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14 - 16 October 2013
Hampshire Hotel, Plaza Groningen
Laan Corpus den Hoorn 300,
Groningen – Netherlands
8th European
Gas Well
Deliquification
Conference
& Exhibition
Contents
Organising comittee
Exhibitors and map
Schedule
Classes
Social event details
Conference abstracts
Breakouts & collaboration
material
Participants
p 3
p 4 - 5
p 6 - 8
p 9
p 10
p 11 - 29
p 30 - 38
p 39 - 43
2
Organising comittee
Gert de Vries
+ 31 6 12088408
Kees Veeken
+ 31 6 51544050
Alyssia Janczak
+ 31 6 19268305
Ewout Biezen
+ 31 6 51920397
Janny Benschop-Jeuring
+31 6 10967871
Michiel de Kroon
+ 31 6 51920211
3
Exhibitors and sponsors
4
Exhibition Layout map
5
Schedule 14th Oct. 2013
Short courses - Auditorium
6
time event
07:30 Registration & Coffee
08:00 A- Compression using surface jet pump - Sacha Sarshar (Caltec)
09:45 Coffee break
10:15 B- Basics of gas well deliquification - Kees Veeken (NAM)
11:45 Lunch
12:45 C- Foam lift - Steven Oude Heuvel & Craig Adelizzi (Nalco Champion)
14:45 Tea break
15:15 D- Plunger lift & Acoustic surveillance - Lynn Rowlan (Echometer)
17:15 Drinks and Exhibition
Schedule 15th Oct. 2013 Conference Day 1: Field Cases,
Deployment Challenges & New Technology
time event 07:30 Registration & Coffee
08:00 Welcome & Opening remarks - Kees Veeken (Facilitation, Opening)
08:15 Keynote speech - Neil Wallace - Vermilion Energy (Managing Director - Netherlands BU)
08:30 Gas well life extension - Sven Tummers, M. Ottevanger, J. Regelink (Vermilion)
09:00 GWD Solutions - Will Vallejo (Schlumberger)
09:30 Velocity string and WRFM campaign in Southern North Sea - Ewout Biezen (NAM)
10:00 Coffee break - Ewout Biezen (Facilitation)
10:30 Application of surface jet pumps to deliquify oil and gas wells - recent field examples - Sasha Sarchar (Caltec)
11:00 Compressco dewatering system on liquid loaded wells in Italy - results and best practices - Pasquale Imbo, Alessandro Aleandri (ENI), Kevin Book (Compressco)
11:30 Inverse gas lift using dual flow SSSV - first North Sea multiwell campaign - Norman Strachan (Weatherford)
12:00 Lunch - Gert de Vries (Facilitation)
13:00 Meeting discharge limits for production fluids during deliquification and drilling - Mike Smith (PWA)
13:30 Retrofit surfactant injection around SCSSV - first North Sea multiplatform campaign - Brian Marr (Weatherford)
14:00 Experimental foam injection selection - Pejman Shoeibi Omrani, Erik Nennie, Wouter Schiferli (TNO)
14:30 Tea break
15:00 Breakout: Populate questionnaire posters & Discuss results informally - Kees Veeken (Introduction) + Theme Moderators
16:30 Wrap-up - Michiel de Kroon (Closing)
16:45 Drinks & Exhibition
18:00 Evening event - Coach leaves Hampshire Hotel - Drinks in Museum Wierdenland & Dinner in De Allersmaborg, both located in Ezinge
22:00 Evening event - Coach leaves Ezinge to return to Hampshire Hotel 7
Schedule 16th Oct. 2013 Conference Day 2: Field Cases,
Deployment Challenges & New Technology
time event 07:30 Registration & Coffee
08:00 Welcome back & Opening remarks - Michiel de Kroon (Opening, Facilitation)
08:15 Breakout: Feedback questionnaire results & Identify collaboration topics - Topic facilitation
10:00 Coffee break - Michiel de Kroon (Facilitation)
10:30 Production optimisation from liquid loading wells - Shona Neve (BOL-Chevron)
11:00 Challenges and successes in Gas Well Deliquification in OMV-Petrom, Romania - Vasile Stanculescu (OMV-Petrom)
11:30 Applications for magnetic sensing in plunger lift - Marc Scantlebury (Extreme Telematics Corp.)
