2013 Gas Well Deliquification Workshop
Technical Presentations
Session: I --- New Technologies,
Session Chair:
Challenges, General Topics
Kelli Poppenhagen
Presentation Title: I – 1
Company(ies):
Southern North Sea Velocity String
NAM
Installation Campaign
Author(s):
Contact Information:
Ewout Biezen
ewout.biezen@shell.com
Lucas Hoekstra
Albert Bootsma
Roel Aretz
Stefan Gesterkamp
Aykut Goncu
Abstract:
About 100 of the 300 offshore gas wells located in the Southern North Sea asset are currently liquid loading and this
number will steadily increase in future as depletion continues. A screening study was carried out to assess whether
the production from these liquid loaded wells can be economically extended by installation of either continuous foam
injection or a velocity string. This resulted in a 20-well velocity string campaign and a 50 well continuous foam campaign (not addressed in this presentation). The presentation describes the velocity string campaign i.e. velocity string
candidate selection, velocity string completion design, well and platform preparation, and actual velocity string installation plus production experience to date.
Solutions:
The velocity string hardware had to be modified to be successful: the seals on the velocity string hanger were
changed from wireline type to completion type to deal with the more challenging completion type deployment conditions; the hanger keys were chamfered to ease deployment; and a different type running tool was mobilized to prevent premature release. Finally a standard part of the VS design had a sliding side door below the subsurface safety
valve included to provide flexibility in the choice of flow path: annular deadstring flow or VS flow.
Results:
Large size (up to 2 7/8” OD) corrosion resistant coiled tubing velocity strings have been installed successfully so far
in 10+ Southern North Sea offshore gas wells. The installed velocity strings will provide a longer and stable production future for some of the more depleted gas assets in the North Sea, extending field life and improving ultimate recovery.
The campaign style execution provided the opportunity to improve performance, procedures and hardware during the
campaign which resulted in an acceptable job duration following the first two jobs which took much longer than expected.
Notes:
2013 Gas Well Deliquification Workshop
Page 2
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: I --- New Technologies,
Session Chair:
Challenges, General Topics
Kelli Poppenhagen
Presentation Title: I – 2
Company(ies):
Effect of Tube Wall Wettability on
TNO
the Onset of Churning In Upward
Delft
Gas-Liquid Annular Flow
NAM
Author(s):
Contact Information:
E.D. Nennie
erik.nennie@tno.nl
J.S. Groen
S.P.C. Belfroid
V. Khosla
C.A.M. Veeken
Abstract:
The production of hydrocarbon gas is often accompanied by liquid. As a result, annular flow is often found in well
tubes and pipelines used for the production and transport of hydrocarbon gas, with the liquid flowing partly as a thin
wavy film along the tube wall and partly as droplets entrained in the turbulent gas core. As the velocity of the gas
decreases, it becomes insufficient to drag the liquid upwards, leading to flow reversal and the transition from annular
to churn flow. As a result, liquid begins to accumulate at the bottom of the well, and eventually may block the production of gas.
Visualization experiments and experiments at different liquid-to-gas ratios and inclination angles are performed in
coated and uncoated steel and Perspex pipes of different diameters: 20 mm, 50 mm and 67 mm. Basic flow characteristics such as pressure drop and liquid hold-up were measured. Experiments with different angles ranging from 90°
(vertical) to close to horizontal (10°) were performed for the 20mm diameter tube. The impact of the wall wettability
on the flow patterns was examined by performing flow visualizations with a high speed camera in coated and uncoated Perspex tubes.
From the experiments if becomes clear that the hydrophobic coating prevents the formation of a liquid film on the
tube wall. As a result, the transport of the liquid phase is solely in the form of droplets/ligaments. In the hydrophobic
coated tube, the onset of churning is at a lower gas velocity than in the uncoated tube. The change in the flow patterns from annular to churn flow is reflected by a minimum in the measurement pressure drop, followed by a sharp
increase. The presence of the coating can reduce the superficial gas velocity corresponding to the minimum pressure
drop by as much as 50%.
Notes:
2013 Gas Well Deliquification Workshop
Page 3
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: I --- New Technologies,
Session Chair:
Challenges, General Topics
Kelli Poppenhagen
Presentation Title: I – 3
Company(ies):
Model the Effectiveness of Plunger
NAM
and Downhole Pump by Transient
SPT Group
Multi-Phase Flow Simulation
Author(s):
Contact Information:
Kees Veeken
Kees.Veeken@shell.com
Rahel Yusuf
Abstract:
Transient multi-phase flow simulations have been carried out to answer two important deliquification questions:

What is the effectiveness of a plunger that travels up to the subsurface safety valve but does not cover the short
distance between subsurface safety valve and wellhead? The outcome determines the requirement for a second
plunger to dewater the top section.

How much back pressure is introduced by the flowing wet gas column in the presence of a downhole pump that
removes liquids from the bottom of the well? The outcome determines the effectiveness of a downhole pump and
defines the best ways of operating a downhole pump.
The presentation provides model details and results, and compares model results against field data.
Notes:
2013 Gas Well Deliquification Workshop
Page 4
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: I --- New Technologies,
Session Chair:
Challenges, General Topics
Kelli Poppenhagen
Presentation Title: I – 4
Company(ies):
Product Enhancement, Asset ProIntegrity Management and Control
tection, and Human Safety
Author(s):
Contact Information:
Lance Witt
lwitt@integrity-measure.com
Abstract:
Why are chemicals utilized in oil and gas production and transmission? Chemicals improve the quality of hydrocarbon products by reducing and/or eliminating contaminants and predicted destructive events. Chemical treatments
also protect assets and human health. Typical contaminants to be mitigated include hydrogen sulfide (H 2S), carbon
dioxide, oxygen, water, paraffin, scale, and bacteria. Potentially destructive events include hydrate formation and
asset corrosion. In order to maintain the quality of the oil and gas stream component, the appropriate measurement
technology must be chosen and the correct methodology followed. An improper choice may lead to inaccurate measurements since chemical interferences can skew results. For instance, when measuring H 2S certain technologies
give false high readings due to interference from other sulfur compounds while lead acetate technology is not subject
to this interference. False high readings lead to excessive use of H 2S scavenger and a waste of financial resources.
