If Argentine production declines were improved by mere percentage points, the country's production could increase substantially, adding enough crude recovery to fuel the entire country for years to come. With the global average recovery factor in a mature field sitting at only 20-40% for oil and 70% for gas, much of the country's assets remain untapped. Considering production optimization can increase incremental production by up to 25% and EOR applications up to 70%, operators are acutely focused on adopting the right production technologies and strategies for application in these fields. The answer lies in optimizing production techniques and EOR; the initial investment into which can be far lower than exploration and workover efforts, while delivering some of the highest returns. A modest 1% improvement in recovery could potentially deliver millions of dollars in added value to a company's assets; YPF is just one company that agrees, stating that waterflooding can improve recovery by 6-8%, with polymer injection recovery forecasted to be even higher at 12-16%. ARGENTINA'S FIRST MATURE FIELDS CONGRESS FOR PRODUCTION AND RESERVOIR PROFESSIONALS Mature Fields Argentina Production Optimization 2014 is the first congress of its kind addressing how to select the optimal lift method to maximize reservoir production in light oil, heavy oil and gas fields. The congress will deliver best practices on artificial lift, production monitoring, deliquification, sand control, corrosion control, paraffin control and EOR.

1. ARGENTINA’S ONLY OPERATOR LED CONGRESS FOCUSED
PURELY ON MATURE FIELD PRODUCTION OPTIMIZATION
Optimizing Artificial Lift And
Secondary Recovery Injection To
Maximize Production And
Reduce OPEX In Argentina’s Depleted,
Multi-Layered Oil And Gas Reservoirs
Key Issues To Be Discussed Include:
July 23-24 | Buenos Aires | Argentina
Damian Ramallo
Leader Of Production
Gran Tierra Energy
Expert Insight From Argentinean E&P Operators
Working In Mature Fields, Incluiding:
M Follow Us: @UnconventOilGas
www.mature-fields-argentina-2014.com
• ARTIFICIAL LIFT TECHNIQUES - LIGHT OIL: Selecting the optimal artificial lift
techniques based on run life, cost, durability, energy consumption and effectiveness
to optimize production within low-pressure reservoirs
• VISCOUS OIL PRODUCTION: Defining the optimal well design to ensure the effective
production of fields with viscous oil properties
• GAS PRODUCTION: Examining the latest technologies to deliquify gas wells and
improve the run life of gas lift production
• SURVEILLANCE & MONITORING: Identifying production monitoring, automation and
chemical tracer technologies to optimize injection and minimize failures
• FAILURE MITIGATION: Preventing well failures through sand, paraffin and corrosion
control methodologies, treatments and technologies
• WATER & POLYMER INJECTION: Delivering water and polymer injection and
waterflooding chemical treatment best practices to maximize oil and gas recovery
Victor Perusini
Head Of Production
San Jorge Petroleum
Francisco Queralt
Head Of Facilities & Construction
Americas Petrogas
Alejandro Ameglio
Production Superintendent
Apache Argentina
Carlos Laluf
Head Of International Engineering Operations
Azabache Energy
Oscar Orellana
Production Supervisor
Total
Martín Ignacio Kennedy
Production Engineering Technical Consultant
Petrobras Argentina
Diego Garzon Duarte
CEO
Oilstone Energy
Register By Friday
May 9 2014
SAVE
$400
Organized By:
Part Of:

2. Sheraton Buenos Aires
Hotel & Convention Center
San Martin 1225-1227
Buenos Aires 1104
Argentina
Phone: (54) 11 - 4318 9000
Website: http://goo.gl/YKCKKA
Venue Information:
Register By Friday
May 9 2014
SAVE
$400
If Argentine production declines were improved by mere percentage points, the
country’s production could increase substantially, adding enough crude recovery to
fuel the entire country for years to come. With the global average recovery factor in
a mature field sitting at only 20-40% for oil and 70% for gas, much of the country’s
assets remain untapped.
Considering production optimization can increase incremental production by up to
25% and EOR applications up to 70%, operators are acutely focused on adopting
the right production technologies and strategies for application in these fields.