12:00 Lunch - Alyssia Janczak (Facilitation)
13:00 Effect of tube wall wettability on onset of churning in upward gas-liquid annular flow - Eric Nennie, Stefan Belfroid (TNO), Kees Veeken (NAM)
13:30 Dynamic IPR and gas flow rate can be determined from measured surface pressure - Lynn Rowlan (Echometer)
14:00 Experiments on gas well deliquification in inclined pipes - Dries van Nimwegen, Luis Portela, Ruud Henkes (TUD), Gert de Vries (NAM)
14:30 Tea break - Alyssia Janczak (Facilitation)
15:00 Field trial update on innovative gas well deliquification pump - Norman Liley (Zilift)
15:30 Development of New Hydraulic Piston Pump Systems David Bolt (Cormorant), and Bert Lugtmeier (NAM)
16:00 Application of Electrical Submersible Pump for GWD – RAG’s experiences - Christian Burgstaller (RAG)
16:30 Wrap up, raffle & Conference close out - Kees Veeken (Closing)
8
Classes 14th Oct. 2013
A- Compression using surface jet pump
by Sacha Sarshar (Caltec)
B- Basics of gas well deliquification
by Kees Veeken (NAM)
C- Foam lift
by Steven Oude Heuvel
& Craig Adelizzi (Nalco Champion)
D- Plunger lift & accoustic surveillance
by Lynn Rowlan (Echometer)
In Auditorium
9
Social event 15th Oct. 2013
Drinks in Museum Wierdenland
& Dinner in De Allersmaborg
Practical information
Attendance is limited ; only people with a ticket will be able to attend
(based on online registration). If you have one but are no longer planning to
join, please let the organising comittee know, so that your ticket can be
given to someone else.
Coaches will leave the Hampshire hotel at 18:00 and bring you back to the
Hampshire hotel (depart from Ezinge at 22:00).
Adresses:
The Allersmaborg is built in a meander of the Reitdiep between Ezinge and
Aduarderzijl. The oldest part of the building dates from the 15th century.
The building is surrounded by a large ditch, featuring a drawbridge and
windbreaks. A 18th century dovecote is also to be seen.
De Allersmaborg
Allersmaweg,
64 9891 TD, Ezinge Nederlands
Museum Wierdenland
Van Swinderenweg 10, Ezinge
Netherlands
10
Conference Abstracts
Keynote speech
by Neil Wallace, Vermilion Energy
(Managing Director – Netherlands Business Unit)
Experience: More than 20 years of industry experience, with a strong and
diverse background in operations, financial management, and business
development assessments. Prior to joining Vermilion in 2004, Neil was the
Finance Manager for Chevron's Western Canadian business unit. During his
12 year tenure at Chevron, Neil also gained experience as an operations
supervisor and a budgeting and financial analyst. At Vermilion, Neil has held
roles as a Corporate Planner and most recently as Vermilion's Operations
Controller.
Education: BSc Geology (Honours) University of Saskatchewan (1988),
B.Comm University of Calgary (1992), Certified General Accountant
Designation (1999)
11
Gas Well Life Extension
S.W. Tummers, M. Ottevanger, J. Regelink (Vermilion)
12
Abstract:
Vermilion has many wells in its portfolio that operate in the tail end of their
production range. Vermilion has installed around 40 velocity strings between
2005 and 2012 with a high success rate. The velocity strings that were installed
ranged from 2 7/8” to 1 ½” coiled tubing strings and were all installed just below
the SCSSSV both onshore as in our Zuidwal Platform wells in the Waddenzee.
We also apply foam, but only occasionally. This year we have identified the need
to further optimize the production from these wells. The presentation will focus
on our selection criteria for all tail-end wells, on the challenges we now face with
these production tubings getting smaller and smaller and will tough on the
difficulties in managing velocity string tubing and annular flow. We will present
the outcome of our studies and the recommended path forward.
