellhead heaters had been removed from these wells as their pressure flow had diminished over the years. Once a pressure restriction starts in a pipeline due to the for mation of hydrates, the resulting pressure drop promotes the forma tion of further solid hydrates due to the self-cooling of the expanding

HYDRATES 179


gas (i.e. the Joule-Thompson expansion). In this way a pluggage in a gathering system pipeline can sustain itself, even when ambient temperatures moderate. The best way to melt out hydrates from un derground piping is by injecting methanol into the gas flowing from a well. A few pints of methanol per million SCF of gas should melt hydrates out of a restricted pipeline. Of course, if the methanol had been injected prior to the freeze-up, the pipeline could have been prevented from plugging in the first place. Methanol is injected from barrels with a small chemical injec tion pump. The pump is powered with high pressure natural gas. The required rate of methanol injection varies with the free water content of the flowing gas. Methanol costs only about a dollar per gallon and is certainly the cost effective method to prevent freezeups in a variety of natural gas operations.

WELLHEAD COMPRESSION In our particular gathering system, about 20% of the produc tion originated in wells equipped with reciprocating wellhead com pressors. Driving through the gas fields, we found 50% of these com pressors had been knocked off-line. Several of the compressors had been tripped-off due to high liquid levels in the compressor suction drum. The majority of the idled machines were found to be inoper able due to plugged fuel gas lines, as evidenced by the low pressure in the fuel gas knock-out drum. The problem with the small, wellhead reciprocating compres sors paralled the difficulties we had just resolved with our main line turbine driven compressors. That is, hydrates had formed in the "Big Joe" fuel gas pressure regulator. Figure 14—4 shows the fuel gas piping. Note that the gas field operators had lined-up the com pressor fuel gas from the discharge, rather than the compressor's suction. Their idea was to use the relatively warm compressor dis charge flow as a source of compressor fuel gas. Unfortunately, they failed to realize that 1000 psig, 90°F gas would be more likely to form hydrates than 200 psig, 70°F gas (i.e. the conditions at the compressor suction). Referring to Figure 14^-2, we can see t h a t gas from the compressor discharge would cool-off by 55°F more than the lower pressure gas from the compressor suction. This meant that the cooler gas from the suction of the compressor would actually be warmer after being reduced to the 5 psig fuel gas pressure, t h a n fuel gas diverted from the compressor discharge. To avoid future freeze-ups which could ocur even when low pressure gas was used as compressor fuel a portion of the engine exhaust gas was piped-up to flow over and warm the "Big Joe" pres-

sure reducing valve. This succesful modification is also shown in Figure 14—4.

WELLHEAD VAPOR-LIQCIID SEPARATION The gas supply to the liquid level dumps on the wellhead high pressure separator is normally saturated, high pressure gas, unless a glycol dehydrator is conviently located to provide a source of dry gas. If the gas supply to these dump valves is stopped, the valves will not operate, and liquid may carry-over from the high pressure separator to downstream equipment such as wellhead compressors. For this reason, the instrument gas supply and signal transmission lines should be self draining and short. Also, the instrument gas should pass through a small liquid K.O. bottle. Pocketed instrument gas lines seemed to account for the majority of liquid dump failures on high pressure separators during cold weather. WELLHEAD GAS 200^70°F

R

10'

(COMPRESSOR

ENGINE

\

IT

FUEL GAS K.O. DRUM ■

1000 90°F

-

■

«

^

F

ROZEN 8IG JOE'

#

—DOOPEN

GAS TO PIPELINE

Figure 14—4

1X3 CLOSED

Avoid using high pressure gas as compressor fuel during cold weather.

PRODUCTION METERING

15 PRODUCTION METERING

Natural gas flow at the wellhead is metered for the purpose of determining tax and royalty payments, to observe state regulations as to the amount of gas that may legally be produced from indi vidual wells, and to permit the lease operator to plan the well's op eration intelligently. The meter consists of an orifice plate with pressure sensing taps both upstream and downstream of the orifice plate. The plate itself may be changed without interrupting gas flow. The meter "run" (i.e. the straight lengths of pipe upstream and downstream of the orifice plate) is sized to minimize the effect of el bows and other fittings on the measured flow. The orifice pressure taps and flanges, the devise permitting the orifice to be changed onstream, and the meter run piping spool pieces are purchased as a unit. The meter usually reads zero to 100 inches of water. This means that the hole in the orifice plate is sized to obtain a pressure drop of about 3 psi (28 inches of water equals 1 psi) at the maximum anticipated gas rate. Each meter run will be limited to a maximum size orifice which corresponds to the maximum gas rate which may be measured with the meter run. It is possible to change the range spring on the meter from 100 to 200 inches of water. This permits an increase in measured flow of 41.4% (i.e., V 200/100 ). PULSATION EFFECTS It would really seem that anything as simple as an orifice meter could not require any real fortitude or intelligence to troubleshoot. That is why I was surprised to find myself assigned to de termine why a wellhead meter was recording a flow of 1100 M ISO

181

SCFD while a custody transfer meter on the same gas was measur ing only 380 M SCFD. Both meters had been carefully zeroed and calibrated, and found to be in good working order. The only differ ence between the meters was t h a t the meter showing the higher flow was located between the well's high pressure separator and a small, slow speed (360 rpm) wellhead reciprocating compressor. The meter recording the low flow was a mile downstream at the custody transfer point. Now it is not unknown for gas to be stolen by tapping into an underground collection lateral. Leaking lines are also a pos sibility. However, in this case I quickly summarized that neither of these mischances were appropriate. By making the following obser vations on the wellhead reciprocating compressor: • • • • •

Suction and discharge pressure. Suction temperature. Head end clearance pocket adjustment. Cylinder valve configuration. Engine speed.

I was able to calculate the maximum amount of gas that the compressor could be moving. This calculated flow was 450 M SCFD. As it was impossible for this particular compressor to move more than 450 M SCFD, the measured flow of 1100 M SCFD was wrong! It is possible—actually quite probable—for meters located im mediately upstream or downstream of sources of pulsations (such as reciprocating compressors) to read high. Depending on how much the pulsation is attenuated, this phenomenon can introduce very large errors into the metered flow, to determine if pulsations are contributing to a high meter reading pinch back on the valve nearest the meter run enough to introduce a pressure drop of five to ten psi. If a meter is reading high due to a pulsation problem, this pressure drop will be sufficient to dampen out the pulsations so that a correct gas flow can be recorded. When I followed this procedure for the meter I was trouble shooting, the indicated flow dropped to 410 M SCFD. Taking into ac count that 20 M SCFD of metered gas was being consumed for fuel for the wellhead reciprocating compressor, the recorded flow for the custody transfer meter and t h e wellhead meter were brought into close agreement. An orifice plate sized to create a ten psi pressure drop (i.e. 300 inches of water) was placed in line near the wellhead meter a few days later and the gate valve, which had been partially closed, was returned to its normal wide open position.