Once contaminants and components of a stream are identified and quantified, the appropriate chemicals can be selected. A treatment plan takes into consideration physical properties of chemicals, process conditions, treatment locations, injection methods, pump rates and efficiency, nozzle discharge patterns, tank sizes, and other factors. The
most overlooked and misunderstood component of the system is the atomizer nozzle or liquid mixing probe. The optimal program consists of multiple components engineered as a system. Automation of this engineered system maximizes the efficiency of the chemical treatment while providing real time data. Pump rates are automatically adjusted
based on containment and chemical concentration data and tank level feedback. Operators treating for H 2S have
realized cost savings in the 90% range when the complete automated engineered system is utilized.
Notes:
2013 Gas Well Deliquification Workshop
Page 5
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: I --- New Technologies,
Session Chair:
Challenges, General Topics
Kelli Poppenhagen
Presentation Title: I – 5
Company(ies):
Intrinsically Safe Acoustic InstruEchometer Company
ment Used in Troubleshooting GasLift Wells
Author(s):
Contact Information:
Lynn Rowlan
lynn@echometer.com
Carrie Anne Taylor
Abstract:
Stringent safety requirements imposed by major operators when fluid level measurements are performed offshore or
in enclosed wellhead spaces such as in Alaska’s North Slope create procedural complications, such as the requirement for hot permits, when performing fluid level measurements in producing wells. This need has been eliminated
by the development of a small, self contained, fully digital, battery powered instrument that is approved for use in
hazardous areas. Examples from North Sea platforms and Alaska North Slope of acoustic liquid test of gas lifted
wells will be presented.
The signal from the liquid level echo and the signals that correspond to the echoes from the gas lift mandrels are
frequently identifiable on the acoustic trace. An “Anomaly” analysis method using the known depth of each mandrel
is used to accurately determine the liquid level depth. For this method the software initially places tick marks on the
depth axis that correspond to the depth of the known down hole markers in the well. The user then manually relocates the markers, starting with the topmost signal, at the exact point in time of the signal arrival. The acoustic velocity for that time interval is computed knowing the depth to the marker. This procedure yields a more accurate calculation of the liquid level depth especially in those wellbores where there are significant temperature variations, such as
in offshore platforms, or when the gas column is stratified.
The acquisition and interpretation of the data through an advanced software package automates the analysis even in
acoustically noisy environments. Results are observed immediately on the instrument screen then saved in the data
base for eventual transfer to external data base. This presentation shows detailed information about the new system
and reviews data acquired in gas lift wells.
Notes:
2013 Gas Well Deliquification Workshop
Page 6
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: I --- New Technologies,
Session Chair:
Challenges, General Topics
Kelli Poppenhagen
Presentation Title: I – 6
Company(ies):
Possible ALRDC R&D Projects
Artificial Lift R&D Council (ALRDC)
Author(s):
Contact Information:
Cleon Dunham
cleon@oilfieldautomation.com
Abstract:
Part of the Charter of The Artificial Lift R&D Council (ALRDC) is to sponsor, encourage, and/or promote artificial lift
R&D projects. ALRDC has an R&D Committee to oversee this activity. ALRDC is considering a number of potential
R&D projects. These will be explained in this presentation.
Notes:
2013 Gas Well Deliquification Workshop
Page 7
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: II --- Reservoir, StimulaSession Chair:
tion, Impact of Loading
Norm Hein
Presentation Title: II – 1
Company(ies):
Joint Industry Project: Predicting
TNO
the Gain from Deliquification
Measures For European Wells
Author(s):
Contact Information:
Wouter Schiferli
wouter.schiferli@tno.nl
J.P. de Boer
E.D. Nennie
Abstract:
In discussions with various operators, a clear demand was identified for increased application of deliquification
measures in North Sea wells.
A Joint Industry Project was set up to identify knowledge and experience gained in the United States on gas well
deliquification and transfer this to European wells.
In the first phase, a literature search was conducted. This provided a broad overview of the techniques used to
deliquify gas wells suffering from liquid loading and a set of available guidelines predicting the range of application.
Having identified potential techniques, a selection tool was developed which suggests the most suitable
deliquification technique for a given well.
The selection tool can predict the gains in production and ultimate recovery resulting from applying a range of
techniques:
Velocity string
Eductor
Wellhead compression
ESP
Foam
Gas lift
Plunger lift
Tailpipe extension
The selection tool is based on TPC (lift curve) analysis and IPR analysis; performance therefore also depends on
reservoir characteristics. For each of these techniques, a model was available or developed to simplify their operating
principles to a TPC.
Results from this tool can aid in deciding what mitigation measure to implement, as it gives a clear overview of the
production gain that is possible for the different techniques.
Notes:
2013 Gas Well Deliquification Workshop
Page 8
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: II --- Reservoir, StimulaSession Chair:
tion, Impact of Loading
Norm Hein
Presentation Title: II – 2
Company(ies):
The Effect of Surfactants on the Hy- NAM
drodynamics of Air-Water Flow for
Univ. of Delft
Gas Well Deliquification
Author(s):
Contact Information:
A.T. van Nimwegen
gert.devries@shell.com
L.M. Portela
R.A.W.M. Henkes
GJ de Vries
Abstract:
From experience in the gas industry, it is known that injecting surfactants at the bottom of the well prevents liquid
loading. Although this technique is frequently applied in practice, understanding the effect the surfactant has on the
flow in the well is still poor. Better knowledge and understanding of this effect is required to create a mechanistic
model for air-water-foam flow.
In this work, laboratory experiments were performed on air-water flow with and without added surfactants in a 12
meter long vertical Perspex pipe with an inner diameter of 50 mm at ambient conditions. Superficial liquid velocities
were varied from 2 mm/s to 50 mm/s and superficial gas velocities were in the range of 6 to 40 m/s. A high-speed
camera was used to visualize the flow. In addition, the pressure drop was measured to quantify the effect of the surfactants on the flow.
The formation of foam is caused by the interfacial morphology of the liquid film, leading to the entrainment of air bubbles into the liquid. At high gas flow rates, the ripple waves and the roll waves on the liquid film cause the formation
of foam. The presence of this foam leads to an increased interfacial friction and an increase in the pressure drop.
At low gas flow rates, the churning of the air-water flow leads to the creation of foam. The images recorded with the
high-speed camera show that the foam makes the flow more regular. It postpones the reversal of the liquid film towards lower gas velocities and suppresses the flooding waves that characterize unstable churn flow. From pressure
measurements, we found that the pressure drop significantly decreases at superficial gas velocities below 15 m/s.
Furthermore, the more regular flow leads to smaller oscillations of the pressure drop in time.
The regularization of the flow and the large decrease of the pressure drop at low gas velocities give insight into why
and how liquid loading in gas wells is prevented by the addition of foamers.