GWD Solutions
Will Vallejo (Schlumberger)
Abstract:
13
Velocity String and WRFM Campaign in the
Southern North Sea
Ewout Biezen (NAM)
Abstract:
Starting end 2011 a vessel-based campaign was started to install 26 velocity
strings on more than 10 different platforms in the Southern North Sea. In many
cases WRFM activities such as HUD deepening and reperforating were carried
out before the velocity strings were installed. The campaign as a whole has
shown an impressive learning curve with the VS installation times approaching
the technical minimum towards the later installations. VS deployments were coil-
based with 2 3/8” and 2 7/8” sizes, hung off in the old tubing at the subsurface
safety valve. Presentation will show the campaign’s main learnings and initial
results.
14
The applications of Surface Jet Pumps to Deliquify
Oil and Gas Wells. A review of several recent field
examples
Sacha Sarshar (Caltec)
Abstract:
Causes of liquid build up in wells are well understood and are contributed
mainly to the drop in reservoir pressure; increase in water-cut and insufficient
flow rate of gas to enable the gas-liquid mixture to flow through the well bore
satisfactorily. There are a number solutions to overcome this problem. The
methods vary in term of complexity and cost, both of which are important to the
operators.
The use of surface jet pumps is one of the simplest methods with lowest cost
to overcome the problem of well deliquification. This paper describes the
principle of operation, conditions under which the system works well and
highlights any limitations of the system. The paper also refers to the use of
downhole jet pumps in comparison with surface jet pumps. A number of recent
field examples in Europe, Middle East and Far East are presented and lessons
learned are highlighted.
15
Wellhead Compressco Dewatering System
Installation on Liquid Loaded Gas Wells in Italy :
A summary of results and best practices
Pasquale Imbo, Alessandro Aleandri (ENI) ,
Kevin Book (Compressco)
16
Abstract:
In May of 2013, ENI, installed three (3) 46 horse-power wellhead compressors
on liquid loaded gas wells in Sicily (Italy), operated by ENIMED. This
presentation will review the well selection process, wellbore and reservoir
characteristics, the impact on production since May and the collaboration of eni,
Compressco and Revoil in solving the logistical problems and installation
challenges/successes. The two original wells selected were either shut-in prior
to installation or being produced by intermittent flow. Both initial wells are now
producing above the critical flow rate with steady gas and liquids production.
The presentation will conclude with a short summary of the wellhead
compressors used in these installations.
Inverse Gas Lift using a Dual Flow Subsurface
Safety Valve – review of first multiwell North Sea
campaign
Norman Strachan (Weatherford)
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.
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.
Results, Observations, and Conclusions:
The paper will review the 1st Multi-well campaign conducted in the North Sea,
provide an update on the current status and share lessons learned during the
campaign.
17
Meeting Environmental and Legislative Discharge
Limits for Production Fluids, even during production
enhancement operations such as deliquification and
drilling functions
Mike Smith (PWA)
18
Abstract:
Many operators are using artificial lift methods for the deliquification of their wells to
enhance production. In many cases this includes the use of chemicals such as
surfactants/foamers, which tend to cause problems with existing processing equipment,
leading to issues with meeting environmental and legislative discharge limits/requirements.
Legislation such as OSPAR is becoming increasingly more stringent and will likely look to
include the discharge of chemicals and surfactants, as well as hydrocarbons and organics,
including dissolved & soluble components such as BTEX. Operators are now even more
interested in systems that can remove and handle these components simply and effectively.
PWA provide novel waste water treatment solutions that utilise our patented and
regenerable Osorb media to handle these fluids and chemicals . The media has the ability to
adsorb up to 99% of free, dispersed, and soluble hydrocarbons from produced water and other
waste water streams. Osorb has a consistent capture efficiency and loading capacity in the
presence of most oilfield chemicals and has been proven to remove many of the toxic
components reducing environmental impact factors. Typically the treated fluids are discharged
at better than 5ppm(mg/l) even during upset conditions such as foamer injection and drilling
applications.
The unique feature of the media is its regenerability which means that the adsorbed species
are recovered and have a ‘value’. Typically, these recovered hydrocarbons and organics can
be fed back into the process or recovered for other uses resulting in no consumable or
additional waste stream generated with the process. This therefore eradicates the need for
large volumes of consumables (replacement cartridges, filters and media), the shipment of
hazardous waste and significantly reduces manual handling requirements which all contribute
to driving down cost and environmental impact.