OVER PAYMENTS DOE TO METERING ERRORS As wellhead meters are the basis for royalty production pay* ments to landowners and to States for severance taxes, over-pay ments due to erroneous metering can add up to a big dollar revenue loss for the lease operator. For example, I observed a well that was recording 320 M SCFD gas flow. The small wellhead reciprocating compressor induced a pulsation that resulted in a high meter read ing. When I attenuated the metered flow with an orifice plate to dampen the pulsations, the recorded flow dropped to 240 M SCFD. As taxes and royalty payments for this well totaled 25%, the lease operator's daily over payments (based on $3.00 per M SCFD gas) was $60.00 per day. As the compressor had been sitting at this par ticular site for approximately three years, I estimated that this pul sation induced metering error had cost the lease operator $60,000! Relatively minor piping pulsations can lead to very large errors in gas metering when the tubing lines connecting the orifice meter taps and the flow recorder have not been properly installed. The re sulting aberation can cause the meter to read 50% or more above the actual gas flow. To avoid this difficulty, when the possibility of pulsations are anticipated in a meter run, the tubing lines should be coiled. This means t h a t 1/4" stainless steel tubing connecting the flow recorder to the orifice meter taps should be installed with half a dozen six to eight inch loops. This coiling will attenuate the pressure pulsa tion effect on the tubing connections themselves, but will not elimi nate the erronous high readings associated with the orifice plate it self. WELLHEAD COMPRESSORS AND METERS To avoid this type of debit, it is a good idea to calculate the theoretical gas flow expected from wellhead compressors by the manufacturers curves. If the compressor's cylinder valves are in good condition, the calculated flow should be 5% to 10% greater than the metered flow. If the metered flow is greater than the flow cal culated from the compressor characteristics, the installation of a pul sation damper and the recalibration of the meter are positively in order. Locating meter runs too close to elbows or piping reducers also can distort recorded flows. A run of straight pipe both upstream and downstream of a n orifice is required to minimize this distortion. Figure 15-1 quantifies those lengths. The "Beta" values shown on the horizontal axis are the ratio of the orifice diameter to the pipe inside diameter. One can correctly conclude from this figure that a piping configuration t h a t provides satisfactory metering with a

PRODUCTION METERING

183

small orifice, may be quite inadequate when a larger orifice is in stalled to accomodate greater natural gas flows. ERRODED AND PLUGGED ORIFICES I once encountered a meter on a new installation t h a t was reading an inordinately high gas flow. The meter was zeroed and re calibrated, but the recorded flow remained high. Finally, the orifice plate was pulled for inspection and a small pebble was found par tially plugging the orifice. The pressure drop created by this pebble

BETA RATIO = ORIFICE DIAMETER DIVIDED BY PIPE DIAMETER L = MINIMUN LENGTHS OF STRAIGHT PIPE REQUIRED EXPRESSED IN PIPE DIAMETERS

...

B .1

^ ^

ORIFICE

.2 Figure 15—1

.3 A .5 BETA RATIO

Correlations to size meter runs.

.6

.7


was interpreted by the meter as a high gas flow. Erosion of an orifice plate with sand also results in erroneous measurements of gas flow. In this case, the pressure drop through the orifice is reduced and the recorded gas flow is lower than the actual gas flow. Of course, this type of situation artifically reduces the lease operator's royalty and tax payments below what they should be.

PRODUCTION METERING

example, the gas flow through a choke with an upstream pressure of 1000 psig is nearly the same whether the pressure in the high pressure separator is 300 psig or 10 psig. The reason for this phenomenon is that the gas reaches a critical or sonic velocity through the choke. This concept can be used to check an orifice meter to determine if it is reading a substantially incorrect flow: Q =

GAS FIELD BALANCES The operator of one large producing district was concerned that metered gas sales at custody transfer points could not be reconciled with the daily wellhead production figures reported by operating personnel. An investigation revealed the following: • Calculations used to determine daily wellhead gas flows did not include correction factors for temperature or compressibility. • Fuel gas used to run wellhead compressors was withdrawn downstream of the wellhead meters and thus was reported as produced gas even though this gas never left the well site. • A standard specific gravity of 0.65 was being used in wellhead gas flow calculations; while actual specific gravity measure ments indicated a 0.62 gravity. • Fuel gas usage to outlying compressor booster stations were being estimated rather t h a n measured; the estimated values were consistently too low. Brine or condensate, which is entrained out of the high pres sure separator and carries through the meter run, will result in an erroneously high measurement of gas flow. For instance, a well was subjected to a vigorous "soap stick" program. (Soap sticking is a pro cedure to promote the emulsification of fluids in the downhole tub ing string). The resulting emulsion carried over through the meter run and created the impression of a substantial enhancement in gas production as a result of the soap stick program. In reality, the in cremented flow of gas was quite modest. MEASURING GAS FLOW WITH A CHOKE NIPPLE Bernoulli's equation, which we all learned in high school, tells us that pressure drop is proportional to flow squared. However, for compressible fluids, this relationship does not hold when substantial changes in pressure are involved. In particular, when the wellhead pressure is at least double the pressure downstream of the choke, the flow of gas through the choke is linearly proportional to the wellhead pressure only—regardless of the downstream pressure. For

185

£-»P V SG • T • Z

where Q C P T SG Z

= = = = = =

Gas flow, M SCFD Choke Nipple Coefficient Wellhead, Pressure, psig Temperature, °F Specific Gravity of gas relative to air. Gas compressibility

Table 15—1 lists choke nipple coefficients for several typical choke sizes. Table 15—2 is a summary of calculated flows through choke nipples. As can be seen whether the ratio of the upstream wellhead pressure to the downstream pressure is ten to one or two to one, the flow through the choke is almost the same. However, as shown in Table 15—3, once this pressure ratio drops below two to one, the flow through a choke nipple is substantially reduced. Using TABLE 15-1 COEFFICIENTS FOR CHOKE NIPPLES ASSUMING CRITICAL FLOW Choke Size

Choke Nipple Coefficient

1/8" 5/32" 3/16" 1/4" 9/32" 5/16" 11/32" 13/32" 7/16" 1/2" 3/4"

.347 .553 .802 1.470 1.885 2.340 2.866 4.063 4.730 6.260 14.490


PRODUCTION METERING

the type of information supplied in Table 15—3, it is possible to es timate the flow from a gas well with reasonable certainty at pres sure ratios down to 1.3. Using data developed for non-critical flows through choke nipples (as shown in Table 15-3) can be a handy way to check orifice meters, even when the lateral collection header pres sure is within a few hundred psi of the wellhead pressure.

REFERENCES 1. "Measuring Variable Gas Flow in a Rapidly Changing Market' : Gas Industries, February 1985, page 16-18.

VARIABLE FLOWS AT CUSTODY TRANSFER POINTS Metering highly fluctuating flows at custody transfer points may not be a practical proposition with a single meter run unless the orifice plates are changed frequently. To achieve accurate nat ural gas metering under such conditions, a turbine meter, rather than an orifice meter is required. The Rockwell Auto Adjust Turbo Meter 1 has been reported to have been successfully applied in one installation to measure flow varying between 10 MM SCFD to 240 MM SCFD at a custody transfer point. TABLE 15-2 CHOKE NIPPLE CAPACITIES FOR CRITICAL FLOWS (M SCFD) Upstream Downstream Pressiirp Prpssurp 1000 1000 1100 1100 1200 1200

100 600 100 600 100 600

3/32 in

Choke Diameter fi/32in 9/32 in

240 235 264 263 299 288

816 797 895 885 980 980

1900 1860 2090 2080 2280 2280

TABLE 15-3 CHOKE NIPPLE CAPACITIES FOR NON-CRITICAL FLOWS (M SCFD) Upstream Downstream Prpssnrp PrpssnrR 1000 1000 1100 1100 1200 1200

600 800 600 800 600 800

3/32 in 235 192 263 235 288 272

Choke Diameter fi/32in 9/32 in 797 649 885 800 980 920

1860 1520 2080 1860 2280 2150

187

60984]i81800

PIPING PULSATIONS

16

a HZ

I 89

=

Speed of sound, ft./sec. (typically 1400 ft./sec. in natural gas pipelines) — Hertz (i.e. compressor speed in revolutions per second)

To calculate the speed of sound:

PIPING PULSATIONS

a = where K Z T SG

The vibrations set-up by reciprocating compressors in natural gas pipeline service can be a severe and complex subject. The effects on gas flow metering and compressor efficiency have been discussed in previous chapters. The effects of the vibrations induced by recip rocating compressors are controlled by proper compressor suction and discharge piping design and by the use of acoustical filters (i.e. pulsation dampening bottles). The information presented in this chapter should be viewed as an introduction to a subject that is a "Science Unto Itself.