Acknowledgement:
The project is funded by NAM, a Dutch subsidiary of Shell and ExxonMobil. The authors would like to thank Gert de
Vries, Kees Veeken, Ewout Biezen and Ruud Trompert from NAM for the valuable discussions.
Notes:
2013 Gas Well Deliquification Workshop
Page 9
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: II --- Reservoir, StimulaSession Chair:
tion, Impact of Loading
Norm Hein
Presentation Title: II – 3
Company(ies):
Optimal Dead-Leg Tubing Length in
Shell EP
Long Perforated Completion Intervals
Author(s):
Contact Information:
Matt Vivian
Matt.Vivian@shell.com
Alec Walker
Abstract:
Dead-Leg Tubing Configurations are a good solution to lift liquid below top perforations in long multistage fracture treatment wells; however when the entry point is set too shallow it results in liquid across
the majority of the production interval and reduced production due to high Bottom Hole Pressures (BHP).
Long Perforated Completion Intervals common to gas wells present challenges for High Liquid Gas Ratio
(LGR) wells as plunger lift cannot unload sufficient fluid to total depth. Energy Added Lift solutions (gas
lift and pumps) would be ideal, but typically fail to meet economic hurdles in gas wells.
Often operating companies setup the well configuration as a Dead-Leg using standard tubing flow from
surface to the top perforation and annular flow between casing and tubing string run to bottom perforations to fill dead space as velocity reduction. While the annular flow is more effective than traditional tubing at top perforations, the Turner Critical Rate is still nearly double that of the upper tubing string and
thus ineffective at maintaining the liquid level near bottom perforations. Therefore it is best to minimize
the Dead-Leg length and flow the full well production down around the end of tubing and cycle a plunger
as deep as possible.
In the Pinedale Anticline Field of the Green River Basin over 100 wells have been configured with DeadLeg entry points and successfully applied plunger lift above the shallower entry point. With a 6,000' perforated interval the Dead-Leg had been placed at 25, 50, and 75% of the completion interval based on
the LGR. It has been found the well dictates optimal entry point based on downtime and slugging, but is
best setup with as deep an entry point as the LGR can handle and then move the entry point uphole.
Findings of field trials will be presented.
Notes:
2013 Gas Well Deliquification Workshop
Page 10
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: III --- Compression, GasSession Chair:
Lift, Velocity String
Kees Veeken
Larry Harms
Presentation Title: III – 1
Company(ies):
Two Short Topics: Using Compres- Consultant
sors More Effectively. Improving
Upon Poor-Boy Gas-Lift
Author(s):
Contact Information:
Jim Hacksma
jim.hacksma@comcast.net
Abstract:
Using Compressors More Effectively
Liquid loaded gas wells & compressors don’t work together very well. A common characteristic of loaded wells is
erratic production, sometimes falling almost to zero. However, compressors can’t tolerate such low gas rates. The
compressor can be starved for gas & quit due to low suction pressures. The result is excessive compressor downtime & poor production. Actual field data will be used to show how these problems can be overcome.
Improving Upon Poor-Boy Gas-Lift (PBGL)
PBGL has very limited application because of two significant limitations. 1) Because PBGL has no gas-lift valves, it is
not capable of handling large columns of liquid. 2) And, as with most gas-lift systems, PBGL requires an outside
source of gas. It will be shown, however; that with many gas wells both of these limitations can be overcome. It is
possible to lift moderate liquid volumes from many gas wells a) without gas-lift valves and b) without an outside
source of gas. Actual field data will be used to demonstrate how this is possible.
Notes:
2013 Gas Well Deliquification Workshop
Page 11
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: III --- Compression, GasSession Chair:
Lift, Velocity String
Kees Veeken
Larry Harms
Presentation Title: III – 2
Company(ies):
Plunger Assisted Gas-Lift
PCS Ferguson
Improving Lift Efficiency in Gas-Lift
Wells
Author(s):
Contact Information:
Darryl Polasek
Matt.Carpenter@pcslift.com
Abstract:
Problem being addressed: Operators face many challenges associated with reducing operating costs while maximizing well production. The goal is to achieve the most efficient and effective form of lift based on these considerations.
Challenges: There are many situations in which wells don’t have sufficient natural energy to move liquids to the surface at desired rates. Changing well conditions, such as reduced reservoir pressure, increasing water cuts and decreasing gas liquid ratios make consistent and predictable production challenging for operators.
Solution: Plunger lift and gas-lift are often considered independently lift methods. However, often they can be used
in combination to even greater effect. Plunger lift can be used to assist gas-lift wells with certain characteristics, specifically lower gas and higher liquid production. In continuous flow gas-lift wells with marginal flow characteristics, a
flow-thru/continuous flow plunger lift system can be installed in the well to assist in carrying liquids to the surface. The
gas-lift and plunger lift system work together to reduce the amount of injected gas and, consequently, lower the compression costs. Plunger assisted gas-lift improves lift efficiency in deviated and horizontal wells, is able to handle high
rates of fluid and is beneficial to the tubing as the plunger operation up and down prevents scale or paraffin from
forming on the inner tubing walls.
Results: Continuous flow gas-lift applications utilizing flow-thru/continuous flow plungers are being used successfully
and economically to improve lift efficiency. We will review the scenario when plunger assisted gas-lift has been effective, problems being addressed and our field experiences with these systems.
Notes:
2013 Gas Well Deliquification Workshop
Page 12
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: III --- Compression, GasSession Chair:
Lift, Velocity String
Kees Veeken
Larry Harms
Presentation Title: III – 3
Company(ies):
Inverse Gas-Lift System (IGLS)
Weatherford
Author(s):
Contact Information:
Rodger Lacy
Rodger.Lacy@eu.weatherford.com
Abstract:
Many wells are now reaching the stage that they may require to be gas-lifted in order to both maximize the life of well
and to increase production. IGLS allows a method of gas injection via an insert string. The system is designed to
maximize both gas injection and production flow paths with no reliance on annuli, and with a safety valve that fully
isolates both production and injection flow paths on closure. To date a coiled tubing string has been utilized below the
well control part of the system.
Gas injection is via a newly installed bore consisting of:

Intermediate spool and concentric hanger at surface,

Coiled tubing or pipe from surface to suspension hanger and dual flow safety valve installed in the existing
safety valve profile,

Coiled tubing to gas injection depth and gas injection valve.
Production is via the annular spaces and bores of the IGLS components and coiled tubing / pipe.
IGLS can be installed using traditional intervention techniques therefore making this a cost effective option to any
work over program.
Components of the IGLS can be used for other applications e.g. water injection systems, in order to dissolve salt
deposits that reduce production rates, and can also be combined with some of our Renaissance System components.
