ransmission
NORMAN P. LIEBERMAN
P e n n W e l l Books
A PennWell Publishing CompanyCopyright © 1987 by
PennWell Publishing Company
1421 South Sheridan RoadlP.O. Box 1260 Tulsa, Oklahoma 74101 Library of C o n g r e s s c a t a l o g i n g in publication d a t a L i e b e r m a n , N o r m a n P . Troubleshooting n a t u r a l g a s processing. 1. G a s i n d u s t r y . I. T i t l e . TP751.L54 1986 665.7 8 6 - 1 6 8 7 8 ISBN 0-87814-308-4
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
Dedicated to Jack Stanley — Grace Under Pressure
DEDICATION iii
PREFACE vii
INTRODUCTION ix
SECTION I TROUBLESHOOTING AT THE WELL SITE
1 Increasing Gas Row at the Wellhead 1
2 Additional Ideas to Enhance
Gas Row 16
3 Wellhead Surface Equipment 25
4 Wellhead Compression 36
5 Process Cooling in Remote
Locations 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
10 Gas Turbine Driven
Centrifugal Compressors 112
11 Light Hydrocarbon Distillation 120
1 2 A m i n e R e g e n e r a t i o n a n d S c r u b b i n g
1 3 Sulfur Plant O p e r a t i o n
1 3 3
1 4 8
SECTION III PIPELINE PROBLEMS
G L O S S A R Y INDEX
14
15
16
17
r
Hydrates
Production Metering
Piping Pulsations
Corrosion and Fouling
172
180
188
192
195
203
VIPREFACE
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
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 H2S
• 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 t h a n 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, t h e 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 t h a t 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.
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 t h a t 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 t h a t it will be cost effective to recover these hydrocarbons as liquid products. Only about 35% of the ethane is usually removed from t h e 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 alky-lation 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 i f s com petitors and sundry producers. The tariff t h a t 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 u p 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 t h e 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 t h a t the pipeline is buried under.
Gas inside a transmission line is non-corrosive; i t is t h e 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-x
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 t h a t 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.
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."
' T m 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 t h e 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 t h e perforations in t h e 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.
High-low pressure shutdown Cap ^ Adjustable choke
w=J
X
Wellhead tree Gas to collection header \ Surface , Casing • Tubing .PackerI77777T7777% /// /T7T
v ' ' , Gas-bearing fll/ . * sand formation /Perforations in casing
Bottom of hole
Figure 1-1 Gas production from the tubing of a single completion well.
These points can best be understood by referring to Figure 1-1. Simply observing t h e operation of a well does little to help differen tiate t h e causes of diminished gas production.
One of t h e questions asked by lease operators is how to calcu late the incremental gas flow t h a t can be expected from a well due to reduced lateral collection header pressure. The formula used to estimate this increase is:
Q2= Qi _,n
Pf - Pi
P* - Pi2 (1) whereQx = Initial gas flow.
Q2 = Final gas flow.
Ps = Stabilized shut-in pressure, measured a t t h e wellhead
cap.
Pi = Initial wellhead pressure. P2 = Final wellhead pressure.
n = The slope of the wellhead performance curve obtained from a well's multipoint test.
While Pxand Qi are known from the current operating data,
and t h e lease operator will be able to estimate P2, (the final well
head pressure) determining a reasonable value for the shut-in pres sure (Ps) and t h e slope of t h e wellhead performance curve (n) can be a challenge. After a well h a s 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 t h e shut-in pressure.
There are several problems which interfere with obtaining a true wellhead shut-in pressure. One difficulty is t h a t while one is waiting for t h e 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 t h e wellhead pressure will be sur-pressed by 1,000 psig. For this case, the observed wellhead shut-in pressure is meaningless. When the well is put back on-line and resumes gas flow, the wellhead pressure will probably increase,
4 TROUBLESHOOTING NATURAL GAS PROCESSING
rather t h a n 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 r u n 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 t h a t the reservoir pressure and porosity are adequate — t h a t is, there is a plentiful supply of gas in the ground for the well to draw on. Also, we are assuming t h a t 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 shut-in and flowshut-ing tube pressures will be similar. On the other hand, if gas flow is restricted by a discarded tool stuck 8,000 feet down in t h e 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 t h a t flow
INCREASING GAS FLOW AT THE WELLHEAD 5
from the well was choked back to maintain constant production). This leads to an important troubleshooting principal: The first point to establish in troubleshooting a well for lost production is whether the problem is above or below the surface!
LIQUID LOADING
Although we have been talking about wellhead pressure (both shut-in and flowing tube), the wellhead pressure is just an indirect indication of the really important parameter-that is, the bottom hole pressure. It is the pressure inside the casing at the level of the perfor ations that determines gas flow. By lowering a pressure sensing instru ment suspended on a wire-line to the proper depth, bottom hole pres sures can be directly measured. But this is an expensive and time consuming procedure, and beyond the scope of the options available to the field troubleshooter.
So we do not usually know the actual bottom hole pressure. If we knew the density of the column of fluids (i.e. the mixture of gas, conden sate and brine) inside the tubing, we could calculate the bottom pressure as follows:
P = P + (SG) H/2.31 (2)
p i
where
P = Pressure at perforations, psig Pi = 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 t h e surrounding sand formation t h a t determines the rate of gas flow from a well. From equation (2) we can see t h a t the bottom hole pressure will increase as the density (SG) in the tubing rises. This increase in Pp reduces the gas production from the well according to
the formula: 2 2 Q - P ' - Pp where r (3) Q = Gas Flow P — Reservoir Pressure
The main point t h a t t h e troubleshooter must absorb from the preceeding paragraphs is t h a t 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 t h a t 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.
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 t h a t 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 t h e 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
8 TROUBLESHOOTING NATURAL GAS PROCESSING
Wells with average production rates below 150 MSCFD, all had one factor in common - low wellhead pressure. The lower the wellhead pressure, the greater the velocity developed in the tubing with a given volume of gas. For example, 150 MSCFD of gas flowing at a pressure of 600 psig develops the same velocity as 240 MSCFD flowing at a pressure of 1000 psig. For those readers familiar with Stokes Law:
V « gr2 (DL - Dy) / (vis) (4)
where
V = velocity of a droplet of liquid falling in a gas phase under the influence of gravity.
g = Gravitational constant. DL = Density of liquid droplet.
Dy = Density of the continuous gas phase. r = Radius of droplets
vis = Viscosity of gas phase.
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 t h a t entraining condenate would require a lower velocity than t h a t 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:
VE = K / DL - DyV/2
V Dv ) (5)
where
VE = Incipient entrainment velocity
K = An empirically derived constant D = Density, lbs./ ft3
INCREASING GAS FLOW AT THE WELLHEAD 9
Of course, my objective was to derive a value for "K" which I could use to predict with confidence VE 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
COMMON TUBING DIMENSIONS (Inches) Size,O.D.* Size, I D . 2% 1.995 27/s 2.441 3V2 2.992 4 3.476 4V2 3.958
*Tubing size in gas field parlance only refers to the outside diameter.
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 t h a t 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 t h a t 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 u p with liquids. Gas lift Mandrels and
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 t h e 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 t h a t 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 high-pressure over-ride is set to open the motor valve when the high-pressure build-up is more rapid t h a n 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 u p 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
accumulating in the tubing, the lower the entrainment velocity. This means t h a t 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 t u r n 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 t h e naphtha t h a t 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. VE, the
entrainment velocity, will also increase by 41%. This occurs because halving the pressure also halves Pv, t h e vapor density, and this in
creases VE 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 t h e 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 t h a t I haven't been trying to listen to you for the past two hours . . . . but
12 TROUBLESHOOTING NATURAL GAS PROCESSING c e 5 c J2 T3 3 O
1
J
I
INCREASING GAS FLOW AT THE WELLHEAD 13
my mind tends to wander. I'm thinking about our Juanita # 5 well, down in J i m 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; t h e 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, t h a t while the well was shut-in to permit the compressor piping to be tied-in, t h e wellhead pressure rapidly increased to 1900 PSIG. You would think that a well with all that high pressure gas behind it could produce more t h a n 80 MSCFD with a W wellhead choke? What do you think".
SAND COVERING PERFORATIONS
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 t h e 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 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 t h e 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 t h e 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 t h e 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 t h e tubing and the outside of t h e 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, t h e n 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 t h e tubing is frac sand rather t h a n 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 t h e 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 t h a t 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.
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.
2
ADDITIONAL IDEAS
TO ENHANCE GAS FLOW
One of t h e 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:
where Q P R P I C,n _ — = = Q = C ( PR 2 Gas flow, SCF Reservoir pressure Wellhead pressure Constants peculiar to <
-Pf )°
in individual wellThe above equation is really of little use to the field trouble-shooter because C,n and PR 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 t h a t as I dropped the wellhead pressure by speeding-up the wellhead compressors that:
16
ADDITIONAL IDEAS TO ENHANCE GAS FLOW 17
• 30% of t h e 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, t h a t the incremental gas flow obtained from a further reduction in the flow ing wellhead pressure may be quite small. It transpires t h a t there is another factor which tends to negate the effects of decreased well head pressure. This factor is water.
CONING WATER INTO A WELL
"Mendoza, this meter is broken", I complained. "Every time we increase t h e compressors speed to pull-down t h e 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 t h a t 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 t h a t , but why don't we increase our gas make too". "You know more about these things t h a n I do Sir. But what I've been told is t h a t the gas in the reservoir is floating on top of a pool of brine. Once t h e gas pressure in t h e reservoir is pretty much reduced, t h e brine starts working it's way towards the casing perforations. The lower the pressure at the perforations, the more easily the brine flows u p 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 t h e 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.
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 down-hole pressure:
Q = C ( PR 2- PD H 2)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 t h a n that of the brine produced when the well was first put on line, we can assume t h a t 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 t h a t 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 t h e 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
TUBING PRODUCTION CASING PRODUCTION
7
PERFORATIONS FOR CASING A PRODUCTION ^ PACKER PERFORATIONS FOR TUBING PRODUCTIONFigure 2-1 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 sur-press 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
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 t h a t 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 t h e 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.
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
TUBING ■ 80°F MOTIVE GAS CASING 2 2 0 PSIG 2 0 0 M SCFD EJECTOR 5 0 0 PSIG MAIN LATERAL DUAL COMPLETION WELLFigure 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.
ADDITIONAL IDEAS TO ENHANCE GAS FLOW 21
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 THICKNESS1 2 VESSEL TO BE STRESS RELIEVED
Z\t
2 1.0 STELLITE LINED NOZZLE FITTED FOR
TANGENTIAL
ENTRY-QUICK-CONNECT FITTING
QUICK-CONNECT FITTING
Figure 2-3A Facility to recover wellhead gas during initial flaring.
GAS DRIVEN PUMP
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 u p 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 shut-in 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 t a k e 15-30 minutes to successfully blow the brine out of a tubing string. If the procedure is working, the wellhead pressure will climb as t h e 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
NORMAL GAS
FLOW FROM
TUBING
WELLHEAD
TREE
Figure 2-4 Facilities to unload a depleted well.
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 t h e 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 t h a t 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 t h e concepts discussed in t h e 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, t h e 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, VE and the coefficient, K, in the entrainment velocity
equation:
VE = K VPT. - P 7
Pv Answer = 6.3 fUsec., K = 1.37
2 4 TROUBLESHOOTING NATURAL GAS PROCESSING
REFERENCES
1. Sim Sci, Simulation Sciences Inc., PLPEPHASE Fullerton,
California.
3
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 t h e 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 t h a t 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
pressure does not bear a direct relationship to the critical bottom hole pressure (i.e. t h e pressure inside the tubing at the level of t h e 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, t h e 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 t h e 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, t h e tubing will collapse. If you observe the opera tion of a well t h a t 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 t h a t 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
2 8 TROUBLESHOOTING NATURAL GAS PROCESSING
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 t h a t 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 t h a t 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
WELLHEAD
CHOKE
3/4"TUBING
CASING
tXl=y VENT
- /'S/// / //// ///
Figure 3-2 A piece of 3/4" tubing can recover gas leaking into the casing of a single completion well.
WELLHEAD SURFACE EQUIPMENT 29
• 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 t h a t 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 t h a t 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 t h e 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
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 a n . 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 t h a t 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
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 t h e 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 3% Methane 53% Ethane 22% Propane 13% Butanes 6% Pentanes Plus 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
32 TROUBLESHOOTING NATURAL GAS PROCESSING
into the gas supply to t h e 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 t a n k s 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 t h a t consequently gasoline was blowing out of the low pressure separator's vent. While I agreed t h a t 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 t h e 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 t h e low pressure, three phase separators are
en-WELLHEAD SURFACE EQUIPMENT 3 3
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 invar-ibly 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 t h a t 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 t h e recovered vapors in t h e compressor after-cooler or in the after-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.
COQ.
O
(§>-0i
needed for a year or two. As wellhead pressure and condensate rates fall, the economics of continued compressor operation will diminish.
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 t h e 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 t h e 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 t h a t the first-stage is called the "head-end" and t h a t the second-stage is termed the "crank-end.
36
WELLHEAD COMPRESSION 37
Head-End Operation
The compressor cylinder valves have been disabled in the crank-end (i.e. second-stage), so t h a t only t h e 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 t h a t the head-end cylinder's volumetric capacity is much greater than that of the crank-end. However, the volumetric capac ity of t h e 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 t h e dis charge, and the discharge cooler may be by-passed.
Reducing the surface pressure by compression reduces the gas pressure in the tubing at t h e 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 t h a t have become water-logged may double or triple
795 PSIG llO°F INTERSTAGE COOLER \ GAS ENGINE — 2lO°F CRANK END
FUEL GAS" SPEED CONTROL
GAS TO PIPELINE S 790 PSIG ;
HEAD END 8 0 0 PSIG CYLINDER CLEARANCE ADJUSTMENT ■I38"F 80°F- - 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:
VE = 1.2 ( DT - D v
\ Dv
where
VE = Entrainment velocity, ft./sec.
Dv = Density of gas, lbsVft.3
DL = Density of liquid, lbs./ft.3
This equation for entrainment velocity is in t h e 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 t h e DL term in t h e
above equation by over 50% and thus effectively lowers the entrain ment velocity.
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:
H P = THFX MSCFD (Per Stage) 6.7
where
THP = Theoretical horsepower per mole obtained from Figure 4—2.
H P = 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