The answer lies in optimizing production techniques and EOR; the initial
investment into which can be far lower than exploration and workover efforts, while
delivering some of the highest returns. A modest 1% improvement in recovery could
potentially deliver millions of dollars in added value to a company’s assets; YPF is
just one company that agrees, stating that waterflooding can improve recovery by
6-8%, with polymer injection recovery forecasted to be even higher at 12-16%.
Mature Fields Argentina Production Optimization 2014 is the first congress
of its kind addressing how to select the optimal lift method to maximize reservoir
production in light oil, heavy oil and gas fields. The congress will deliver best
practices on artificial lift, production monitoring, deliquification, sand control,
corrosion control, paraffin control and EOR.
Over two days, attendees will benefit from 20 operator case studies specifically
focused on how to reduce OPEX and maximize production in fields with
a high water cut. The mission of the congress is for Argentinean operators to
take away usable solutions focused on how to maximize the run life of the
well and prevent well failures through field automation, surveillance, monitoring
technologies, lift selection and optimization and secondary recovery applications.
The First Congress Focused On Increasing The Ultimate Recovery Of
Argentinean Mature Fields With Minimal Resources:
• Evaluates how to select the most effective artificial lift for light and heavy oil
reservoirs to maximize production results in depleted reservoirs
• Identifies how lifts and deliquification processes can maximize recovery and
minimize drowning gas fields
• Delivers real-life case studies on how operators have not only prevented
well failures but rectified sand, corrosion and paraffin issues downhole
ARGENTINA’S FIRST MATURE FIELDS CONGRESS FOR PRODUCTION AND
RESERVOIR PROFESSIONALS
Andy Barrett
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the Mature Fields Argentina Production
Optimization 2014. Our busy exhibit area
is an integral part of the congress and is of
genuine practical value to delegates, who are
looking for new solutions and technologies.
Exhibiting at the congress will help you position
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3. ARTIFICIAL LIFT OPTIMIZATION, VISCOUS OIL
PRODUCTION AND GAS LIFT OPTIMIZATION
Day 1
Wednesday, July 23
8.30 Chair’s Opening Remarks
KEYNOTE: ARTIFICIAL LIFT SELECTION
8.40 How To Select The Optimal Artificial Lift System
For The Reservoir To Maximize Production Within
Argentina’s Mature Fields: Case Study
• Understanding how the presence of gas, liquids,
sands and solids impact which artificial lift would
optimize production
• Comparing pulling index results from artificial
lift systems to select the rig that will minimize
interventions in gas and oil fields
• Defining the optimal reservoir to use ESP, PCP,
plunger lift and manual bean pump units to increase
the run life of the well
• Comparing the average run life of artificial lift
systems to ensure the OPEX will not exceed the oil
recovery
DiegoGarzonDuarte,President,OilstoneEnergy
9.10 Question & Answer Session
ARTIFICIAL LIFT - LIGHT OIL
SELECTING THE OPTIMAL ARTIFICIAL LIFT TECHNIQUES
BASED ON RUN LIFE, COST, DURABILITY, ENERGY
CONSUMPTION AND EFFECTIVENESS TO OPTIMIZE
PRODUCTION WITHIN LOW PRESSURE RESERVOIRS
BEAM PUMP OPTIMIZATION PANEL
9.20 How Operators Are Reducing Paraffin And Gas
Failures And Energy Consumption In Beam Pumps To
Reduce OPEX
• Assessing optimal beam pump velocity to prevent
downhole breakages whilst maintaining the
maximum level of production
• Identifying the optimal beam pump for use in wells
with high gas content to prevent gas interference,
downhole failures and increase run life
• Selecting the optimal beam pump when producing
in deep wells to ensure the liquid can be lifted to
surface efficiently
• Comparing ceramic and steel beam pumps to
assess the optimal system for preventing corrosion
in high temperature wells
PabloChebli,VPArgentina,CentralResources
9.50 Question & Answer Session
10.00 Morning Refreshments In Exhibition Showcase Area