PWA plan to provide an update at the conference regarding corporate information,
technology updates and recent developments including ongoing testing within the Dutch sector
of the North sea with regards to these fluids and chemicals.
Retrofitted surfactant injection around SCSSV
leads to greater than expected production uplift -
first North Sea Multiplatform campaign
Brian Marr (Weatherford)
Abstract:
Many mature gas fields are suffering liquid loading; barriers to retrofitting wells
with continuous surfactant injection in the North Sea have always centered on
the need to maintain full surface and subsurface safety valve functionality.
This presentation reviews the 1st WCS continuous chemical injection
application in the UKNS. A review of the system, installation process and startup
will be covered and production improvement discussed.
The presentation will show technical solution, with:
- Modular capillary unit
- New Custom Lower Master Valves
- Control Line Hanger
- Chemical Injection SSV
- Injection Valve
Results, Observations, and Conclusions:
Production graphs will be shared, with both pre and post installation data, this
includes one well which was a continuous producer before surfactant injection
and another which was a cyclic producer prior to continuous chemical injection.
19
Experimental foam injection selection
Pejman Shoeibi Omrani, Erik Nennie, and Wouter
Schiferli (TNO)
20
Abstract:
Foamers are widely applied worldwide to deliquify gas wells. In order to be effective,
the surfactant chemical should form a stable foamer when combined with field water
and condensate under field conditions. To ensure good foamer performance in the
field, lab testing is conducted beforehand to test foamer performance.
A wide variety of test methods is currently being used to perform these tests. In
discussions with various operators, a clear demand was identified for a standardized
test method. The fact that all chemical vendors use somewhat different test
procedures to qualify their products makes it very difficult to objectively compare
foamers.
A Joint Industry Project was set up in order to arrive at a standardized test method
which will be made available to all parties involved in foamer testing. The central
concern is that none of the current test methods are representative of field conditions,
which may lead to incorrect or incomplete foamer selection.
This presentation will show the first results of this project. The first phase of the
project consisted of an extensive literature search in which an inventory was made of
current test methods. TNO is now constructing a foamer setup to test foamers at
pressures up to 15 bar and temperatures up to 150°C. This setup is designed to
accommodate the vast majority of test methods currently in use, and allows extending
them to higher flows, pressures and temperatures. This will give insight in the role of
pressure and temperature in foamer performance.
In later stages of the project, conditions can be extended further if needed, for
example by performing flow loop tests or tests at true field pressure. The final goal is
to identify the necessary conditions to ensure representative foamer performance,
while keeping the setup sufficiently simple to allow all parties to adopt the resulting test
methodology.
Production Optimisation from Liquid Loading
Wells
Shona Neve (BOL-Chevron)
Abstract:
This presentation focuses on the optimisation of a gas condensate field whose
well stock is increasingly affected by liquid loading as the field matures. There
has been a big focus on both improving our understanding of well performance
and identifying ways to maximise production.
Recent non-intrusive initiatives have been adopted to enhance our production
from liquid loading wells. Multiple elements have contributed to creating a more
robust production performance process and each of these will be touched upon
in this knowledge share:
Applying results from a well cycling optimisation project
Optimisation of batch foam treatments
Improving our measurement techniques
More frequent and cross functional production performance reviews between
offshore and onshore teams
21
Challenges and success in Gas Well
Deliquification in OMV-Petrom, Romania
Vasile Stanculescu (OMV- Petrom)
22
Abstract:
When the reservoir pressure depletes, the gas is not able to carry out the total
quantity of liquid which accumulates in the well. This leads to an increasing
accumulation of liquid in the well which has a negative effect on well production
and in worst case, can even lead to a complete stop of gas flow where the well
"kills" itself.
In this context, OMV PETROM has been studying various modern
technologies for gas wells deliquification for many different conditions of gas
wells: Foamer injection, Plunger lift, Capillary foamer injection, Wellhead
compression, Hydraulic piston pump and Wellhead electric compressors, in
autonomous and completely automatized system, are being used in more than
200 wells in PETROM Assets.