These systems offer a revival for troubled wells by expanding the productive life.
This paper will discuss the development of the IGLS system and describe the first installation in a UK North Sea well.
Notes:
2013 Gas Well Deliquification Workshop
Page 13
2013 Gas Well Deliquification Workshop
Technical Presentations
Session Chair:
John Green
Bill Hearn
Presentation Title: IV – 1
Company(ies):
Ball and Sleeve Plunger System Au- Anadarko Petroleum Corporation
tomation Algorithm Utilizing Ball Fall IPS Corporation
Rates
Author(s):
Contact Information:
B. Smiley
Jason.Carmichael@anadarko.com
J. Portillo
Abstract:
Session: IV --- Plunger Lift
Initial setup, configuration, and tuning of a ball and sleeve plunger lift system can be a tedious process for an operator that is new to the system. First, the operator must determine if the well is a ball and sleeve candidate by evaluating pressures and flow rates. Next, either based on experience or vendor supplied chart interpretation, the operator
must make decisions such as; ball and sleeve size, method of operation, and time and other inputs. Errors in these
decisions can lead to insufficient ball and sleeve separation causing short trips and increased liquid loading.
In this presentation we review the trial of a PLC program which incorporates ball fall calculations. The PLC program
iterates depth based on surface pressure and flow rate; shutting in the well when the ball reaches an inputted point
down the tubing string. Results are presented from testing the PLC program for several months utilizing two different
ball sizes on a single well.
Notes:
2013 Gas Well Deliquification Workshop
Page 14
2013 Gas Well Deliquification Workshop
Technical Presentations
Session Chair:
John Green
Bill Hearn
Presentation Title: IV – 2
Company(ies):
Automatic Plunger Lift Adjustment
Encana
Pilot Using Lean Methodology
Author(s):
Contact Information:
Kelli Poppenhagen
Kelli.Poppenhagen@encana.com
Abstract:
Session: IV --- Plunger Lift
Automatic plunger lift adjustment was implemented on 24 wells in the Encana South Piceance Mamm Creek Field in
Colorado using the Lean project methodology approach. The algorithm utilized makes adjustments to plunger lift
control settings based on plunger arrival time and also reacts to consecutive missed plunger arrivals. Production for
the 24 wells increased by 2.5% with the improvement as the program reacts to continuously changing surface pressures and liquid loads. The lease operator observed a one hour per day time burden savings as a result of the improvement. The project approach from definition to control will be shared including various Lean tools used.
Notes:
2013 Gas Well Deliquification Workshop
Page 15
2013 Gas Well Deliquification Workshop
Technical Presentations
Session Chair:
John Green
Bill Hearn
Presentation Title: IV – 3
Company(ies):
Minimizing Plunger Lift Risk
T-RAM Canada
Lynn Rowlan
Contact Information:
Carolyn Cepuch
Lynn@echometer.com
Abstract:
Session: IV --- Plunger Lift
This presentation will discuss flowing gas velocities plus plunger unloading and arrival velocity. Often operators think
that high pressure wells are more dangerous. High pressure gas wells have gas a velocity profile with less change
from the bottom to the top of the well. Low pressure gas wells have a dramatic change in velocity from the bottom to
the top of the well. Average plunger rise velocity is monitored by most controllers, but impact speed at the surface is
generally not known. Data collected on a low pressure well will show very high impact velocities can occur. As gas
wells are produced to lower reservoir and lower gathering pressures, more and more wells are becoming low pressure wells. The operator must be concerned about high velocity plunger impacts, due to the potential for damage
and greater risk. Point of impact speed is generally not known and this lack of knowledge leads to a false sense of
security.
Bumper spring and lubricator assemblies are designed to stop the plunger at the surface and prevent damage. Rather than continue “crashing” into striker blocks, let’s move them out of the way. Instead of driving your truck into the
wall and building bigger bumpers, quit driving into the wall. The concept of lubricator extension is a mechanism that
can be used to stop the impact of fast arriving plungers. The feature of extending the lubricator to stop a plunger was
observed during laboratory testing at the full scale well model. Features of the lubricator extension are the plunger
must clear the top outlet to allow for chamber compression and some liquid must be present.
Notes:
2013 Gas Well Deliquification Workshop
Page 16
2013 Gas Well Deliquification Workshop
Technical Presentations
Session Chair:
John Green
Bill Hearn
Presentation Title: IV – 4
Company(ies):
Comparison of Plunger Fall Model to Echometer Company
Field Data
PL Tech
T-RAM Canada
Author(s):
lynn@echometer.com
Lynn Rowlan
James F. Lea
Carolyn Cepuch
Rick Nadkrynechny
James McCoy
Abstract:
Session: IV --- Plunger Lift
A new plunger fall velocity model has been developed that predicts a plunger fall velocity in a well as different pressure conditions. This model is based on filed measured plunger fall velocities and laboratory measured fall velocity.
All plungers have the same general trend of fall velocity; where the plunger fall velocity is fast at low pressure and
slow at high pressure. Data acquired from various wells will be used to compare the measured fall velocity of different types of plungers to the predicted fall velocity by the new model. Some construction features of plungers cause a
plunger to fall rapidly, while other features cause the plunger to have a slower fall velocity. A particular plunger’s
known fall velocity at a specific pressure and temperature is input into the model and the model will calculate the fall
velocity at other pressures and temperatures. Published fall velocities can be used for each plunger type but may not
be accurate for all wells, because fall velocity is significantly impacted by well pressure.
By accurately knowing the plunger fall velocity, the proper shut-in time for the plunger lift installation can be determined. Use of an acoustic instrument is an effective method to determine a fall velocity during the shut-in time period
for input into the model. When changes to the well cycle impact the operating pressure, this new model can be used
to determine the change in time required for the plunger to fall to bottom during shut-in. Setting the well’s controller
to have the shortest possible shut-in time can maximize oil and gas production from the plunger lift well. Determining
the plunger fall velocity will allow the operator to set the minimum shut-in time for the plunger lift installation. Knowing the plunger fall velocity for specific well conditions will ensure that the plunger will reach the bottom of the tubing
by the end of the shut-in period.