JET PUMP OPTIMIZATION
10.30 Evaluating Jet Pump Applications In Wells With
A Depth Of 4000m With A Temperature Of 173°C To
Define The Optimum Operating Regime In Mature
Light Oil Wells
• Analyzing the optimal surface pump, motor and
power oil conditions when using jet pumps in light
oil fields
• Evaluating the installation costs, failure rates and
production rates of jet pumps to identify production
economics of the project
• Examining pump efficiencies and run life to identify
if running a jet pump will produce a well more
efficiently than beam pump units
• Identifying the optimal temperature for running a jet
pump to ensure a polymer can be selected that will
withstand the downhole conditions
Moderator:DamianRamallo,ProductionLeader,Gran
TierraEnergy
SergioFlores,ProductionEngineer,GranTierraEnergy
11.00 Question & Answer Session
ARTIFICIAL LIFT INNOVATIONS: CASING PLUNGERS
11.10 Validating The Application Of A Plunger Casing
System In The Neuquina Basin To Evaluate The
Potential For Improving Recovery In Low Gross
Production Wells
• Evaluating how to power the production system by
using the energy generated in the well to minimize
operating costs
• Applying a production system to wells with medium/
high gas to liquid ratios to maintain fluid production
in low production grossing wells
• Defining the optimal casing diameter used in the
Medanito reservoir to define the optimal apparatus
and materials needed for successful application
• Defining the capital costs of the tubing and sucker
rod pump to evaluate if replacing the pumping
system will be economical
NicolasCuestas,ExtractionEngineer,PetrobrasArgentina
MartínIgnacioKennedy,TechnicalAdvisor,Petrobras
Argentina
11.40 Question & Answer Session
LIGHT OIL: ARTIFICIAL LIFT SELECTION
11.50 Evaluating The Optimal Artificial Lift Selection
Across The Life Of A Well To Minimize Production
Losses
• Evaluating geological characteristics of the reservoir
including fluid distribution to define the optimal
production system
• Analyzing geological, economic and workload factors
to select the optimal artificial lift system
• Assessing depressurization to evaluate the impact
on natural upwelling
VictorPerusini,HeadOfProduction,SanJorgePetroleum
12.20 Question & Answer Session
12.30 Lunch In Exhibition Showcase Area
HEAVY OIL PRODUCTION OPTIMIZATION
DEFINING THE OPTIMAL WELL DESIGN TO ENSURE THE
EFFECTIVE PRODUCTION OF FIELDS WITH VISCOUS OIL
PROPERTIES
MANAGING LOW PRESSURE WELLS
1.30 Selecting Optimal Surface And Downhole
Equipment To Ensure Mobility Of Viscous Oil Within
Wells With Low Production
• Describing how surface lines have been optimized to
improve the mobility of viscous oil from the wellhead
to battery
• Identifying the optimal pumping unit design to
maximize heavy oil fluid production and reduce the
failure of the pump
• Evaluating how friction reduction chemicals improve
the fluid movement of viscous oil and reduce
wellhead to battery pressure
JuanMiguelLinares,ProductionManager,Sinopec
Argentina
AldoSarelli,HydrocarbonProcessingEngineer,Sinopec
Argentina
FedericoG.Porta,IndustrialEngineer,SinopecArgentina
JoaquínVaz,IndustrialEngineer,SinopecArgentina
2.00 Question & Answer Session
GAS PRODUCTION OPTIMIZATION
EXAMINING HOW THE LATEST TECHNOLOGIES ARE
BEING USED TO COST TO EFFECTIVELY DELIQUIFY
WELLS AND IMPROVE THE RUN LIFE OF GAS LIFT
DELIQUIFICATION
2.10 Assessing How Capillary Technology, Chemical
Injection, Plunger Lift And Polymer And Soap Agents
Are Being Used To Control Water Downhole
• Assessing how capillary technology and chemical
injection can control water in the bottom hole to
prevent wellhead pressure decreases
• Assessing the advantages of using a plunger lift
systems to deliquify the well and prevent workover
costs
• Identifying wellhead pressure and production
symptoms to forecast wells with a high liquid ratio
early on and prevent drowning
• Assessing how utilizing polymer and soap agents
can extract water from reservoir channels without
removing the water from the well
• Identifying the most efficient gas separator to ensure
a technology is selected which does not allow a
liquid presence