The success of these, led to extension of applied technologies in OMV
PETROM.
The results of the application of modern technologies, for gas wells
deliquification of gas wells, increased the average gas production by 21 %.
This presentation will summarize the evaluation process, design, installation
and results of the various applications.
The challenges found during these operations and the lessons learned, along
with new applications and new technologies, will greatly enhance our efforts in
gas well deliquification.
Applications for Magnetic Sensing in Plunger Lift
Mark Scantlebury (Extreme Telematics Corp.)
Abstract:
Magnetic pickup coils have been used for years to detect the arrival of the
plunger. There has been little to no advancement in this technology over the last
decade. The currently available devices have reliability and consistency issues.
Slow plungers are often missed and false detections are a common occurrence.
Utilizing a magnetic field sensor combined with a microprocessor allows plunger
detection to move into the digital age. Measuring the magnetic field and applying
digital filtering and advanced algorithms eliminate all of the issues seen with
traditional plunger arrival sensors. This technology also paves the way for future
devices that can not only detect the arrival of a plunger, but the velocity at
surface, a problem that is plaguing plunger lift.
23
Effect of tube wall wettability on the onset of
churning in upward gas-liquid annular flow
Erik Nennie, Stefan Belfroid (TNO)
Kees Veeken (NAM)
24
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 it 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%.
Dynamic IPR and gas flow rate can be determined
from measured surface pressure
Lynn Rowlan (Echometer)
Abstract:
Tubing and/or casing pressure acquired at a high sampling speed during a
conventional plunger lift well’s cycle can be used to determine the Dynamic
Inflow Performance Relationship (IPR) for the well. The shut-in time period for
the well defines the Dynamic IPR based on how the gas flow rate changes as a
function of the flowing bottomhole pressure. If the tubing and/or casing volume
from the end of the tubing to the surface is thought of as a closed volume and
the amount of liquid in the tubing is known, then the change in gas volume can
be calculated from the measured surface pressures. Flowing bottom hole
pressure can be determined from the measured surface pressure. The Dynamic
Inflow Performance Relationship for the well is equal to the best fit equation
determined from the of the change in gas volume (gas rate) versus flowing
bottom hole pressure during the shut-in time period.
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. In a conventional plunger lift well these calculated
instantaneous gas flow rates are reasonably accurate. 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.
In some cases this technique can also be applied to intermittent operated gas
wells.
25
Experiments on gas well deliquification in inclined
pipes
A.T. van Nimwegen (TUD), L.M. Portela (TUD),
R.A.W.M. Henkes (TUD & Shell P&T)
and G.J. de Vries (NAM)
26
Abstract:
Liquid loading is a frequently occurring problem when producing gas from wells
with a low reservoir pressure. From experience in the gas industry, it is known that
injecting surfactant (foamer) at the bottom of the well prevents liquid loading. The
surfactant causes the liquid to foam, changing the tubing performance curve and
decreasing the critical velocity required to lift liquids from the well. However, not
much systematic research has been done on this topic.
Last year at this conference, we have shown results of laboratory experiments
performed on air-water flow with and without added surfactants in a vertical pipe.
However, in reality gas wells are often deviated from vertical. Therefore, we have
extended our research with measurements for deviations between 0° and 70°
(from vertical). A high-speed camera was used to visualise the flow. In addition,
the pressure drop was measured to quantify the effect of the surfactants on the
flow.
At large gas velocities, in the annular flow regime, surfactants increase the
pressure drop at all inclinations, as the foam formed on the liquid film increases the
interfacial friction. For gas flow rates below the transition to irregular flow,
surfactants are able to decrease the pressure drop at any deviation by making the
morphology of the flow more regular. However, surfactants are more effective
when the liquid film is thinner, such that a very regular foam substrate at the wall
can be formed. Therefore, surfactants perform better at low liquid flow rates. In
deviated pipes, the liquid film at the bottom wall becomes significantly thicker and
the surfactant is less able to make the morphology regular. As a result, the
surfactants are less effective in deviated pipes than in vertical pipes.