PIPING PULSATION The development of a resonant frequency in the suction or dis charge piping of a reciprocating compressor is called pulsation. One of the common detrimental effects of pulsation is t h a t isolating or by-pass valves may begin to leak due to the alternating force of the pulsation. A valve in a closed position, located within a few hundred feet of a reciprocating compressor, making a continuous rattling sound, is being subjected to pulsation induced by the compressor. To correct this problem, you will need to either shorten or lengthen the isolated piping run "L". First, calculate the value of "L" as follows: L =—a— 4»HZ where L

=

Resonant piping length, ft. 188

41.5 V K « Z » T SG

= = = =

Ratio of specific heats, Cp/Cv Compressibility factor Temperature, °F Specific gravity relative to air

All multiples of "L" will develop resonant frequencies; the first resonant frequency being the strongest and hence the most destruc tive. To reduce the piping pulsation, you should modify the deadended or isolated piping length so that it is much shorter or much longer than a multiple of the resonant piping length. For more complex piping pulsation problems, contact Southwest Research Institute with offices in San Antonio, Texas. An analog computer simulation of a piping system may be required to deter mine the cause and cure of pulsations. Often, the installation of damping orifice plates or pulsation bottles will be required toeliminate a resonant frequency. Southwest Research can make these de terminations. For a comprehensive treatment of this subject, consult the listed references. 1,a RUNNING COMPRESSORS IN PARALLEL There are three general types of compressors used in the gas fields: • Slow speed reciprocating (less than 400 rpm). • High speed reciprocating (900-1000 rpm). • Centrifugal. I have seen severe piping pulsations introduced into a formerly stable system by retrofitting a slow speed reciprocating machine to operate in parallel with several high speed reciprocating compres sors. Also, I have been told that it is difficult to add a centrifugal compressor to operate in parallel with reciprocating machines with-


PIPING PULSATIONS

out having the performance of the centrifugal machine adversely ef fected by the reciprocating compressors. Locating reciprocating and centrifugal compressors in series is no problem, provided that suf ficient intervening pulsation dampening is provided. A glycol dehydration tower makes an excellent pulsation dampener. At one station that exhibited severe piping pulsation at a compressor discharge meter run, relocating trhe compressor up stream of the dehydration column eliminated the problem. The Gas Processors Suppliers Association Engineering Data Book 3 has a section for the sizing of pulsation dampening bottles. Alternately, just like any other piece of process equipment, pulsation bottles can be purchased from a variety of vendors. Basically the pulsation dampener (or acoustical filter) consists of a device with the characteristics shown in Figure 16—1. Flow of the gas through the choke shown in this figure dampens the pulsa tions set up by the reciprocating compressor. The diamensions of the choke and the pulsation bottle shown in Figure 16-1 can best be cal culated from correlations in the literature. 2 However, as an approx imation, the following is a good rule of thumb: • The volume of the suction pulsation dampener bottle equals twelve times the compressor cylinder head end volume of one cylinder (same whether one or several cylinders are in use). The length of the bottle equals twice the diameter. • The volume of the discharge bottle equals sixteen times the swept head end volume. The length of each bottle is four times the diameter. • The allowable pressure drop for the choke should be set at 1/2% of the compressor discharge pressure or 1% of the compressor suction pressure, whichever is less. • The choke length should be one-half the length of the bottle, while the internal separation baffle shown in Figure 16-1 is located at the bottle's midpoint.

r

INLET

CHOKE--*'

t r

OUTLET

Figure 16—1 A pulsation dampener bottle for the discharge of a recipro cating compressor. Relative dimensions shown are typical.

191

The above criteria completely defines the dimensions of a pul sation dampener bottle. However, it is best to design thihs bottle fol lowing the more rigorous correlations available in the literature cited above. Of course, as discussed in the chapter on metering, pulsation dampening can blso be accomplished with an orifice plate. However, this does not seem to be as effective as an acoustical filter bottle, and the orifice plate also requires more pressure drop. REFERENCES 1. Controlling the Effect of Pulsations and Fluid Transients in In dustrial Plants, Published by Southwest Research, San Antonio Texas. 2. Barta, M.L., T.P. Bass. "Gas Piping Design For High Speed Reciprocating Compressor Units", Journal of Engineering for Industry, November 1971, Pages 1183-1189. 3. Gas Process Suppliers Engineering Data Book, 9th edition. Page 4-17.

CORROSION & FOOLING

17 CORROSION & FOOLING

Ortega scrapped the black viscous material from the cen trifugal compressor's inlet guide vanes and said, 'This is ". I'm not thrilled to be here either, Ortega—but let's not resort to profanity". "But no; really Mr. Lieberman", protested Ortega, "This is re ally excrement. It is the accumulated waste from the biological ac tivity of sulfate reducing bacteria. These bacteria metabolize iron in the presence of moisture and sulfates. They are a primal life-form. Most likely though, they will outlast us". "Where does the iron come from", I inquired. "Unfortunately, the bacteria have a rather substantial supply of iron to consume", responded Ortega. "They are eating our natural gas collection piping system. These fouling deposits that we now see, t h a t have reduced the capacity and efficiency of our pipeline booster compressor, are also indicative of corrosion in our gas field lateral piping system. Of course, not all this material is biological waste products. Much of it is probably sodium chloride, with calcium and potassium chloride salts also present. In addition, I am quite sure we will find a significant percentage of organics in this deposit. These organics often originate in the pipeline as corrosion inhibitors which are injected at the wellhead to reduce downstream corrosion by coating the pipeline interior with a protective coating. Careful selection of a corrosion inhibitor t h a t is consistant with the temper ature, pressure and composition of the gas gathering system will minimize downstream fouling. Also, proper inhibitor addition rate and dispersion will help. "Some of the deposit also consists of "paraffin wax". This wax 192

193

precipitates out of natural gas when it is compressed; possibly due to the heat of compression. That is why there is a lot more paraffin wax on the discharge side of the compressor opposed to the suction". "It would be nice if we could poison the bacteria", I interjected. "Actually, this is quite a common practice", responded Ortega. "An aldehyde type microbiocide can be used both to reduce corrosion and downstream fouling. To control the rate of fouling deposit ac cumulation on the compressor's internals due to organic deposits, an organic solvent should be injected at a rate of several pints per mil lion SCF of gas. Chemlink, Nalco, and Betz market such solvents with a typical price being $6 per gallon. However, many petroleum refineries produce highly aromatic solvents as a by-product of the naphtha reforming process. The solvents, which boil in the range of 450-500°F, sell for slightly more than gasoline and, at least in my experience, are equally as effective as the high priced name brand organic solvents".