Notes:
2013 Gas Well Deliquification Workshop
Page 17
2013 Gas Well Deliquification Workshop
Technical Presentations
Session Chair:
John Green
Bill Hearn
Presentation Title: IV – 5
Company(ies):
Dynamic IPR and Gas Flow Rate De- Echometer Company
termined for Conventional Plunger
Lift Well
Author(s):
Contact Information:
Lynn Rowlan
Lynn@echometer.com
Abstract:
Session: IV --- Plunger Lift
The tubing and casing pressure acquired during a conventional plunger lift well’s cycle can be used to determine the
Inflow Performance Relationship for the well and calculate the gas flow rate from the formation and down the flow
line. If the tubing and casing volume from the end of the tubing to the surface is thought of as a closed volume, then
the change in gas volume can be calculated from the measured surface pressures.
The cumulative production from the formation and the instantaneous gas flow rate down the flow line can be computed from the measured pressures, gas properties, and height of the gas free liquid in the tubing, plus the wellbore
configuration. Gas flow from the formation occurs during the entire cycle whether the flow line valve is open or
closed, as long as the flowing BHP is less than the reservoir pressure. Generally there are two peak instantaneous
gas flow rates down the flow line, one peak occurs at the beginning of the unloading period when the flow line valve
is first opened and a second peak gas flow rate occurs at the beginning of the afterflow period immediately after the
plunger arrives at the surface. The initial high gas flow rate is due to gas stored in the tubing above the plunger and
the second high gas flow rate is due to gas accumulated behind the plunger which lifted the plunger and liquid to the
surface.
In a conventional plunger lift well these calculated instantaneous gas flow rates are reasonably accurate. If there is
high gas velocities in the tubing, then the frictional effects can cause gas to stack in the tubing then the flow rate is
impacted by pressure drop due to friction. The Dynamic IPR of the well determined from one complete conventional
plunger lift cycle can be used to calculate the flow from the formation when the flow line valve is open or closed.
Notes:
2013 Gas Well Deliquification Workshop
Page 18
2013 Gas Well Deliquification Workshop
Session: IV --- Plunger Lift
Presentation Title: IV – 6
Plunger Lift Report Card
Author(s):
Rick Nadkrynechny
Lynn Rowlan
Carolyn Cepuch
Abstract:
Technical Presentations
Session Chair:
John Green
Bill Hearn
Company(ies):
T-RAM Canada
Echometer Company
Contact Information:
lynn@echometer.com
A new software tool allows the operator to generate a report card on his Plunger Lifted well. Data can be manually
entered into the system or loaded from an EXCEL plunger inspection form that has been performed on location at the
well site. A Plunger Wizard button provides interactive help for inputting the well’s current plunger information.
Once you have the complete well information, then click grade to view the results examine any apparent issues.
Suggestions for improving operation of the well will be listed in the results box. This system provides a systematic
approach to identifying and solving plunger lift problems.
Following are examples of several report card suggestions:
1) There appears to be an unnecessary pressure drop of 234kPa between the wellhead and separator. Check
for things like undersized choke trim or hydrates in line.
2) An average orifice differential of 1670kPa is a high for optimal performance. If possible an increase in orifice
plate size would help increase production.
3) One or more arrival speeds was greater then 300m/min, which depending on plunger mass is dangerous.
Think about looking into why this happened and ensure it doesn’t happen regularly.
4) Your fast shut down time of 6.5min allows for arrival velocities up to 387m/min. Depending on plunger mass,
this can be dangerous and can result in damaged equipment. Consider lowering this to something near
11.2min.
5) There are factors that can cause non arrivals where it may be necessary to shut down the well. These factors can include: The plunger may not be dropping, which can load up the well, or the plunger may actually
be arriving and not be sensed by the controller which can cause damage to equipment.
6) It is important to gauge the cap threads to check for signs of stretching caused by possible high force impacts.
7) A passing choke can cause the well to load up during the off cycle by allowing liquid and gas to continue to
enter the tubing. The valve needs to be serviced.
Notes:
2013 Gas Well Deliquification Workshop
Page 19
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: V --- Chemicals --- SelecSession Chair:
tion, Installation, Optimization
Fenfen Huang
Presentation Title: V – 1
Company(ies):
Optimizing Chemical Injection
ABB Totalflow
Author(s):
Contact Information:
Dave Barry
dave.barry@us.abb.com
Abstract:
I have developed a program to optimize chemicals. The first installation was on a Chesapeake location and they
reported that they cut chemical usage by 85% and increased production by 35%. As you may know Chesapeake has
been cutting back and sadly they shut this well in. We are presently installing some for ConocoPhillips and BHP with
several other companies very interested.
The installations we have done have been with the TXAM pumps. I am sure someone from TXAM or one of the producing companies would want to join me, if this presentation is approved.
Notes:
2013 Gas Well Deliquification Workshop
Page 20
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: V --- Chemicals --- SelecSession Chair:
tion, Installation, Optimization
Fenfen Huang
Presentation Title: V – 2
Company(ies):
Foamer Application to Optimize
Nalco Company
Production of Horizontal Wells
Author(s):
Contact Information:
Fenfen Huang, et al
fhuang@nalco.com
Abstract:
Efficient and effective removal of liquid in the low gas rate natural gas wells is key in optimizing the tail-end production. Many mechanical and chemical artificial lift methods have been successfully utilized by the oil and gas industry
to manage the liquid deliquification for mature vertical gas wells with the aid of various modeling tools to predict the
liquid loading.
Horizontal drilling has played a critical role in the development of the natural gas shale plays. For the horizontallydrilled natural gas wells, their undulating trajectory with low spots for liquid accumulation, and/or deeper well toe than
the heel, can cause earlier onset of liquid loading and also complicate the understanding and deliquification remedy
of these wells compared to vertical wells. While mechanisms and modeling of liquid loading in horizontal wells have
attracted interest of many studies, this presentation will focus on the application of chemical foamers to optimize the
production of horizontal natural gas wells. Laboratory development of the chemical solutions, technology execution in
the field, and successful case studies illustrating benefits gained from the chemical foamer program in horizontal
wells will be demonstrated.
Notes:
2013 Gas Well Deliquification Workshop
Page 21
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: V --- Chemicals --- SelecSession Chair:
tion, Installation, Optimization
Fenfen Huang
Presentation Title: V – 3
Company(ies):
Chemical Pellet Trials
BP
Author(s):
Contact Information:
Paul Nguyen
Paul.Nguyen@bp.com
Abstract:
Chemical Pellet is a solid controlled-release additive that slowly desorbs overtime. In brine water it is slow dissolving,
producing a continuous treatment to inhibit scale/paraffin.
The BP Operation Team is currently facing challenges with:
1) Cost and timing of installation.
2) Maintaining current continuous injection.
a. Refilling chemical (PM work). We found wells that have injection but no chemical.
b. There are wells with injection but it’s not working.
