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

Participants Aubin Ltd

Ms Neroutsou Aimilia aimilia.neroutsou@aubin.co.uk

Mr Stirton Raymond ray.stirton@aubingroup.com

Baker Hughes

Mr Adrians Marcus marcus.adrians@bakerhughes.com

Mr Bjoern Lause bjoern.lause@bakerhughes.com

Mr Ciavarro Lucio lucio.ciavarro@bakerhughes.com

Mr De Ceuster Bart bart.deceuster@bakerhughes.com

Mr De Jonge Robert robert.dejonge@bakerhughes.com

Ms Hannah Lieder - Wolf marcluecke@gmx.de

Mr Mather Alan alan.mather@bakerhughes.com

Mr Pitassi Francesco francesco.pitassi@bakerhughes.com

Mr Schorling Peter peter.schorling@bakerhughes.com

Mr Valenta Christian christian.valenta@bakerhughes.com

Mr Van Veen Wilco wilco.vanveen@bakerhughes.com

Mr Welboren David david.welboren@bakerhughes.com

BashNIPIneft

Mr Litvinenko Konstantin litvinenkokv@gmail.com

Brilliant Water

Mr Arnoldy Michiel michiel@brilliantwater.org

Mr Schouten Paul paul@brilliantwater.org

Caltec

Mr Sarshar MM(Sacha) s.sarshar@caltec.com

Centrica Energy

Mr Bentley Nick nicolas.bentley@centrica.com

Mr Hall Les les.hall@centrica.com

Mr Talbot David david.talbot@centrica.com

Mr James Stephen stephen.james1@centrica.com

Mr Paige Stephen stephen.paige@centrica.com

Chevron / BOL

Ms Neve Shona shona.neve@bol.co.uk

Ms McBeath Jenni jennifer.mcbeath@bol.co.uk

Chimec S.p.A.

Mr Allegrucci Alessandro aallegrucci@chimec.it

Mr Di Toto Raul Antonio aditoto@chimec.it

Clariant

Mr Brauchle Michael michael.brauchle@clariant.com

Mr Cheramie Gary yvonne.gray@clariant.com

Mr Lambert Brian brian.lambert@clariant.com

Compressco Partners Sub Inc.

Mr Book Kevin kbook@compressco.com

Conoco Phillips

Mr McLaughlin David david.g.mclaughlin@conocophillips.com

Mr Sutherland Iain iain.sutherland@cop.com

Cormorant Engineering

Mr Bolt David david@cormorant.us.com 39

40

Definitive Optimization

Mr David Lyren david.lyren@defopt.com

Mr Mason Clint cmason@defopt.com

Echometer

Mr Rowlan Lynn lynn@echometer.com

ENI

Mr Aleandri Alessandro alessandro.aleandri@eni.com

Mr Imbò Pasquale pasquale.imbo@eni.com

Ms Passucci Claudio claudio.passucci@eni.com

Expro Meters

Mr Davidson Arran arran.davidson@exprogroup.com

Mr Wavell David david.wavell@exprogroup.com

Extreme Telematics Corp.