MONITORING INTERNAL CORROSION A corrosion probe is a device for inserting a thin strip of metal through a 3/4" bleeder into a pipeline. The metal strip is called a corrosion coupon. The probe is designed to permit the coupon to be inserted and removed under full pipeline pressure. The coupon is weighted prior to installation and then periodically thereafter. Weight loss of the cleaned coupon is then correlated with the cor rosion rate on the pipeline (in mils per year). The key to the suc cessful application of this program is routinely weighing of the coupon. Checking the coupon after leaks have developed in the gas collection piping system is not especially informative. Once natural gas has been sweetened and dehydrated with triethylene glycol, it is no longer corrosive and internal pipeline cor rosion is no longer a danger. External corrosion of a pipeline, due to moisture and minerals in the soil continues to be a hazard. To protect underground pipelines, piping is wrapped with a thick plas tic coating which is impervious to moisture.

EXTERNAL PIPEUNE CORROSION The external coating protecting a pipeline is subject to deterio ration. When this happens, the pipeline is exposed to the corrosive effects of soil and water. To control this corrosion, cathodic protec tion is normally required. Both economic and safety factors, require that the corrosion rate be slowed or mitigated to extend the lifetime of pipelines.

GLOSSARY


Cathodic protection is a corrosion mitigation method that can effectively stop corrosion on buried pipelines. It involves the instal lation of grounding devices called "anodes" in the soil near the pipeline to be protected. These anodes pass DC current onto the pipe surfaces to neutralize the natural currents that cause corrosion. There are two types of cathodic protection systems. A galvanic cathodic protection system involves anodes that are more electrochemically active than steel. The anode materials used are mag nesium, aluminum, or zinc. No external power is required. An im pressed current cathodic protection system involves anodes made of special cast iron, graphite or platinum. An external source of DC power is required. The most commonly used power source is a rectifier which converts AC to DC. The anodes are also electrically connected to the structure in these systems to complete the electrical circuit. Cathodic protection is an effective corrosion mitigation system. However, a number of things can cause a cathodic protection system to malfunction. It is critical to detect and correct these failures be fore corrosion can occur on the pipeline. Electrical surveys are the most commonly used tool to detect these failures.

PIPE-TO-SOIL POTENTIAL The structure-to-environment potential is called the pipe-to-soil potential (P/S potential) when measured on a pipe in soil. This mea surement indicates the tendency for corrosion of a metal in a given environment. A change in pipe-to-soil potential is used to estimate the effectiveness of cathodic protection on cathodically protected sys tems. The measurement of pipe-to-soil potential requires little equip ment and is quick and relatively simple. A high resistance voltmeter is used on the DC scales. The structure of interest is electrically con nected to the ( + ) terminal of a digital voltmeter. A device called a reference electrode is connected to the (-) terminal of the meter. The reference cell is placed in the soil. The cell should be placed as close as possible to the point of interest. The reference electrode generates a constant corrosion potential against which the variable structure potential can be measured. Copper in a saturated solution of copper sulfate is the most common reference electrode. The voltage measured is called the "P/S Poten tial vs. the Saturated Copper/Copper Sulfate Reference". A Silver/ Silver Chloride cell is normally used in brackish or salty environ ments.

A Absorber A trayed or packed column used to recover light components (H2S, propane) from natural gas. Adjustable Choke Used to regulate the flow of gas from moderate pres sure weils. Afterbum Combustion of unbumt hydrocarbons in the exhaust gas man ifold of a reciprocating engine. Amine Solution Used to remove H2S and C 0 2 from sour gas. Annulus The space between the tubing and casing. Anode A grounding device used in the cathodic protection of buried pipelines. Anti-Surge The control system used to prevent surge in a centrifugal compressor. Attenuate Reduce the effects of pipeline pulsation.

B Beta Scan A picture of the internal cylinder pressure VS. volume displayed on an oscillascope for a reciprocating compressor. Big Joe A pressure reduction valve commonly used in the gas fields. BMEP Gauge A device used in troubleshooting engines. Booster Station Compressor station located along a gas pipeline to boost the pressure of the flowing gas. Button Hole A small hole made in the tubing which permits gas from the tube side to flow up the casing. Bottom Hole Pressure The pressure in the wellbore at the level of the per forations. Brine Water produced from the wellbore. Bundle The heat transfer device used in air coolers.

c Carbon Black The effect of burning light hydrocarbons with insufficient air. Carnot Cycle The ideal pressure-volume work cycle for compression. Casing The pipe which is cemented in place, which isolates the wellbore from the surrounding earth. Cathodic Protection An electrical method used to protect pipelines from external corrosion. Choke A restriction used to control gas flow at the wellhead. Choke Nipple The interchangable part of a fixed choke used to adjust gas flow. Claus Plant Used to recover elemental sulfur from H 2 S. 195

GLOSSARY 197


Coil Tubing CInit A devise used to wash sand out of a well using nitrogen and water. Common Carrier Pipeline Gas entering this pipeline must meet standard specifications for temperature, moisture and BTCI content CompressiabQHy The deviation of an actual gas from an ideal gas. Compression Ratio The absolute discharge pressure divided by the ab solute suction pressure. Condensate Light liquid hydrocarbon co-produced with natural gas. Coning Water flow to the perforations from another level. Contactor The trayed tower used in glycol drying of gas. Conversion In sulfur recovery, the percent of H2S converted to elemental sulfur and water. Copper Sulfate Reference Used in monitoring external pipeline corrosion rates. Corrosion Probe Used to monitor rates of corrosion in pipelines. Coupon Metal strip used in a corrosion probe. Crank End The inside end of a reciprocating compressor. Custody Transfer The point in a pipeline system where the title to the flowing gas changes from seller to buyer. Cylinder Clearance Valve A device attached to the head end of a recip rocating compressor to reduce the load on the engine. Cylinder Exhaust Temperature A measure of the ioad efficiency for a re ciprocating engine.

D Dampening Bottle Pulsation bottle installed on the discharge and suction of reciprocating compressors. Delta P The pressure drop between two points. Dehydration Drying gas to meet pipeline moisture specifications usually seven pounds of water per MMSCF of gas. Double Acting The characteristic of a cylinder that permits it to compress gas when the piston moves in either direction. Downcomer Downflow area for liquid from a distillation tray. Drilling Mud A high density fluid pumped into a well to prevent gas from flowing out of the well during drilling. Dual Completion Wells Gas is produced from both the tubing and casing sides of the annulus. Dump Valve A pnematically operated valve which opens or closes com pletely to control a liquid level in a vessel.

E Emulsification Promoting the mixing of gas, condensate and brine to form a fluid of reduced density. Entrainment Velodly The velocity of gas flowing through the tubing necessary to unload liquids from the tubing string.