Field Trial update on an Innovative Gas Well
Deliquification Pump
Norman Liley (Zilift)
Abstract:
This presentation will describe an innovative low power through-tubing ES-
PCP that can be installed through 23/8 inch production tubing using cable
deployment techniques. The system can be used to economically produce deep
mature liquid loaded gas wells, increase ultimate recovery and is capable of
retrofit installation.
Multiple field trials have been conducted on a variety of applications including
heavy-oil and GWD. The result from these trials will be described in detail.
The pump uses a medium speed permanent magnet motor, a contactless
speed reducer and a Progressing Cavity Pump. The complete system includes
a bottom hole assembly, cable, connectors, and variable speed drive offering
significantly better environmental footprint than conventional surface driven
systems.
Based on the success of the field trials an assembly line has been created for
the volume manufacture of this innovative product.
27
Development of new hydraulic piston pump
Systems
David Bolt (Cormorant), and Bert Lugtmeier (NAM)
28
Abstract:
Cormorant Engineering development efforts in advancing hydraulic dewatering
have resulted in two new systems, both of which eliminate the need for hydraulic
oil downhole, improve production rate, and reduce deployment and retrieval cost.
The first system conceived by and jointly developed with NAM, utilizes a set of
nitrogen springs in the downhole pump design, a single coiled tubing string, and
produced water as the power fluid. The system concept, design concept,
performance modeling, and proof of concept program are presented.
The second system uses produced water as the power fluid as well, however
includes a self-reciprocating pump producing water rates into the 100s of barrels
per day. The pump is deployable and retrievable simply by pumping fluid into the
coiled tubing string. No expensive downhole completion is necessary as the
pump sits in a standard API seating nipple. The design concept, performance
modeling, and development status are discussed.
Application of Electrical Submersible Pump for GWD – RAG’s experiences
Christian Burgstaller (RAG)
Abstract
The presentation summarizes RAG’s experience with the application of an electrical
submersible pump (ESP) in combination with a fully automated fluid level measurement
tool for gas well deliquification.
Previous applications of downhole pumps (e.g. sucker rod pumps) for gas well
deliquification in RAG suffered from limited run times due to insufficient control of the
fluid level causing gas break throughs and pumps running dry. The combination of an
ESP with an automated fluid level measurement tool has successfully been applied for
gas well deliquification in the Weizberg field (Upper Austria).
The automatic fluid level measurement tool is used to control a VSD (Variable Speed
Drive) to keep the fluid level in the well at a specific depth to avoid pump-off conditions
and the resulting serious equipment damage. The unique feature of this system is its
fully automated and purely electronic functioning. The measuring device is enclosed,
mounted on the casing valve and works with zero emissions on the environment (no
outlet of casing gas).
Compared with a conventional downhole 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.
ESP in Combination with an Automated Fluid
Level Measurement Tool for GWD
The availability of continuous online
fluid level data at a high sampling rate
(one measurement per minute) has also
been applied to derive continuous
bottom hole pressure information. The
presentation shows comparisons of
reservoir pressure data derived from
the continuous fluid level measurement
with pressure data recorded with a
downhole pressure sensor.
29
Breakout Sessions Tuesday 3-5PM: populate questionnaires, identify & discuss
collaboration topics
Questionnaires and possible collaboration topics are collected on flip
charts, moderators have been asigned to each flip chart
Prepare your response up front to leave more time for discussion
Collaboration topics must address tangible, planned activities and must
include time specific targets
Wednesday 8-10AM: feedback results, agree collaboration
scope, populate collaboration groups & asign leaders
Participants must share, support and execute
Collaboration kick-off requires up-front face-to-face framing session,
progress meetings can be by telecon
Leader needs to spend 2-4 hours per month to keep momentum
Method
Note down answers to survey questions and potential collaboration
topics on flip charts #1-#x
Discuss results and collaboration topics, note down your support of
collaboration topics on flip charts #1-#x, please coordinate your
response within your companies
30
Questionnaires
Predict Liquid Loading #1 – How do you predict liquid loading rate?
Turner Prosper (or
equivalent)
Offset well Collabora-tion topics & Support
#2 – How accurate is your LL rate prediction?