Ms Ferec Jehn jehn.ferec@etcorp.ca

Mr Scantlebury Mark mark.scantlebury@etcorp.ca

Exxon Mobil

Mr Fulls Russell russell.fulks@exxonmobil.com

Mr Kempf Rüdiger ruediger.kempf@exxonmobil.com

Mr Patzschke Clemens clemens.patzschke@exxonmobil.com

Fangmann Energy Services

Mr Fangmann Frank

jplaumann@fangmanngroup.com Mr Gerdes Steffan

Mr Mergenthaler Frank

Mr Recalde Lummer Nils

GDF Suez

Mr Jeancenel Christophe christophe.jeancenel@gdfsuezep.com

Mrs Lafage Stephanie stephanie.lafage@gdfsuezep.com

Geveke Pompen

Mr Ippel Renée ripp@geveke.com

Mr Wijnen Eric ewij@geveke.com

Halliburton

Mr De Vries Bert bert.devries@halliburton.com

Hansen Downhole Pump Solutions AS

Mr Hansen Henning henning@wellborepumps.com

Mrs Hansen Cynthia Beckman cindy@wellborepumps.com

Ircat

Mr Nestor Mihnea nestor@ircat.ro

Maesrk Oil

Mr Kairan Mohd Awallizam mohd.awallizam.kairan@maerskoil.com

Marathon Oil

Mr Shields Christian cshields1@marathonoil.com

Munzing

Mr Oudesluys Johan j.oudesluys@munzing.com

Mr Swanson David dswanson@munzing.us

Nalco Champion

Mr Adelizzi Craig ceadelizzi@nalco.com

Mrs Gray Cheryl cheryl.gray@champ-tech.com

Ms McFadzean Jaclyn jaclyn.mcfadzean@champ-tech.com

Mr Oude Heuvel Steven steven.oudeheuvel@champ-tech.com

Mr van der Knoop Sjoerd sjoerd.vanderknoop@champ-tech.com

Mrs Todosijevic Ana ana.todosijevic@yahoo.de

Mr Zijlstra Mark mark.zijlstra@champ-tech.com

National Metallurgical Academy Dnepropetrovsk, Ukraine

Mr Omoloye Abiola Amos biom81@yahoo.co.uk

Nexen Petroleum

Mr Davis Frank frank_davis@nexeninc.com

Mr Tunoglu Ahmet ahmet_tunoglu@nexeninc.com

N/A

Mr Adeyin Olufemi toye2001ng@yahoo.com

Oilchem

Mr Jörg Mundo info@oilchem.de

OMV Petrom

Mr Stanculescu Vasile vasile.stanculescu@petrom.com

Mr Tipple Philipp elena.rotaru3@petrom.com

Perenco

Mr Browne Mark mbrowne@uk.perenco.com

Mr Lucero Luna Xavier xlucero@uk.perenco.com

Mr Morah Uzochukwu umorah@uk.perenco.com

Mr Rogdy Espinoza respinoza@fr.perenco.com

PGNiG SA Sanok

Mr Wrzos Maciej maciej.wrzos@sanok.pgnig.pl

Mr Ziobro Robert robert.ziobro@sanok.pgnig.pl

PWA Europe

Mr Smathers Caleb c.smathers@pwasystems.com

Mr Smith Michael m.smith@pwasystems.com

Mr Robertson Ian i.robertson@pwasystems.com

RAG

Mr Burgstaller Christian christian.burgstaller@rag-austria.at

REACHWise

Mr Douben Peter peter.douben@reachwise.eu

Resato

Mr Sijtsma Hendrik hendriksijtsma@resato.com

Revoil

Mr Antonio Mazzon antonio.mazzon@revoil.it

Mr Gil Miguel Enrique miguel.gil@revoil.it

RWE Dea

Mr Eisenberger Michael michael.eisenberger@rwe.com

Mr Oswald Wolfgang wolfgang.oswald@rwe.com

Mr Racher Dominik dominik.racher@rwe.com

Mr Völgyi Sandor bestellung@semigator.de

Mr Wessel Folkert folkert.wessel@rwe.com

Schlumberger

Mr Vallejo Will will@slb.com 41

42

Shell / NAM

Mr Beijer Vincent v.beijer@shell.com

Mr Biezen Ewout ewout.biezen@shell.com

Mr Bolley Ralf ralf.bolley@shell.com

Mr de Kroon Michiel michiel.dekroon@shell.com

Mr de Vries Gert gert.devries@shell.com

Mr Donald James james.r.donald@shell.com

Ms Garming Linda johanna.garming@shell.com

Ms Hovland Ingun ingun.hovland@shell.com

Mr Irvine James james.irvine@shell.com

Ms Janczak Alyssia alyssia.janczak@shell.com

Mr Klompsma Dick dick.klompsma@shell.com

Mr Smith Jeroen jeroen.j.smith@shell.com

Mr Trompert Ruud ruud.trompert@shell.com

Mr van der Weijde Maarten maarten.vanderweijde@shell.com

Mr van Haersma Buma Michiel m.vanhaersmabuma@shell.com

Mr van Zadelhoff Koen koen.vanzadelhoff@shell.com

Mr Veeken Kees kees.veeken@shell.com

Shell UK

Ms Dickson Sara-Jane sara-jane.dickson@shell.com

Mr Kitsios Stathis efstathios.kitsios@shell.com

Mr Strachan Colin colin.strachan@shell.com

Mr Webb Phil phil.webb@shell.com

Siemens

Mr Carnal Rob rob.carnal@siemens.com

Mr Okhuijsen Bob bob.okhuijsen@siemens.com

SIVAM

Mr Antonacci Marco marco.antonacci@sivam.com

Stepan

Mr Pendleton Nicholas npendleton@stepan.com

Mr Storey Rupert rupert.storey@stepaneurope.com

TAQA

Mr Mulder René rene.mulder@taqaglobal.com

Mr Plug Willem-Jan willem-jan.plug@taqaglobal.com

Taywood Engineering and Power System

Mr Dasaolu Olawale dazaat@gmail.com

Tetra Technologies

Mr Ormezzano Ugo uormezzano@tetratec.com

TNO

Mr Alberts Garrelt garrelt.alberts@tno.nl

Mr Bijl Marteen maarten.bijl@tno.nl

Mr Ham Koos koos.ham@tno.nl

Mr Nennie Erik erik.nennie@tno.nl

Mr Shoeibi Omrani Pejman pejman.shoeibiomrani@tno.nl

Total E&P

Mr Boot Nicolaas nicolaas.boot@total.com

Mr Jonathon Clutterbuck jonathon.clutterbuck@total.com

Mr Francot Eddy eddy.francot@gmail.com

Ms Abolarin John john.abolarin@total.com

TU Delft

Mr van Nimwegen Dries a.t.vannimwegen@tudelft.nl

Vermilion Energy

Mr Ottevanger Michiel m.ottevanger@gmail.com

Mr Regelink Jaap jaapregelink@gmail.com

Mr Tummers Sven stummes@vermilionenergy.com

Wasser Behandlung

Mr Mundo Axel umlexa53@t-online.de

Weatherford

Mr Birner Wolfgang wolfgang.birner@eu.weatherford.com

Mr Griffiths Colin colin.griffiths@eu.weatherford.com

Mr Iordanescu Bogdan bogdan.iordanescu@eu.weatherford.com

Mr Lacy Rodger rodger.lacy@weatherford.com

Mrs Müller Pamela pamela.mueller@eu.weatherford.com

Mr Rae Colin colin.rae@eu.weatherford.com

Mr Ungureanu Silviu mihaisilviu.ungureanu@eu.weatherford.com

Welltec

Mr Davies Paul pdavies@welltec.com

Mr Dilling Lambert ldilling@welltec.com

Mr Jones Phil pgjones@welltec.com

Wintershall

Mr Elichev Vitaly vitaly.elichev@wintershall.com

Mr Kobel Michael michael.kobel@wintershall.com

Mr Reijn Hans hans.reijn@wintershall.com

Mr Segeren Harry harry.segeren@wintershall.com

Zilift

Mr Liley Norman norman.liley@zilift.com

43

44