F Filter Coalescer Used to remove solids and liquids from flowing gas. Fixed Choke A choke to which no adjustment is possible. Flameless Heater Generates low temperature heat by oxidizing natural gas at a temperature too low to cause an explosion of leaking gas. Flaring Venting gas from a well directly to the atmosphere to clear sand or liquid from the tubing string. Flooding When liquid cannot drain down freely in a trayed column. Flowing Back Venting a well to the atmosphere or through a sand trap to clear a newly completed well of sand and drilling mud. Flowing Tube Pressure The pressure at the wellhead when gas is being produced. Flowpoint A gas flow rate corresponding to the entrainment velocity. Flash Gas High BTU content gas vented from the low pressure separat ing. Formation Sand The sand which appears in the high pressure separator at the wellhead which has originated in the gas bearing sands. Frac Sand A special type of sand pumped into a well to stimulate pro duction.

G Galvanic Protection A form of cathodic protection of pipelines. Gas Turbine A jet engine type of compressor drive. Gas Driven Giycol Pump A pump used to circulate glycol in remote lo cations. Gas Lift Using a well's gas flow to unload liquid. Gas Turbine A jet engine type of compressor drive. Gauger A gas field worker who checks the operation of wells. GPSA Handbook Standard reference book for natural gas processing. Glycol Degradation The result of overheating glycol. Glycol Dehydrator Used to dry gas.

H HD-5 LPG The common propane used commercially. Head-End The outside end of a reciprocating compressor. Hydrate Plug A pipeline which is frozen solid with hydrates. Hydrates Solidified hydrocarbon and water mixture.

I Impeller A wheel on the rotor of a centrifugal compressor. Inert Gas Does not support combustion, i.e. Nitrogen. Inhibitor A chemical used to control corrosion rates. Interface The common level between brine and condensate. Intermitter A devise used to unload liquid from gas wells by automatically stopping and starting gas flow.

1 9 8 TROUBLESHOOTING NATURAL GAS PROCESSING

J Jet Ejector A method of compressing gas without moving parts. Jet Hood Excessive entrainment between tray decks in a distillation col umn.

K Kettle A type of reboiler used in distillation service. Killing a Well Pumping water into a partially depleted well to stop gas flow. Knock Out Drum A small vessel placed ahead of a compressor to re move entrained liquids. L Labyrinth Seal An internal component of a centrifugal compressor. Lateral Piping Small diameter pipe used to collect gas from scattered wells.

Lease Operator Entity responsible for operation and meeting of a gas well

Liquid Flood Downcomer back-up on a trayed distillation column. Little Joe A small pressure reduction valve. Loading Excessive accumulation of liquid in the tubing. Lubricator The fixture through which a wire line is run down into a well.

M Mandrel A gas lift system. Master Valve The upstream valve on a wellhead tree. Meterman A gas field worker who changes the charts once a week on wellhead orifice meters. Meter Run The length of straight pipe required on either side of an orifice meter. Microbiocide Used to control the growth of iron consuming bacteria living in pipelines. Multipoint Test A series of readings of wellhead pressure, upstream of the choke, at various gas flows.

N Matural Gasoline Condensate recovered from natural gas. NGL Natural gas liquids—that is, ethane, propane and butane. Normalize Data Compile the data in a form for comparison against a base period. NOX Nitrious oxide emissions. Nutblasting A common technique to clean a centrifugal compressor rotor.

o Orifice Meter The usual device used to measure gas flow on individual well.

GLOSSARY 199

Orifice Plate A specially drilled plate used to measure gas flow. Otto Cycle The ideal cycle taking place in a power cylinder of an internal combustion engine.

P Packed Pipeline Pressure drop through the pipeline has become excessive due to excessive gas flow rates. Packer A devise that isolates the tubing from the casing, placed just above the perforations. Packing Rings dumped into a distillation tower to promote fractionation. Paraffin A waxy, greasy substance deposited by natural gas. Partial Depletion A well that has lost most of its wellhead pressure but still has significant amounts of gas left to recover. Pass Partition Baffle Used in air coolers to redirect the gas flow. Peak Pressure The maximum pressure generated in a power cylinder im mediately after ignition. Perforations Openings in the bottom of the casing through which gas en ters the wellbore. Permeability The property of a gas bearing sand formation that deter mines the rate at which gas can flow out of the reservior into the weilbore. Pipe-To-SoQ Potential A measure of the external corrosion tendance of a buried pipeline. Plunger Lift A method used to unload gas wells of liquid. Porosity The property of a gas bearing sand formation that determines the volume of gas stored in the reservoir. Pulsation Fluctuation in pressure and flow in a gas pipeline. Pyrophoric Iron A form of corrosion product which ignites at ambient temperatures when dry and exposed to air. Precoat Filter A renewable type of filter used to remove particulates from a circulating amine solution. Pyrometer An instrument used to measure temperature.

R Radiation Scan Used to detect flooding on trays in a distillation column. Reaction Furnace The first vessel in a Ciaus Plant, also called a Thermal Reactor. Reboiler Used to drive moisture from the circulating giycol. Reclaimer Used in MEA circulation systems. Recomplerjon A general term used, for example, in describing reperforating a well at a higher level. Regenerator Strips C 0 2 & H2S out of the circulating amine. Reservoir The pressure of the gas in the sand formation in an area away from the wellbore. Resonant Frequency The natural frequency of a pipeline. Pulsations at this frequency can increase in amplitude.

2 0 0 TROUBLESHOOTING NATURAL GAS PROCESSING

Rod Load A mechanical limit on a reciprocating compressor. Rotating Assembly A centrifugal machine's rotor. Royalty The percent of gross receipts paid on a well to the owner of the field's mineral rights. Rat Hole The space in the wellbore below the perforations.

s Sand Bridge A blockage of sand in the tubing above the perforations. Separator Separates water, condensate and gas into three streams. Severance Tax A state tax paid on the production of gas and liquids. InTexas, 7%. Scrubber A trayed or packed column used to remove H2S or CO2 from natural gas. Seal Leg Used on Claus plants to drain sulfur from the condensers. Sheave A pulley used on an air cooler. Shut-In Pressure The pressure at the wellhead when no gas is flowing. Soap Stick A stick dropped into a well used to promote liquid unloading. Sour Containing H2S or C0 2 . Specific Gravity The molecular weight of gas divided by 29. Squeeze Job Forcing additional cement around the previously cemented in casing. Stripper A regenerator. Super Charger Same as a Turbo Charger, except it is driven directly by the engine and not by hot exhaust gas. Surge An abnormal and dangerous operating mode of a centrifugal com pressor. Split-Shaft A common feature of gas field turbine driven centrifugal com pressor. Swabbing Remove fluids from the tubing string by a mechanical method. Sweet Free of sulfur compounds.

T Tagging Bottom Using a wire line to determine the depth of sand in the wellbore covering the perforations. Tandum Operation Two stage operation of a reciprocating compressor. Tariff A charge levied by a pipeline owner for moving gas owned by another party through their pipeline. Typically 15£ per 100 miles, per MSCF. TDS Total dissolved solid content in an aqueous stream such as boiler feed water. Tetraethylene Glycol An expensive, thermally stable dehydration agent Torsional Vibration Analyzer An instrument used to uncover misfires in an internal combustion engine. Tree The complex assembly of valves that fits on top of a gas well. Triethylene Glycol The most common dehydration agent used in gas fields.

GLOSSARY 201

Trip Point A setting that, when exceeded, causes a compressor to shut down automatically. Tubing String A pipe run into the wellbore casing to promote gas flow. Turbine Meter An accurate way to measure large gas flows' at custody transfer points. Turbo Charger A small centrifugal air compressor driven by a exhaust gas from a reciprocating engine; the compressed air is used as combustion air to the reciprocating engine.

a Unloading Pocket Used on reciprocating compressors to reduce the load on the driver.