GustavoGonzales,ProductionEngineer,Capsa-Capex
2.40 Question & Answer Session
2.50 Afternoon Refreshments In Exhibition Showcase Area
ESP
3.20 Identifying How ESP Lift Is Being Used To
Simultaneously Improve The Run Life Of Low
Pressure Wells And Minimize Energy Consumption
• Evaluating the optimal reservoir pressure and gas-
liquid relationship for ESP to ensure the system can
optimize production within the reservoir
• Defining the optimal reservoir pressure and
temperature when using an ESP to optimize the
pump life
• Examining methods for reducing downtime due to
electrical stop
• Assessing the application of magnet motor
and speed drive technology to reduce energy
consumption whilst pumping
• Predicting the capacity of the ESP to run within deep
wells to prevent costly interventions and reduce failure
• Evaluating the optimal pump for use with various
casing diameters to ensure the pump is adequately
protected
• Evaluating real time ESP production data to identify how
the pump system is impacting the reservoir run life
• Describing the efficiency of the gas lift system at
each stage of the pump to identify stages where
energy consumption can be reduced and gas
production can be increased
3.50 Question & Answer Session
GAS FIELD: LIFT SELECTION
4.00 Evaluating Artificial Lift Management In Mature
Oil Fields To Ensure The Right Lift Is Selected,
Installed And Monitored
• Evaluating the selection, acquisition, installation,
evaluation, monitoring and inspection of lift methods
to adopt a multidisciplinary approach to lift selection
• Analyzing how understanding the location and
culture of the fields will impact the gas production
optimization and cost of operations
• Assessing how production optimization
requirements change over time to identify when
waterflooding and EOR projects are required
MarceloHirshfield,OPOGC,Pemex
4.30 Question & Answer Session
SURVEILLANCE
IDENTIFYING PRODUCTION MONITORING AND
AUTOMATION TECHNOLOGIES TO IMPROVE THE
EFFECTIVENESS OF ARTIFICIAL LIFT AND MAXIMIZE
RECOVERY
PUMP OFF CONTROLLERS
4.40 Analyzing How Pump Off Controllers Are Being
Installed And Maintained To Extend Run Life And
Mitigate Downhole Failure
• Providing a case study of how pump off controller
automation has fixed a well problem and prevented
workover and intervention costs
• Explaining the installation and maintenance costs for
pump off controllers to calculate the monthly cost of
surface automation
• Analysing how the automation of production levels,
fluid levels and production weight controls can
prevent pump breakages and surface leaks
• Assessing the accuracy of using pump off controllers
to fix well issues to evaluate if the system should
replace previous monitoring and well maintenance
methodologies
• Evaluating how combining SCADA and the pump
off controller has minimized beam pump failure
through more efficient data management
JuanMiguelLinares,ProductionManager,Sinopec
Argentina
AldoSarelli,HydrocarbonProcessingEngineer,Sinopec
Argentina
FedericoG.Porta,IndustrialEngineer,SinopecArgentina
JoaquínVaz,IndustrialEngineer,SinopecArgentina
5.10 Question & Answer Session
5.20 - 6.20 Networking Drinks Reception In Exhibition
Showcase Area
www.mature-fields-argentina-2014.com (1) 800 721 3915 info@american-business-conferences.com
Register By Friday
May 9 2014
SAVE
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4. MITIGATING FAILURES, WATER AND POLYMER INJECTION
Day 2
Thursday, July 24
8.30 Chair’s Opening Remarks
PREVENTING FAILURES
UNDERSTANDING HOW FAILURE ANALYSIS, SAND,
PARAFFIN AND CORROSION CONTROL IS PREVENTING
WELL INTERVENTIONS AND WORKOVERS
FAILURE ANALYSIS
8.40 Outlining How Production Monitoring Techniques
Are Being Used To Predict Equipment Failure And
Prevent Intervention And Workover Costs
• Determining the most common causes of failure in
wells to prevent failure in the pump, rod, surface and
facilities
• Explaining how a downhole failure analysis program
can determine the accurate run life of a well and
calculate the pulling-intervention index
• Defining how failure analysis data software has
improved the well run life
AlejandroAmeglio,ProductionSuperintendent,Apache
