Table Of ContentGas Well Deliquification
Gas Well Deliquification
Third Edition
James F. Lea Jr
Consultant, PLTech LLC,
Lubbock, TX, United States
Lynn Rowlan
Engineer, Echometer,
Wichita Falls, TX, United States
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1
Introduction
James F. Lea’s experience includes about 20 years with Amoco Production
Research, Tulsa, OK; 7 years as Head PE at Texas Tech; and the last 10 years or
so teaching at Petroskills and working for PLTech LLC consulting company. Lea
helped to start the ALRDC Gas Dewatering Forum, is the coauthor of two previous
editions of this book, author of several technical papers, and recipient of the SPE
ProductionAward,theSWPSC SlonnegerAward,andtheSPELegends ofArtificial
LiftAward.
1.1 Introduction
Liquid loading in a gas well is the inability of the produced gas to lift the produced
liquids from the wellbore. Under this condition, produced liquids will accumulate
in the wellbore leading to reduced production and shortening of the time till the
wellnolongerproduces.
According to EIA, there are about 600,000 gas wells in the United States (see
Fig.1.1).
By some estimates, 70%(cid:1)80% of gas wells are low rate and below about
300Mscf/D. Therefore perhaps 400,000(cid:1)500,000 gas wells are at risk of lower or
noproductionfromliquidloadingunlessartificiallift(AL)isproperlyapplied.
Methods of diagnosing the occurrence of liquid loading will be presented here
forbothnearverticalconventionalwellsandhorizontalrapidlydecliningunconven-
tional wells. Methods of solution will be presented and discussed in detail to help
optimizethesolutionofliquidloadingusingvariousformsofALincluding:
1. Newer techniques of rod design and rod protection in deviated wells using sucker rod
systems
2. NewmethodsforSRP(suckerrodpump)systemstoallowdeeperintakeforthesystems
inhorizontalwells
3. Design of gas lift systems for conventional and also declining unconventional wells
usingconventionalgasliftwithbracketedvalvesforanticipatedchangingrates
4. Use of high-pressure gas lift to allow more drawdown initially and to eliminate some
downholeequipment
5. Newtechniquesoftrackingplungers,variousforms ofplungerlift,newplungeroptimi-
zationtechniques,newequipment,andplungersinhorizontalwells
GasWellDeliquification.DOI:https://doi.org/10.1016/B978-0-12-815897-5.00001-9
©2019ElsevierInc.Allrightsreserved.
2 GasWellDeliquification
Number of elements
800,000
600,000
400,000
200,000
0
1990 1995 2000 2005 2010 2015
U.S. Natural Gas Number of Gas and Gas Condensate Wells
Figure1.1 Numberofgaswells.
Source:USEnergyInformationAdministration.
6. Use of electric submersible pumps (ESPs) to dewater including design for lower rate
wellsrequiringneededcautions
7. Optimization of progressing cavity pumpings (PCPs) that usually operate in shallower
wells.Rodprotectionindeviatedandhorizontalwells
8. Thelatestinapplicationoffoamerchemicalsandmethodsofapplication
9. Detailsandmethodsofapplicationforgasseparationforallthepumpingsystems
10. Newadvancesinautomationarepresentedinaseparatechapter.Automationisaneces-
sityifoptimumconditionsaretobeachieved
1.2 Multiphase flow in a gas well
To understand the effects of liquids in a gas well, we must understand how the liq-
uidandgasphasesinteractunderflowingconditions.
Multiphase flow in a vertical conduit can be described by a number of available
flow regime maps. These can be used to decide whether or not a well is predicted
to be in a loaded condition. However, the well would have to be evaluated at both
the surface and depth for a complete analysis. The flow regime of annular mist
would be where one would like to flow a gas well and if it drops out of the flow
regime,AL(artificiallift)wouldberequiredtoremoveliquidandlightenthegradi-
ent in the tubing. In the mist flow the effects of liquid production are felt the least
bythewell(Fig.1.2).
Coincidentally the rate of 320Mscf/D at 100psi is the critical for 2 3/8
tubing.Whenpressure(200psi),thepointdropsbelow criticalandthe linebetween
annular and slug/churn for both values of bpd/Mscf. When the pressure is
less than 100psi, the velocity is more than critical for both 88 and 200bbls/Mscf
liquid/gas fractions. In Chapter 3 and Appendix B the expression derived and
used for critical velocity and rate is independent of the liquid/gas fraction and
Introduction 3
Approximate flow regime illustration
Dispersed bubble
0.7
s) Bubble Annular
sl (ft/ mist
V Slug or churn 6 5 4
3 2 1
0.07
0.01 0.1 1 10 100 1000
Vsg (ft/s)
Figure1.2 Illustrationofpossibleflowregimemapforverticalflow.
Forabovewhatnumbersinboldindicate:(allfor23/8’stubing)
1:88bbls/Mscf,50psi,velocityfor320Mscf/D,120(cid:3)F;
2:88bbls/Mscf/100psi,velocityfor320Mscf/D,120(cid:3)F;
3:88bbls/Mscf,200psi,velocityfor320Mscf/D,120(cid:3)F;
4:200bbls/Mscf,100psi,velocityfor320Mscf/D,120(cid:3)F;
5:200bbls/Mscf,50psi,velocityfor320Mscf/D,120(cid:3)F;
6:200bbls/Mscf/50psi,velocityfor320Mscf/D,120(cid:3)F.
this shows why the critical, without this dependency, is still shown to work in
thisexample.
Thisexampleusesanapproximateflowregimemap andifoneistouse theflow
regime chart to suggest if an operational point is above/below critical (in Annular
Mist or not), then one should find a flow regime chart that is tested to agree with
welldata.
More details will be shown on the critical velocity and critical rate. Also it will
be shown that Nodal Analysis (Chapter 4) can infer above/below critical or not.
However, this example ties the critical to the multiphase aspects of the calculated
critical rate. It is shown that the flow regime map, the calculated critical rate/
velocity model, and Nodal Analysis will be predictive techniques for critical rate
and under what conditionsliquid loading can occur.
A well may initially have a high gas rate so that the flow regime is in mist
flow in the tubing near the surface, but is more liquid rich flow regimes in the
tubing at depth. As time increases and production declines, the flow regimes from
perforations to surface will change as the gas velocity decreases. Liquid produc-
tion may also increase as thegasproduction declines.
Flow at surface will remain in mist flow until the conditions change sufficiently
at the surface so that the flow exhibits a more liquid rich regime such as slug flow.
At this point, the well production will be observed to become somewhat erratic,
progressing to slug flow as gas rate continues to decline. This will often be
4 GasWellDeliquification
accompanied by a marked increase in the decline rate. Note this type of analysis is
more complicated than presented here as conditions in a well can be different from
the surface to the bottom hole of the well. For instance liquids may be starting to
accumulate in a more liquid-rich flow pattern downhole and the conditions uphole
canstillbeinmistflow.
Eventually, the unstable slug flow at surface will transition to a stable, fairly
steady production rate again as the gas rate declines further. This occurs when the
gas rate is too low to carry liquids tosurface and simply bubbles up through a stag-
nantliquidcolumnatthebottmofthewell.
If corrective action is not taken, the well will continue to decline and eventu-
ally log off. It is also possible that the well continues to flow for a long period in
a loaded condition with gas produces up through liquids with no liquids coming
to the surface. Note that the well can continue to flow below critical, sometimes
for a long time, but it would flow more if the liquid loading problem could be
solved.
1.3 Liquid loading
Nearly all gas wells produce some liquids even if the rate of liquid production
is small; if the gas velocity is below the critical (to be defined in more detail in
Chapter 3), then the well will experience liquid loading. In other words, liquids
will accumulate in the wellbore and reduce production. This is shown by the
fact that there are many gas wells on plunger lift that produce 5 or less bpd of
liquids. If not on plunger, they will produce less or no gas. Critical velocity correla-
tions (Chapter 3) do not require the liquid rate as an input. If more liquid is being
produced then once below the critical the well can load faster. If little liquids
are still being produced below critical, the well will eventually liquid load. Liquid
loading modeling is sensitive to the liquid rate when using Nodal Analysis
(Chapter 4).
1.4 Deliquification techniques
The below list1 (modified) introduces some of the possible methods to deliquefy
gas wells that will be discussed in this book. These methods may be used singly or
incombinationinsomecases.
(cid:1) Initialhighrates(forunconventionalwellonsharpdecline)
Unconventional wells may come in high rates initially which are well above critical
rate. For maximum PVP (present value profit) use Nodal to look at flow up casing, flow
up casing/tubing annulus and to look at tubing size effect on flow. Some operators are
considering annular gas lift and high-pressure gas to boost the high rates. Most of the
profitsfromunconventionalwellsareinthefirstyearortwo,andthenlaterwithlowrates
andrequiredAL,thereturnsaremuchlower.
Introduction 5
(cid:1) Lowerratesbutstillabovecritical(perhaps300(cid:1)1000/2000bpd)
Beingabovecritical,thechoiceisavailabletoflowthewells.However,theuseofAL
can exceed the rates above even the most optimum flow situation (which can be deter-
mined by Nodal). So higher rate ALs such as ESP, gas lift, or other pumping systems
maybeusedtoacceleratetherateaboveflowingconditions.Lowersurfacepressurehelps
allALsandallabove-criticalflowingsituations.OnceALisselectedforthemid-rangeor
even higher rates, then the process of AL staging begins (from higher rate systems to
lowerratesystems).
Conditions may determine the method/s of lift. For instance, if the well is very gassy
orhassolidsthenonemaychoosegasliftforlong-termliftasexcessivegasmakesuseof
pumping systems more difficult. Also excesssive solids production and excesssive devia-
tionordog-legseveritycanmakeoneconsidersomethingotherthanpumpingsystems.
On the other hand, SRP systems are one of the most profitable methods of lift and
with not too much gas, solids, and well-deviation SRPs can be used for a wide range of
productionrates.
Othersystemshaveparticularadvantagesthatmayhelpwithselection.
(cid:1) Belowcriticalproduction
HereALisrequiredtopreventloading.
Plunger,surfactants,compression,pumpingsystems,andgasliftcanbeconsidered.
Pumps and then plunger could be sequentially applied. Or gas lift and then plunger
could be a strategy. Discussion of the lift possibilities in the following chapters will help
withtheselectionorstagingofliftpossibilities.
(cid:1) Lowtoverylowproductionrates
Beam pumps, hydraulics, and ESPs can be used to low rates. However, low rates for
ESPs can be damaging and a lower limit on production or special precautions should be
considered for EPSs at low rates. PCPs can be used for moderate to low rates but are
more depth-limited. Ineffective gas separation can lead to poor drawdown with pumping
systems.
Gasliftcanbeusedtolowratesbutasmallertubingallowsformoreefficientlift.
Plungers are designed for low rates and modified plunger lift sysstem such as GAPL
(gas-asssisted plunger lift) and progressive plunger lift (use of two or more plungers run-
ning in one well, i.e. one plunger moving up and down in the top part of the well and
another plunger moving up and down in the lower part of the well) can be efficient for
lowerratesandloweravailablewellpressures.Sandlimitsorpreventstheuseofplunger
lift.Againsand/deviation/gasproductiontendstoleadtogasliftforlongerlifeandfewer
problemsbutmostlikelynotasgoodofdrawdownundercertaincircumstances.
1.5 Most used systems for deliquification
ThetopmostusedfourALmethodsofdewateringareasfollows:
(cid:1) Plunger
(cid:1) SRPs
(cid:1) Surfactants
(cid:1) Gaslift
Augmenting the choices includes intermitting the well with no AL system, spe-
cial pumping systems, heating systems, velocity strings, compression (which should
6 GasWellDeliquification
be used in combination with all systems for maximum performance), combination
systems,andmore.
The best economical system or the most profitable system should be used. One
such economics decision might be to use plunger lift because it is cheaper to install
and operate but it may not give the best drawdown, especially with an on/off sys-
tem. You might then choose a pumping system but it would cost more initially,
also most likely cost more to operate, but might get better drawdown depending on
conditions and time spent operationally. It seems that the industry chooses a lot of
plunger because of lowinitial/operatingcosts, andtosave the time spent tojudge if
another system may produce more or slightly more. Plunger does pretty well for a
long time for producing rates for the lower range of liquids production. Some con-
ditions such as sand/solids, not enough gas/liquid ratio, or low-pressure build up
canruleoutplunger.
Allofthesefactorsarecoveredinmoredetailinthefollowingchapters.
Reference
1. Coleman SB, et al. A new look at predicting gas well liquid load-up. J Petrol Technol
1991;329(cid:1)32.
Further reading
Lea JF, Tighe RE. Gas well operation with liquid production. In: SPE 11583, presented at
the1983productionoperationsymposium,OklahomaCity,OK,February27(cid:1)March1;
1983.
LibsonTN,HenryJT.Casehistories:identificationofandremedialactionforliquidloading
ingaswells-intermediateshelfgasplay.JPetrolTechnol1980;685(cid:1)93.