V Valve Qnloader A device that temporarily disables compressor valves to re duce engine load.

w Water Hits The sound of slugs of water hitting the wellhead tree when a well unloads liquids. Weir The device that maintains the liquid depth on a distillation tower tray. Wellhead Heater Used to prevent an adjustable choke from plugging with hydrates. Wellhead Compressor A small reciprocating compressor placed at a well to accelerate gas recovery. Wire Line A long, weighted wire lowered into a well to perform a variety of downhole tasks.

Z Zone A level of gas bearing sands capable of commercial production.

INDEX

INDEX A Acidizing, 66 Acid Blower, 154 Acid Gas, 154 Acid Gases, 133 Acidic Vapors, 138

Acoustical Filters, 188,190 Acoustical Filter Bottle, 191 Adibatic Dqpansion, 173 Adjustable Choke 25,29 Adjustable Clearance, 42 Adjustable Weirs, 131 Adlehyde Type Mictobiocide, 193 Aerated Foam, 8 Aerial Cooler, 68 Afterbum, 94 Air Compressor, 56 Air Compressor Rotor, 116

"Big Joe" Valve, 174

Biological Wastes, 106 Blade Pitch, 52 Blower Check Valve, 168 Blue Fire, 168 Boiler Tube Leaks, 156 Boiler Tube Sheets, 156 Booster Compressors, 90 Booster Stations, intro. Bottom Hole Pressure, 5,6 Brake Mean Effective Pressure, 98 Brine, 5,16 Brine Tank, 25,32 Bubble Caps, 71 Bubble Cap Tray, 66 Buried Pipelines, 194 Button Hole, 19

Air Cooling, 50

C

Air Fitter, 116 Air Inlet Filter, 94 Air Row, 51 Air to Fuel Ratio, 95 Amine Corrosion Inhibitor, 137 Amine Natural Gas Scrubber, 129 Amine Regenerator, 154 Amine Regenerator Feed, 166 Amine Solution, 133

Capacity Ratio Plot, 156 Carbide Plug, 31 Carbon Accumulation on Catalyst, 154 Carbon Black, 154 Carbon Deposits, 153 Carbon Deposits on Turbine Blades, 116 Carbon Disuifide, 148 COa, 148 Carbon Steel Trays, 144 Carbony! Sulfide, 148 Carry—over of Glycol, 75 Cartridge Filters, 136 Cascaded Sea Legs, 165 Casing Perforations, 14,18 Casing Pressure, 18 Catalyst Activity, 150,153 Catalyst Beds, 160 Catalytic Converter, 94 Catalyst Support Balls, 167 Catalyst Support Screens, 158 Cathodic Protection, 193,194 Center Downcomer, 130 Centrifugal Compressors, 100 Centrifugal Force, 106 Centrifugal Gas Turbine Driven

Ammonia Odor, 140

Annulus, 20 Anodes, 194 Anti-Surge, 111 Aromatic Solvent, 107 Aromatic Solvents, 193 Atmospheric Gas Vent, 33 Automated Loaders, 82 Auxiliary Drives, 49 B Back Pressure, 4 Back Pressure Controller, 32 Baskets Reduce Pressure Drop, 167 Bearing Damage, 103 Beit Drive, 52,56 Bernoulli's Equation, 184 Beta Scan, 85,88,96

Compressor, 113

2 0 4 INDEX Charcoal Removes Surfactants, 142 Chlorides, 144 Choke, 13,19,28,45 Choke Nipple, 184 Choke Nipple Coefficient, 185 Choke Sizes, 185 Circulating Dirty Amine, 135 Claus Capacity, 166 Claus Plant Warm-up, 160 Claus Reaction, 156 Claus Recovery Plant, 147 Claus Sulfur Recovery Plant, 147 Claus Unit, 150 Coil Tubing Unit, 14 Collection Header Pressure, 4 Collection Laterals, intro. Combustion Air, 92 Combustion Air Compressor, 103, 1 Common Carrier Transmission Lines, intro. Compressibility, 114,117,185,189 Compression Cylinders, 85 Compression Ratio, 100 Compression Work, 81,86 Compressor Booster Stations, 184 Compressor Curves, 114 Compression Efficiency, 83,102 Compressor Fuel Gas, 178 Compressor Lube Oil, 7 6 Compressor Speed, 117 Compressor Rod Loading, 39 Compressor Surging, 103 Computer Simulation of a Piping System, 189 Condensate Tank, 2 5 3 2 Condensers, 152 Condenser Demister, 152 Coning Water, 16 Copper Alloy, 144 Correlations to Size Meter Runs, 183 Corrosion Inhibitor, 106,137,166,192 Corrosion Probe, 193 Corrosion Products, 125 Corrosive Aspect of Amine Solutions, 133 Coupon, 193 Crank End, 36,86 Critical Flow, 185 Cross Exchanger, 133,138

INDEX Custody Transfer Meter, 181 Custody Transfer Points, 184 Cyclic Unloading of Liquids, 7 Cylinder Exhaust temperature, 9 0 Cylinder Head, 82,91 Cylinder Liners, 91 Cylinder Mis-Fires, 9 0 Cylinder Valves, 3 7

D Dampening Bottles, 190 Damping Orifice Plates, 189 Dampen out the Pulsations, 181 Debutanizers, 120

DECA, 85 Decomposition Furnace, 159 Defective Exhaust Valves, 98 Defrosting Procedure, 176 Degreaser, 66 Dehydration Efficiency, 5 5 Demister, 152 Desuperheater, 141 Detergent, 142 Detergent Washing, 116 Detonation, 9 8 Dew Point, 69,142 Dew Point - Solid Deposition, 108 Diethyiine, 7 4 Digital Pyromoter, 51 Digital Voltmeter, 194 Dirty Amine, 133 Dirty Glycol, 6 2 Discharge Temperature, 4 7 Discharge Valve, 86 Discharge Valve Leaking, 85 Distillation Column, 120 Double Acting Cylinders, 82 Double-Pipe Exchangers, 6 2 Down Hole Problems, 13 Downcomer, 63,121 Downcomer Pipes, 71 Drager Tubes, 148 Dried Air, 89 Drilling Mud, 65 Dry Fuel Source, 176 Dry Point, 108 Drying Tower, 71 Dual Completion, 25,45 Dual Completion Wells, 18

E Electronic Digital Timers, 10 Emulsion, 11 Engine Deficiency, 81 Engine Horsepower, 39,115 Engine Speed, 90,181 Engine Water, 56 Enriched Air, 161 Entrained Brine, 108 Entrained Grycol, 176 Entrain Liquids, 6,11 Entrainment Velocity, 6 , 1 1 , 2 2 3 8 Entrain Water, 8 Equilibrium, 7 4 Erosive Sand, 2 7 Ethane, intro. Excessive Mud Pressure, 65 Exhaust Gas, 3 9 Exhaust Gas Manifold, 9 2 Exhaust Gas Scavenging, 97 Exhaust Gas Temperature, 81 Exhaust Temperature, 115 Exhaust Valves, 91 External Coating Protecting A Pipeline, 193 External Grycol Stripper, 7 6 Exterior Corrosion, intro. F Fan Blade Pitch, 5 0 Fan Blade Tip Speed, 51 Fan Speed, 50 Field Compressor, 3 6 Filter Coalescer, 108 Fin-Fan Air Cooler, 50,166 Firing Time, 97 Fixed Choke, 25,29 Flameiess Heater, 177 Flaring, 2 0 H a s h Gas, 31,45 Float Chambers, 136 Hooding, 120,133 How-Back Connection, 2 2 How Recorder, 182 Rowing-Back, 2 0 Rowing Tube Pressure, 4 Rowpoint, 9 Foaming, 130,177 Foaming Glycol, 177