+/- 10% +/- 20% +/- 50%
#3 – Do you want to improve your LL rate prediction?
Yes No Maybe
#4 – How do you predict date of onset of liquid loading?
Decline curve
Material balance
Gap (or
equivalent)
#5 – How accurate is your LL date prediction?
+/- 1qtr +/- 1yr +/- 4yrs
#6 – Do you want to improve your LL date prediction?
Yes No Maybe
#1 – How do you predict GWD gain?
Decline curve
Material balance
Gap (or equivalent)
#2 – What is typical uncertainty in predicted GWD gain?
+/- 20% +/- 40% +/- 60%
#3 – Do you account for baseline IP without GWD?
Yes Sometimes No
#4 – What is your experience? Prediction optimistic
Prediction pessimistic
Prediction about right
#5 – How do you label GWD gains? New reserves
Existing reserves
Acceleration
Predict Deliquification Gains
31
Recognize Liquid Loading #1 – How do you recognize liquid loading? Gas
trend Temperature
trend Liquid trend
#2 – How much reduction of gas rate do you observe?
50% 90% 100%
#3 – Do you carry out dedicated surveillance to diagnose LL?
Pressure gradient
Pressure buildup
Well test
#4 – Do you match your well and reservoir model?
Yes Sometimes No
#5 – How long does LL go unnoticed? 1mon 1qtr 1yr
#6 – What percentage of wells is currently liquid loading?
<10% 10-30% >30%
#7 – What is awareness level in your company?
Poor Fair Good
#1 – What uptime do you achieve directly after onset of LL?
>80% 50-80% <50%
#2 – What percentage of LL wells is currently on active IP?
<30% 30-70% >70%
#3 – What parameter do you use to control shut-in?
Gas rate Temperature Timer
#4 – What parameter do you use to control start-up?
Wellhead Pressure
Casing pressure
Timer
#5 – By how much does active IP increase uptime?
<10% 10-30% >30%
#6 – What type of IP do you use? Manual Automated local
Automated remote
#7 – What percentage of active IP wells are candidates for GWD?
<30% 30-70% >70%
Intermittent Production
32
Assess Technical Feasibility #1 – What approach do you use? Detailed
review Offset
experience Trial and
error
#2 – What kind of technical assurance do you use?
Field trial Lab/yard trial
Vendor input
#3 – Do you consider new technology? Develop Test Follow
#4 – Any technique ruled out due to SSSV?
Pump Plunger lift Other
#5 – What technique ruled out due to horizontal?
Pump Plunger Other
#6 – What technique ruled out due to liquid?
Plunger Velocity string
Other
#7 – What technique ruled out due to temperature?
Foam Pump Other
#1 – What selection parameters do you use?
Profitability Incremental production
Strategic fit
#2 – What is your key uncertainty? Installation cost
Operating cost
Production
#3 – How do you select? Well level Field level Area level
#4 – What is your key reservoir parameter?
Size Inflow Other
#5 – What is your key well parameter? Tubing size Wellhead pressure
Area level
Select Deliquification
33
Compression #1 – Is compression considered as part of original FDP?
Yes Some-times
No
#2 – Where are your compressors located?
Central processing
Satellite location
Wellhead
#3 – What compressor types do you operate?
Centrifugal Recipro-cating
Screw Wet gas
#4 – What minimum wellhead pressure do you plan to achieve?
<2 barg 2-10 barg >10 barg
#5 – Do you consider sand risk a potential blocker?
Yes Sometimes
No
#6 – Do you take synergy into account with other GWD?
Gas lift Plunger lift Velocity string
#7 – How many surface jet pumps have you installed?
<5 5-50 >50
#8 – What source of power gas do you use?
Compressor ullage
HP well Other
34
#1 – Is velocity string considered as
part of well proposal?
Yes Sometimes No
#2 – How many VS did you install? <5 5-50 >50
#3 – What percentage of VS were
successful?
<30% 30-70% >70%
#4 – Do you take future inflow risks into
account (sand/water)?