3) Frequency of batch treatment not clearly communicated.
a. Missed bi-weekly batch treatment.
b. Wells that are waiting for rig work are continuously being batched without any production.
4) Treatment effectiveness.
a. Batch treatment causing wells to log off.
b. The rate of continuous treatment has to manually adjusted overtime.
Chemical Pellet will benefit the following:
1) Significantly reduce field personnel’s exposure to hazardous chemical and mechanical equipment associated with continuous chemical injectors.
2) Reduce well work relating to stuck/plug tubing due to scale/paraffin.
3) Reduce maintenance failure that can result to rig work.
4) Directly treat the downhole wellbore.
5) Rate of treatment will depend solely on water rate.
Evaluation process includes:
1) Economic over 10 years comparing Continuous Injection vs. Batch Treating vs. Chemical Pellet
2) Pressure Loss Gradient from Prosper to evaluate pressure loss between the sand-screen and seating nipple. Thus, evaluate risks of losing gas rate due to friction.
3) Evaluate MSDS with HSE and Corrosion Engineers to ensure no corrosion or safety risk with this product.
Notes:
2013 Gas Well Deliquification Workshop
Page 22
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: V --- Chemicals --- SelecSession Chair:
tion, Installation, Optimization
Fenfen Huang
Presentation Title: V – 4
Company(ies):
Foam Injection via Capillary String
Shell EP
in Vicksburg Dry Gas Wells
Author(s):
Contact Information:
Adam Pitman
Chandran.peringod@shell.com
Abstract:
Notes:
2013 Gas Well Deliquification Workshop
Page 23
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: V --- Chemicals --- SelecSession Chair:
tion, Installation, Optimization
Fenfen Huang
Presentation Title: V – 5
Company(ies):
Correlating Laboratory Approaches
Multi-Chem, A Halliburton Service
to Foamer Product Selection for Gas
Well Deliquification
Author(s):
Contact Information:
Shane Rorex
shane.rorex@halliburton.com
Abstract:
Proper product selection is critical when designing a liquid foamer treatment program for gas well deliquification. The
proper liquid foamer can provide an incremental increase in gas production by working at the interface between liquid
and gas to lower the overall density of reservoir fluids and lower the critical rate for that well, allowing large volumes
of fluid to be removed from the wellbore. Liquid foamers are typically selected based on the results of foam testing
using live reservoir fluids. Foam height and stability are important criteria that are practically correlated to the efficacy of the well deliquification.
For this project, an additional approach is introduced for determining compatibility between reservoir fluids and liquid
foamers and correlating the laboratory results to the field performance. By comparing the results of surface tension
testing on different liquid foamer base materials, different concentrations, and different synthetic brines, we have
found that the foamer performance can be correlated to its dynamic diffusion behavior to the interface between air
and brines and stability of critical micelle concentration. This information can be used in conjunction with field foam
testing to more accurately predict the expected field performance of a particular liquid foamer
Notes:
2013 Gas Well Deliquification Workshop
Page 24
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: V --- Chemicals --- SelecSession Chair:
tion, Installation, Optimization
Fenfen Huang
Presentation Title: V – 6
Company(ies):
To the Heel and Beyond with Soap
Pro-Seal Lift
Sticks
Author(s):
Contact Information:
Dan Casey
dan@prosealinc.com
Abstract:
Contrary to a popular misconception, the gas well operator should not send the soap stick into the rat-hole and the
requirement to shut-in a flowing gas well is the exception, not the rule. Horizontal completions present a challenge to
proven artificial lift methods but, if used correctly, soap sticks remain the first choice solution for low cost, early, effective intervention. For the purpose of de-watering with soap sticks, this paper will define the transition from vertical to
horizontal profile (it changes), when the well must be shut-in, the duration of shut-in if required, the quantity of soap
sticks to use, the depth at which the stick is to land and the preferred frequency of use.
The author has assisted in the deployment of 8 to 10 million soap sticks in the past 12 years over every major basin
in the US. This presentation will explode certain fallacies related to the use of soap sticks and offer details on the
best use of soap sticks over the wide variety of gas wells extant. Examples will include the successful use of soap
sticks in tubingless completions when running tubing is difficult or expensive.
Notes:
2013 Gas Well Deliquification Workshop
Page 25
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: VI --- Automation, Optimi- Session Chair:
zation
Scott Campbell
Presentation Title: VI – 1
Company(ies):
Choke Management in Tight Gas
Acock Engineering
Reservoirs
Author(s):
Contact Information:
Sheldon Cote
sheldon.cote@bp.com
Abstract:
Choke management is a strategy utilized in higher pressure wells (+600 psi shut in pressures) to maintain constant
and stable flow at the wellhead. The strategy is used on new and old wells where reservoir pressure is preserved.
A choke is implemented to stabilize initial flow backs at completion and during regular production phases on older
wells. The strategy utilizes a choke or flow control valve in the flow stream at surface.
The choke is managed to control flowing wellhead pressures above sales or line pressures while minimizing rate
deferral.
Choke management helps protect against line pressure increases. The choke model is controlled either manually or
through automated control and algorithm. The intent of choke model is to stabilize instantaneous flow rates on new
wells, and flatten decline on existing wells.
The strategy works well in both high and low LGR wells. Stabilized instantaneous flow helps protect newly placed
stimulations and allows for better control over surface facilities and flow management.
When managed properly the strategy can flatten decline on higher pressure wells with higher fluid rates.
Choke management has shown the ability to naturally flow wells with LGR's as high as 400 Bbls/mill.
Choke management also helps keep condensate in phase downhole minimizing dropout and added flowing friction in
the wellbore.
Notes:
2013 Gas Well Deliquification Workshop
Page 26
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: VI --- Automation, Optimi- Session Chair:
zation
Scott Campbell
Presentation Title: VI – 2
Company(ies):
Closed Loop Control of Free FlowApplied Control Equipment
ing Gas Wells
Author(s):
Contact Information:
Al Majek
jschrader@appliedcntrl.com
Mark Mauk
Mike Gabel
Abstract:
Sizable drilling programs in the shale plays of North America have bought about a massive number of
free flowing wells. Maintaining optimal performance for so many sites can prove to be a formidable challenge.
To fulfill this need, producers have flow from each well manipulated via a single automated choke valve.
The primary focus of the system is to maintain a steady flow from the well to the sales line based on an
operator entered set point. Multiple overrides come into play based upon operating conditions. Measurements include delta pressure and flow rate from an orifice run feeding a sales pipeline, and static
pressure and temperature of the flow line feeding a separator.
Specific issues addressed include start-up sequencing, liquid loading, maintaining critical velocity, and
transient flow conditions.