Formation Sand, 14,103 Fouling, 17,119 Fouling Deposits, 30,192 Frac Sand, 14,65 Freezing Temperature, 8 9 Freeze Up, 172 Fuel Efficiency, 113 Fuel Gas Manifold Pressure, 81 Fuel Gas Valves, 9 8 Fuel Injection Valves, 92,97 Fuel to Air Ratio, 9 2 Fungible Material, intro. G Gas Gas Gas Gas Gas Gas Gas Gas Gas

Compressor, 103,112,114 Cooling, 4 9 How, 16 Field Operators, 1 7 8 Lift Downhole Methods, 10 Lift Mandrels, 9 Metering, 182,186 Moisture Level, 70 Processors Suppliers Assoc. Engineering Data, 190 Gas Production, 5 Gas Scrubbers, 128 Gas Specific Gravity, 118 Gas Transmission, 113 Gas Turbines, 112,174 Gas Turbine Centrifugal Compressors, 173 Gasoline Fractionation, 120 Gauge Glass, 3 0 Glycol Circulation, 69 Glycol Dehydration, 4 9 Glycol Dehydration Tower, 190 Glycol Dehydrator, 30,108,176,179 Glycol Drying, 61 Glycol Losses, 63,177 Glycoi Mist, 176 Glycol Pump, 61 Glycol Reboiler, 61,74 Grycoi Seal, 66 Governor Speed Control, 91 H Head-End, 3 6 Head End Cylinder Clearance, 4 5 Head End Clearance Pocket Adjustment, 181

205

206 INDEX Heat of Condensation, 55 Heat Transfer Coefficient, 51 Heater Capacity, 29 High Meter Reading, 181 High Pressure Separator, 25,29 High Valve Losses, 85 Hot Discharge Valve Cap, 88 "Huff & Puff', Self-Cleaning Air Filter, 116 Hydrate Formation, 28,172,174 Hydraulic Oil, 56 Hydrogen Sulfide, 148 H2S Scrubbing Towers, 129 Hydrauiic Height of Liquid, 132 Hydraulic Powered Fans, 56 Hydrocarbon Deposits, 66 Hydrocarbon Hydrate, 172 Hydrocarbon Skimming Tap, 129 Hydrocarbon Vapor, 31 Hydrochloric Acid, 66 Hydrolized, 151 I Ice Crystals, 176 Ignition Valves, 91 Impeller, 56,93 Impeller Diameter, 117 Impeller Fouling, 111 Impeller to Casing Clearance, 94 Incinerator Temp., 149 Incipient Entrainment Velocity, 8 Incipient Jet Rood, 130 Incremental Gas Flow, 3 Inducer, 93 Instrument Gas, 30 Instrument Gas Bottle, 10 Interface Level, 31 Intermitter, 10 Intermitter Controller, 10 Internal Combustion Engine, 90 Internal Peak Discharge Pressure, 89 Iron Sulfide Particulates, 136 Isobutane, intro. J Jet Erectors, 19 Jet Hood, 121,122 Joint Ventures, intro. Joules Thompson Expansion, 174

INDEX 207 K Kerosene Blanket 145 Kettle Reboiler, 125 Key Components, 120 Knock Out Drum, 177 L Labyrinth Seals, 110 Labyrinth Seal Leakage, 103 Late Combustion, 97 Leaking Condenser Tubes, 153 Leaking Liquid Dump Valve, 29 Leaky Valves, 88 Lean Amine, 133,138 Level Taps, 136 Lift Gas, 19 Liquid Backing Gp out of the Downcomers, 131 Liquid Dump, 175 Liquid Rood, 121 Liquid Rood Point, 121 Liquid Loading, 1,6 Liquid Level Dumps, 179 Liquid Level in a Vessel, 128 Liquid Sulfur, 156 Liquid Unloading, 1 Lithium Bromide, 143 Lost Compression Horsepower, 81 Low Pressure Three Phase Separator, 2531 Low Sulfur Gas, 170 Low Wellhead Pressure, 8 Lubricator, 14 M Magneholic Gauges, 123 Main Line Compressors, 172 Master Valve, 27 MDEA, 166 Meter Recording, 181 Meter Run, 33,180,184,190 Metered Row, 47 Methanol, 178 Mineral Rights, intro. MIT, 85 Mositure Specifications, 59,62,176 Molecular Weight, 118 Monoethanolamine, 133 Moths, 53

Motor Valve, 10 Multipoint Test, 3

Poppet Valves, 88 Porosity, 1,4 Portable Sand Separator Skids, 21 N Positive Choke, 40 Natural Gas condensate, 29 Power Cylinder, 90 Natural Gas Hydrates, 115 Pneumatic Relays, 89 Natural Gasoline, 32 Pressure Drop in a Sulfur Plant, 153 Nitrogen Purge, 169 Pressure at Perforations, 5 Nitrous Oxides, 92 Pressure Sensing Taps, 180 Normal Butane, intro. Pressure-Volume Diagram, 85 Production Losses, 33 Production Rubing, 16 O Promote Gas Row, 1 Olefins in Natural Gas, 89 Open Area Gnder the Downcomer, 131 Propane, intro. Propane-Butane Splitter, 122 Orifice Diameter, 182 Plugged with Hydrates, 173 Orifice Meter, 25 Plugged Orifices, 183 Orifice Plate, 32,180,182,191 Plunger Lift, 10 Organic Solvent, 193 Pulsation, 33,86,181,182,188 Orifice Taps, 136 Pulsation Bottles, 189 Otto Cycle, 95 Pulsation Damper, 182 Outlet Weir, 131 Pulsation Effects, 180 Oxidized Amine, 135 Pulsation Induced Metering Error, 182 Oxygen Deficiency, 98 Pulsation Problems, 89 Oxygen to Enrich Process Air, 161 Pulley, 52 Pumping Efficiency, 61 P Pyrometers, 97 Packer, 18 Pyrophonic Iron, 168 Packed Beds, 120 Panel Board, 89 Paraffin, 106 Paraffin Wax, 192 Pass-Partition Baffle, 50 Peak Pressure, 89 Peak Pressure of Cylinder, 97 Peak Speed, 115 Perforations, 1,16 Perforations Covered with Sand, 27 Permeability, 1,4 Pipe to Soil Potential, 194 Pipeline Booster Compressors, 173 Pipeline Moisture Specification, 50 Pipeline Pressures, intro. Piping Pulsation, 87,182,189 Piping Reducers, 182 Piston, 82 Piston Position, 85

Piston Rings, 97 Piston Ring Leakage, 87

R Radial Bearings, 110

Radiation Scan, 126 Reboiler, 125 Rated Speed, 42 Ratio of Specific Heats, 189 Reaction Furnace, 149,152,156 Reactor Inlet Baskets, 166 Reboiier Drum, 70 Reboiler Duty, 120 Reboiler Leaks, 133 Reboiler Temperature, 74 Reboiler Tube Corrosion, 137 Reboiler Tube Metallurgy, 166 Reboiier Vapor Return Nozzle, 126 Recessed Sumps, 131 Reciprocating, 45 Reciprocating Compressor, 81,89,181 Reciprocating Engine, 90,113,176 Reclaimer, 138

208 INDEX Reclaimer Duty, 140 Reclaimer Operation, 137 Rectification Section, 124 Rectifier, 194 Reduced Compression Efficiency, 1 Reduced Conversion, 153 Reference Electrode, 194 Reflux, 137 Reflux Rate, 120 Refactory, 159 Regenerator, 140 Regenerator Boiler, 133 Regenerator ReboUer Tube Leak, Regenerator Reflux, 137 Reheat Line, 156 Reheat Exchangers, 163 Reheat Exchanger, 150 Rejection of C0 2 , 166 Reservoir, 9 Reservoir Pressure, 4,16 Resonant Frequency, 188 Resonant Piping Length, 189 Retarded Firing, 97 Rich Amine, 133,148 Rich Amine Surge Drum, 147 Rod Loading, 39,41,88 Rotating Assembly, 113 Rotary Precoat Filters, 136 Rotor, 93 Rotor Fouling, 119 Rotor Vibration, 103 Royalty, 33 Royalty Payments, 180 S Salt Deposits, 107,108 Salt Laydown, 75 Salty Environments, 194 Sand Bridge, 13 Sand Covering Perforations, 13 Sand Formation, 4 Sand Separator, 21

Scrubber, 133 Scrubber, Foaming, 141 Sea Leg Blowout, 164 Seal Legs, 157 Secondary Valve, 27 Self-Cleaning Air Filter, 116 Senior Meter Run. 33

INDEX Severance Tax, 33,182 Sheave, 52 Shut-In Pressure, 3,4,13 Sieve Holes, 181 Silicone Defoamer, 142 Single Completion, 25 Skids, 21 Soap-Sticking, 43 Soap Sticks, 10,11,2238 Soda Ash, 138 Solid Hydrates, 177 Solvent Injection System, 107 Sonic Velocity, 185 Spark or Stack, 136

Spark Plug, 98 Spark Plug Wires, 91 Sparger Pipe, 75 Steam Condensate Level, 137 Specific Gravity, 5,114,185 Speed Sound, 189 Spillback Control, 110 Split Shaft, 103,112 Squeeze-Job, 18 Stabilized Shut-In Pressure, 3 Stainless Tubes, 144 Stalling, 110 Statiscope, 98 Steam Boiler, 156 Stokes Law, 8 Stripping Gas, 75

Stripping Efficiency, 177 Specific Gravity of Sulfur, 157 Structure to Environmental Potential, 196 Suction Temperature, 118 Suction Valves, 87 Sulfate Reducing Bacteria, 192 Sulfur Fires, 152 Sulfur Fog, 151 Sulfur Hexafluoride, 143 Sulfur Plants, 149 Sulfur Plant Catalyst, 150 Sulfur Recovery Capacity, 166 Sulfur Recovery Plant, 133,135 Sulfuric Acid, 158,169 Sulfuric Acid Formation, 153 Sulfur Solidifies in the Catalyst Beds, 156 Supercharged Engine, 92

Surfactants, 38 Surface Metal Temperature, 84 Surface Piping, 6 Surface Pressure, 37 Surface Tension, 136 Surge, 110

Sustaining Entrainment Velocity, 7 Superheated Gas, 68 Swabbed Out 23 Sweet Gas, 133 T Tachometer, 91 Tagged Depth, 14 Tandum, 36 Tariff, intro. Tax Payments, intro. Temperature Drying Force, 51 Temperature Increase of Gas Due to Compression, 83 Temperature Inversion, 128 Temperature Rise, 55 Tetraethylene Glycol, 63 Thermal Degradation, 75 Thermocouples on the Gas Exhausts, 90 Thermoplastic Valve Plates, 88 Theoritical Reduction in Conversion, 163 Theoritical Gas Row, 120 Three-pass Trays, 130 Three Phase Separator, 32,45 Thrust Bearings, 110 Top Tray Equilibrium, 74 Torsional Vibration Analyzer, 91 Tower Internals, 120 Tower Pressure Drop, 121,132 Total Dissolved Solids, 142 Toxic Vapors, 164 Transmission Compressors, 82 Transmission Lines, intro. Transmission Pipelines, 49 Transmission Temperatures, 55 Tray Capacity, 70 Trayed Columns, 64 Tray Damage, 132 Tray decks, 120 Tray Design, 131 Triethylene, 49

Triethyiene Glycol, 62,193 Trips, 42

Tube Fouling, 50 Tubing Dimensions, 9 Tubing Entrainment Velocity, 39 Tubing Pressure, 20 Tubing String, 4,9,25 Turbine, 112 Turbine Blades, 116 Turbine Metering, 186 Turbine to Shroud Tip Clearance, 94 Turbine Wheel, 103 Turbocharger, 49,56,92,98 Two-Stage Compressor, 36

a Underground Collection Lateral, 181 Unloader Pocket, 81,82 Unloading Liquids, 6 Upset Tray Decks, 128 V Valve Valve Valve Valve

Lift, 89 Losses, 88 Plate Springs, 89 Plates, 87

Valve Ports, 88

Valve Trays, 72 Vapor Liquid Distribution, 130 Vertical Temperature Profile, 153 Vertical Temperature Survey, 126 Vibrations, 188 Vibration Induced by Reciprocating Compressors, 188 Viscosity, 8 Volumetric Capacity, 37,82 W Water Hits, 38,47 Wasted Horsepower, 87 Wear Ring, 56 Weir, 121 Weir Heights, 132 Wet Gr/col Flash Drum, 70 Wellhead Cap, 22 Wellhead Compressors 13,16,76 Wellhead Field Compressor, 36 Wellhead Liquids, intro. Wellhead Performance Curve, 3

210 INDEX Wellhead Pressure, 9,33 Wellhead Tree, 1,11,18,25 Wellhead Tubing Velocity, 39 Wire Line 5,14 Worn Piston Rings, 88 X X-Ray, 132

ABOUT THE BOOK Troubleshooting Natural Gas Processing is based on Norm Lieberman's experiences in gas fields in South Texas. Encompassing wellhead produc tion problems, as well as gas treating, dehydration, compression and transmission, the book recounts the trials and tribulations of moving gas from the wellhead to the common carrier pipeline from both a technical and personal viewpoint. Each chapter describes the operating principles and troubleshooting techniques of a particular process step in the context of the time and place the problem was first encountered. Troubleshooting sulfur recovery, amine treating and light hydrocarbon distillation techniques are based on the Author's many years of experience in petroleum refineries and process plants. Norm Lieberman's approach is to attack problems from the most practical level possible.

ABOUT THE AUTHOR: Trained as a chemical engineer at Cooper Union and Purdue, Mr. Lieberman worked for Amoco Oil and GHR Energy prior to establishing Pro cess Improvement Engineering in Metairie, La. He has held positions as an operating superintendent, technical manager and refinery manager. His current activities en compass field troubleshooting and teaching troubleshooting seminars based on his previous best selling books. Norman P. Lieberman

ISBN 0-87814-306-8

Troubleshooting Natural Gas Processing

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