Argentina
9.10 Question & Answer Session
SAND CONTROL
9.20 Assessing How Gravel Packers, Sand Filters And
Sand Screens Are Removing Sand Cost-Effectively
And Preventing Well Failures
• Defining how the percentage of sand within the
reservoir effects pump selection to optimize
production within high sand content reservoirs
• Comparing artificial lifts and gas lift pumps’ ability to
handle sand content to determine the optimal pump
for use when producing solids
• Assessing the pulling index to determine if the sand
should be removed from the reservoir or if the pump
can operate without intervention
• Outlining how gravel packing is being used to
contain the sand in the well and prevent sand
cleaning interventions
9.50 Question & Answer Session
10.00 Morning Refreshments In Exhibition Showcase Area
PARAFFIN CONTROL
10.30 Analyzing Optimal Conditions In Which To
Utilize Paraffin And Asphaltene Management
Chemicals To Prevent Stuck Pipe
• Outlining the optimal chemicals for reducing paraffin
blockages downhole to maintain well performance
and production
• Determining how deep the paraffin disperser should
be injected to avoid paraffin blockages within the
tubing string
• Identifying casing and chemical suites that handle
paraffin to prevent downhole bottlenecks
• Providing chemical deposition analysis results to
determine if the chemical has worked effectively to
remove the paraffin downhole
• Evaluating the options for handling paraffin
downhole and at the wellhead devices to avoid
depositions and minimize interventions
OscarOrellana,ProductionSupervisor,Total
11.00 Question & Answer Session
CORROSION CONTROL
11.10 Evaluating The Type, Cost And Volume Of
Chemical Treatments Being Used To Combat Surface
And Downhole Corrosion And Prevent Pipeline
Failures And Interventions
• Assessing chemical reaction and equipment
injection points to identify the optimal location for the
chemical product to combat corrosion
• Analyzing the optimal injection rates for corrosion
chemicals to ensure target layer is reached
• Evaluating the volume and cost per barrel of corrosion
chemical treatment required to determine if well
replacement is more economical than treatment
• Explaining the chemistry composition of the
corrosion control treatment to define how the
chemical will tackle corrosion downhole
• Evaluating the fluid characteristics, temperature and
pressure of the well to select a treatment which will
minimize corrosion effectively
JuanManuelGarro,CorrosionEngineer,Pluspetrol
11.40 Question & Answer Session
11.50 Lunch In Exhibition Showcase Area
CORROSION CONTROL METHODS
12.50 Identifying The Optimal Corrosion Control
Methodologies Across The Most Problematic Areas
Facing Corrosion Within Well Design
• Sucker rod corrosion: evaluating key methodologies
for preventing pump corrosion within high salinity
wells to minimize well failures
• Flow line corrosion: identifying a chemical treatment
that effectively combats oil, gas and sulphuric acid
corrosion to prevent pipeline breakages
• Tubing corrosion: how an operator has evaluated
the tubing pigments downhole to select a chemical
treatment which will prevent H2S and CO2
equipment failures
• Capillary injection corrosion: examining if wells
can remain productive with paraffin downhole to
determine if chemical investment is required
• Bacteria corrosion: classifying corrosion chemical
treatments within production facilities over 10 years
old
• Water quality corrosion: understanding how to
effectively run chemicals from the surface to
downhole to extend the run life of the rod and pump
OscarOrellana,ProductionSupervisor,Total
1.20 Question & Answer Session
INTERVENTION
1.30 Minimizing Non-Productive Time During
Interventions To Reduce The Cost Of The Workover
Operation
• Identifying how to reduce standby times within
intervention operations to reduce the cost of the
workover
• Defining the technical limit for workover operation
drilling services to prevent complex workover
operations damaging the economics of a well
CarlosLaluf,HeadOfInternationalEngineeringOperations,
AzabacheEnergy
2.00 Question & Answer Session
INJECTION