Notes:
2013 Gas Well Deliquification Workshop
Page 27
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: VI --- Automation, Optimi- Session Chair:
zation
Scott Campbell
Presentation Title: VI – 3
Company(ies):
Plunger Lift I/O
Freewave Technologies
Author(s):
Contact Information:
Jim Gardner
jdouglas@catapultpr-ir.com
Abstract:
Artificial lift technologies are increasingly popular for optimizing upstream solutions such as oil and gas production.
The objective of artificial lift is to allow oil and gas producers to automate and optimize well production, as well as
minimizes maintenance and life cycle costs. The key to artificial lift is to build enough downhole pressure to lift the
fluid to the surface. In order to improve this process, producers utilize a plunger, or valve, to assist with lifting the
fluid.
Oil and gas measurement and automation technicians and engineers have been tasked with retrieving more data and
doing more with less. However, new drilling and production technologies have created the need for new automation
techniques. The conventional approach of putting a flow computer or controller (RTU and PLC) on each well head
quickly becomes redundant, and excessively expensive. The integration of new production technology created a
need for advanced automation techniques, particularly with wireless instrumentation. With new wireless input/output
(I/O) technology, operators can easily install and manage an automated plunger lift system.
There are dozens of wireless instrumentation products that have come into the market over the past 5 years. Manufacturers have risen to the challenge of creating new products to provide new solutions to the automation challenge.
Each manufacturer has taken a different approach to solving these challenges. Understanding your data requirements and matching the differing products to your application is what you really need to consider.
This presentation will explore a new approach and new criteria for automated plunger lift and will aim to help producers understand the needs of their own system. Additionally, a focus on the communication layers of a system will
help attendees understand the value of wireless I/O and learn how to eliminate redundancies and enable fail safe
capabilities in case communication is lost.
Notes:
2013 Gas Well Deliquification Workshop
Page 28
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: VI --- Automation, Optimi- Session Chair:
zation
Scott Campbell
Presentation Title: VI – 4
Company(ies):
Hybrid Communication Networks
Freewave Technologies
Author(s):
Contact Information:
Dan Steele
jdouglas@catapultpr-ir.com
Abstract:
The concept of automation is a primary driver of competitiveness for all types of organizations, but, increasingly it is
critical for oil and gas companies looking to improve upon their pipeline monitoring efforts. These companies have
faced countless regulatory compliance issues, especially due to recurring accidents and events that have made front
page news. This has elevated concerns to the extent that government entities across the world continue to produce
legislation directed specifically toward improving safety standards in regards to corrosion and cathodic protection
(CP) practices. In an industry saturated with many pipeline monitoring solutions, it is critical for operators to understand which technologies are best suited for their pipeline infrastructure and its impact on their CP efforts. Sometimes, it makes the most sense to take a hybrid approach and leverage several solutions for a company’s asset monitoring needs.
Obviously, the key building block to a cost-effective, pipeline integrity, corrosion protection program is vital, timely
monitoring and reporting of CP data. There are several data communication technologies available today to help automate key functions within an organization, including, cellular, satellite, licensed and spread spectrum wireless data
radios, fiber and wire.
Traditionally, companies with large geographically dispersed communication networks typically have selected one
technology, one source, one vendor to collect, retrieve and report data to assess the health of their pipeline infrastructures. However, there is a new paradigm today in which organizations are breaking away from tradition and deploying multiple communication technologies to create a hybrid communications network that can better serve an
organization’s needs. Now there are many different technologies available to:

Drive maintenance/monthly costs down – directly impacting the bottom line,

Decrease polling cycle times and reducing the time needed to identify and remedy problems within the network,

Eliminate system “pinch points” – or single points of failure.
Notes:
2013 Gas Well Deliquification Workshop
Page 29
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: VI --- Automation, Optimi- Session Chair:
zation
Scott Campbell
Presentation Title: VI – 5
Company(ies):
Fully Automated Fluid Level MeasRAG Rohöl-Aufsuchungs Aktiengesellurement Tool – Applications in Oil
schaft
Production and Gas Well Dewatering
Author(s):
Contact Information:
Christian Burgstaller
Christian.Burgstaller@rag-austria.at
Abstract:
A fully automated fluid level measurement tool was developed recently. The paper describes the technical features of
the tool and summarizes via case studies the results of the field tests on various ESPs (electrical submersible
pumps) and sucker rod pumps running with and without VSD (Variable Speed Drive) both in oil production and gas
well dewatering applications.
The unique feature of this system is its fully automated and purely electronic functioning. The measuring device is
enclosed, mounted on the casing valve, has a pressure rating of 5000 psi and works with zero emissions on the environment (no outlet of casing gas). Compared with a conventional down hole pressure sensor, mounted on an ESP,
the system is insensitive to high well fluid temperatures and simple to maintain due to its easy access on surface
location. It additionally has a sampling rate of down to one measurement per minute. The measured fluid level data
can be transmitted via a SCADA system.
The measurement tool can be run down hole pumps in a more safe way. It can be used to avoid pump-off conditions
and the resulting serious equipment damage. It can also be used to control a VSD to keep the fluid level in a well at
a specific depth to avoid down hole flow conditions below the bubble point pressure in oil production. Due to the
availability of online fluid level data, all kind of pumps (e.g. ESP, Sucker Rod, PCP, and Jet Pump) can be operated
safely at more aggressive production rates. Furthermore possible applications of acoustic well diagnosis, also a feature of the tool, which is currently under scientific investigation, are presented.
Notes:
2013 Gas Well Deliquification Workshop
Page 30
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: VII --- Pumps, ESP, PCP,
Session Chair:
Hydraulic
Rob Sutton
Presentation Title: VII – 1
Company(ies):
Hybrid Hydraulic Dewatering: Lower Cormorant Engineering
Cost – Increased Prod.
Author(s):
Contact Information:
Dave Bolt
Travis@cormorant.us.com
Ken Newman
Travis Bolt
Abstract:
Cormorant Engineering developed a new method of hydraulic deliquification. The system addresses the problems
that arise with fitting a dual acting pump into production tubing. Traditional dual acting hydraulic pumps require three
conduits. This is costly and typically unfeasible in through tubing applications.
Cormorant has developed in conjunction with Conoco Phillips a new method for achieving a dual acting system with
a single acting pump. This new system (referred to as a 1.5 acting system) allows a single acting pump deployed with
single coiled tubing yet operates as a double acting system. The system operates through a patented power down
pump that allows for optimized area ratios that virtually offset the density difference in oil and water. The power down
pump minimizes moving parts and complex flow paths, helping to decrease risk of failure. The combination of the
two concepts allows hydraulic dewatering applications for depths up to 15K while maintaining a hydraulic pressure
less than 3000 psi.