Yes – Opex
to pull VS
Yes – Risk
Production
No
#5 – How do you install? Rig or HWU –
dead well
HWU – live
well
CTU –
live well
#6 – What VS material do you use? Corrosion
resistant
Carbon steel
w/ CI
Carbon
steel
#7 – Do you straddle section above
SSSV?
Yes Sometimes No
#6 – What is minimum VS ID that you
install?
<1” 1”-1.5” >1.5”
#7 – What problems have you
experienced?
Integrity Intervention Other
#8 – What is your mean-time-between-
failure (MTBF)?
<2yr 2-5yr >5yr
#9 – Have you used choke to stabilize
production?
Yes -Success Yes- Failure No
Velocity String and Choke
35
#1 – Is foam lift considered as part of well proposal?
Yes Sometimes No
#2 – How many batch foam jobs do you execute per year?
<10 10-100 >100
#3 – What percentage of batch foam lift was successful?
<30% 30-70% >70%
#4 – How many continuous foam installations do you operate?
<5 5-50 >50
#5 – What percentage of continuous foam lift was success?
<30% 30-70% >70%
#6 – What reduction of critical gas rate do you achieve?
<30% 30-70% >70%
#7 – How do you select foam chemical? Field trial Lab test Vendor info
#8 – What is target foam concentration? <1000ppm 1000 -10,000 ppm
>10,000 ppm
#9 – How do you dispose produced water? Surface – As usual
Surface – Add treatm.
Downhole
#10 – What do you consider potential blockers for foam lift?
CGR Tempera-ture
CI
#9 – What problems have you experienced? Corrosion Blockage Other
#10 – What is your mean-time-between-failure (MTBF)?
<1yr 1-3yr >3yr
Foam Lift
36
#1 – Is plunger lift considered as part of well proposal?
Yes Sometimes No
#2 – How many plungers did you install?
<5 5-50 >50
#3 – What percentage of plungers were successful?
<30% 30-70% >70%
#4 – Do you consider SSSV as a blocker?
Yes Maybe No
#5 – How do you model plunger lift? Foss & Gaul Lea et al.
Virtuwell Other
#6 – What type plunger do you install? Bar stock Padded Continuous
#7 – Who optimizes plunger cycle? Operator Vendor Automated
#8 – What do you consider potential blockers for plunger lift?
Solids Deviation Pressure buildup
#9 – What problems have you experienced?
Solids Control Stalled
#10 – What is your mean-time-between-failure (MTBF)?
<1qtr 1qtr-1yr >1yr
#11 – Are you considering plunger for GWD?
Yes Maybe No
Plunger Lift
37
#1 – Is gas lift considered as part of FDP and well proposal?
Yes Sometimes No
#2 – How many gas lift did you install? <5 5-50 >50
#3 – What percentage of gas lift was successful?
<30% 30-70% >70%
#4 – What type of gas lift geometry? Annulus Concentric Mixed
#5 – Do you use unloading valves? Yes Sometimes No
#6 – What is your source of lift gas? Local Remote HP well
#7 – What problems have you experienced?
Scale Control Other
#8 – What is your mean-time-between-failure (MTBF)?
<1yr 1-3yr >3yr
#9 – Are you considering gas lift for GWD? Yes Maybe No
Gas Lift
#1 – Is pump considered as part of FDP and well proposal?
Yes Sometimes No
#2 – How many pumps did you install? <5 5-50 >50
#3 – What percentage of pumps was successful?
<30% 30-70% >70%
#4 – What type of pump did you install? Piston PCP ESP
#5 – Do you consider SSSV as a blocker? Yes Maybe No
#6 – What do you consider potential blockers for pump?
Solids Deviation Gas separation
#7 – What problems have you experienced?
Gas Control Other
#8 – What is your mean-time-between-failure (MTBF)?
<1y 1-3yr >3yr
#9 – Are you considering pump for GWD? Yes Maybe No
Pump
38
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Baker Hughes
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Clariant
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Conoco Phillips
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Cormorant Engineering
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Definitive Optimization
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ENI
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N/A
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Perenco
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PGNiG SA Sanok
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PWA Europe
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RWE Dea
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Schlumberger
Mr Vallejo Will [email protected] 41
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Shell / NAM
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Siemens
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