EXAMINING THE EFFECTIVNESS OF WATER AND
POLYMER INJECTION, WATERFLOODING, CHEMICAL
TREATMENTS AND CHEMICAL TRACERS IN OPTIMIZING
SECONDARY RECOVERY
WATER INJECTION PANEL
2.10 Evaluating Injection Assembly And Reservoir
Dynamics To Ensure Waterflooding Optimizes Sweep
Efficiency Within Multi-Layered Reservoirs
• Evaluating injection pressure, volume and length
of time to inject the reservoir to identify the optimal
design for optimizing recovery
• Quantifying injector pressure variance across fields
to identify the pressures that led to maximum
recovery increases
• Qualifying the optimal flow injection rate and water
shut off point to identify if lower or higher flood rates
will improve recovery factor
• Identifying the optimal point within a well’s run life to
stimulate the reservoir to prevent production decline
• Selecting how many reservoir layers should be
flooded simultaneously to assess what is the optimal
injection vertical sweep efficiency
• Calculating the cost of a waterflooding project;
estimated well run life and investment cost to
determine if well replacement is more cost effective
• Identifying methodologies for perforating thin
waterfields layers to prevent waterflooding all layers
and damage overall well recovery
FranciscoQueralt,HeadOfFacilities&Construction,
AmericasPetrogas
2.40 Question & Answer Session
2.50 Afternoon Refreshments In Exhibition Showcase Area
WATERFLOODING WATER TREATMENT
3.20 Defining The Optimal Water Quality And Volume
Needed For Flooding To Calculate Treatment
Requirements And Costs
• Defining the minimum water injection quality which
is compatible with the reservoir to prevent corrosion,
scale and bacteria in the pump, rod and tubing
• Understanding the level of brine water solid and gel
removal for recycling to reduce the volume of fresh
water sourcing required for waterflooding
• Evaluating how water treatment chemistry can be
matched to water qualities to avoid surface and
downhole decomposition
• Defining the water treatment plants, floatation units
and chemicals required to reduce ion and sulphur
content and water salinity
• Analyzing how electricity changes within the water
can be used to separate the water and corrosion
materials to prevent deposition
• Comparing the cost per barrel of treatment to the
chemical’s ability to clean the water to ensure the
operating cost reduces the OPEX
FranciscoQueralt,HeadOfFacilities&Construction,
AmericasPetrogas
3.50 Question & Answer Session
POLYMER INJECTION
4.00 Identifying The Optimal Polymer Injection
Technique To Improve Aerial Sweep Efficiency And
Prevent Water Diversion
• Evaluating well surveillance data to determine if
polymers can successfully increase the sweep
efficiency within a waterflood project
• Matching the polymer to the reservoir pressure,
temperature and fluid movement to:
• Ensure the treatment will have the desired
transit and activation time within the reservoir
• Prevent cooking through overheating the
polymer
• Avoid a change in polymer elasticity due to high
gas content
• Designing the polymer injection rate to improve
the EOR of the well
CarlosBerto,HeadOfOperations,Tecpetrol
4.30 Question & Answer Session
MONITORING & CHEMICAL TRACERS
4.40 Analyzing The Monitoring Benefits Of Chemical
Tracers In Evaluating The Success Of The Waterflood
Operation And Improve Future Injection
• Utilizing tracers to compare the predicted and
actual vertical and aerial sweep efficiency of the
waterflood to determine if production increases can
be attributable to the EOR
• Assessing how monitoring injection through the
SCADA system can identify well failures to improve
the run life of the well
• How an operator utilized water tracer results to
lower the water cut by identifying the high water
content layer and avoiding injection
• Outlining how water tracer data has improved
injection through defining the optimal reservoir
injection pressure to increase production recovery
• Assessing if using chemical tracer data can ensure
only specific reservoir layers are flooded to maximize
well production
5.10 Question & Answer Session
5.20 Chair’s Closing Remarks
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