The 1.5 system operates like a traditional single acting system by applying and releasing hydraulic pressure as well
as alternating the pressure on the produced water conduit. This action turns a single acting hydraulic pump into a
dual acting pump while maintain the simplicity of a single acting pump. This system allows for a 50% to 100% increase in produced fluid production over a traditional single acting system, while maintaining the downhole cost of a
single acting system.
Notes:
2013 Gas Well Deliquification Workshop
Page 31
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: VII --- Pumps, ESP, PCP,
Session Chair:
Hydraulic
Rob Sutton
Presentation Title: VII – 2
Company(ies):
Factors that Affect the Reliability of
UPCO, Inc.
Couplings
Author(s):
Contact Information:
Erik Tietz
ASriraman@upcoinc.com
Arun Sriraman
Abstract:
Failures in the sucker rod industry can be costly and time consuming. As an end user in this industry, it is very critical to understand the mechanics behind couplings. This paper addresses some of the important aspects of couplings
which play an important role in the overall reliability of the rod string. The topics addressed in this presentation are as
follows:
1.
2.
3.
4.
Strength of material analysis of coupling and sucker rods.
What happens to a sucker rod coupling joint during an improper make up process?
Types of manufacturing processes for couplings.
Recommended field practices.
Notes:
2013 Gas Well Deliquification Workshop
Page 32
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: VII --- Pumps, ESP, PCP,
Session Chair:
Hydraulic
Rob Sutton
Presentation Title: VII – 3
Company(ies):
Evaluation and Performance of
Echometer
Packer-Type Downhole Gas Separa- Univ. of Texas
tors
Author(s):
Contact Information:
Jim McCoy
jim@echometer.com
A. L. Podio
O.L. Rowlan
D. Becker
Abstract:
Many downhole gas separators are inefficient, and the percentage of liquid in the pump is actually less than the percentage of liquid in the fluids in the casing annulus surrounding the gas separator. This presentation discusses a
new packer type gas separator design increases separation capacity and efficiency. The separator design can be
used with a conventional packer or a special pack-off assembly consisting of elastomer rings on a tube positioned
between the separator and the tubing anchor below the separator. The pressure drop across the separator is generally less than 10 psi so flexible elastomer rings can be used instead of a high pressure packer.
The separator is generally used with a tubing anchor, and the tubing anchor should be positioned immediately below
the separator instead of above the separator, because field data indicates that the tubing anchor can cause an accumulation of gas below the tubing anchor and considerable liquid accumulation above the tubing anchor.
A separation technique that diverts the formation fluids into the casing annulus above the pump inlet is used to increase gas separation from liquids efficiently by using the larger area in the tubing/casing annulus. A seating nipple
is positioned within inches of the liquids that exist in the casing annulus surrounding the gas separator to reduce the
pressure drop so that gas is not released from the oil that flows from the casing annulus into the pump chamber.
This presentation describes techniques for evaluating the effectiveness of downhole gas separators. Often times, the
evaluation of a separator’s performance is based on pump fillage and the total gas production from the well instead of
the amount of gas present in the gaseous liquid column that exists in the casing annulus surrounding the pump.
Notes:
2013 Gas Well Deliquification Workshop
Page 33
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: VII --- Pumps, ESP, PCP,
Session Chair:
Hydraulic
Rob Sutton
Presentation Title: VII – 4
Company(ies):
Selection of Downhole Gas SeparaEchometer Company
tor
University of Texas
Author(s):
Contact Information:
Jim McCoy
Lynn@echometer.com
Tony Podio
Lynn Rowlan
D. Becker
Abstract:
Selection of a properly sized downhole gas separator is critical for efficient trouble-free operation of sucker rod
pumps used in deliquification of gas wells. When feasible to correct inefficient downhole gas separation, the first
attempt should be to set the pump below the gas entry zone. This is the most efficient method of downhole gas separation. However, in horizontal wells the pump cannot be set below the gas entry zone, and a gas separator should
be used below the pump that offers efficient gas/liquid separation.
Downhole gas separators can be divided into different types. If the gas separator is placed below the gas entry zone,
a single dip tube type of a gas separator should be used below the pump’s seating nipple. If the gas separator is
placed in or above the fluid entry zone, then for lower capacity wells a gas separator assembly should be used that
consists of an outer barrel having ports at the top of the barrel with a dip tube extending from the pump inlet down
into the outer barrel and opening below the ports. If a higher capacity gas separator is required, then the formation
fluids must be diverted into the larger diameter casing annulus for gas separation.
One of the most basic ideas to consider is the separation of gas from liquid is achieved through GRAVITY separation
without the introduction of other mechanisms (centrifugal forces, nozzles, etc.). Also, when the velocity of the gas
flow is too high, then turbulence and mixing of the gas and liquid will be detrimental to the separation process.
This presentation will provide guidance in the proper selection of downhole gas separator. Discussing the impact of
gas entry zone, liquid rate, pump capacity, gas velocity, casing pressure buildup, and other critical parameters that
impact the selection of a gas separator.
Notes:
2013 Gas Well Deliquification Workshop
Page 34
2013 Gas Well Deliquification Workshop
Technical Presentations
Session: VII --- Pumps, ESP, PCP,
Session Chair:
Hydraulic
Rob Sutton
Presentation Title: VII – 5
Company(ies):
Wellbore Gas/Liquid Separation
Muleshoe Engineering
Author(s):
Contact Information:
David Simpson
zdas04@muleshoe-eng.com
Abstract:
Field observations have shown for many years that on pumping wells it is very common for the gas flowing up the
tubing/casing annulus to be free of liquid. This has been especially noticeable when the downhole pump was directed
to an on-site tank or to a water gathering system. Many operators have interpreted this observation to imply that the
annular space is acting as a separator--a very long skinny separator that has fairly poor separation efficiency per unit
length, but that has a lot of unit lengths. This paper evaluates some of the critical flow models to determine the flow
rates that would allow a well to flow to sales without an on-site separator.
The other side of the coin is the gas that flows through the pump. Every pump allows some amount of gas to flow
with the pumped liquid, but historically producers have had to accept this “pumped gas” as a necessary evil and live
with very high water-gathering pressure, excessive gas in produced water tanks, and lost revenue. This paper concludes with a discussion of a technique to allow the power of the downhole pump to recover pumped gas for sale.
Notes: