Artificial Lift Screening and Selection

Artificial Lift Screening and Selection
Master Class
Andres Martingano
Artificial Lift 2013 – Praxis Interactive Technology Workshop

Agenda
• Introduction: The Need
• AL Selection Process Overview
• Some Common (and Less Common) Options
• Step 1: Screen
• Step 2: Evaluate• Step 2: Evaluate
• Step 3: Select
• Summary
Page 2Artificial Lift Screening and Selection9 Sep 2013

Agenda
• Step 1: Screen
• Step 3: Select
• Summary

The Need: One approach
• Liquid production profile with initial natural flow period
70
100
“Delay AL ”
approach
-20
10
40
70
0 20 40 60 80 100 120
LiquidRate
Time
Good Natural
Flow
Period
Complement
Reservoir
Energy
Provide
External
Energy
Increased need for energy to lift fluid
(depletion, WC increase)

70
100
The Need: A different approach
• Liquid production profile with AL inception on day 1
“Accelerate
-20
10
40
70
0 20 40 60 80 100 120
LiquidRate
Time
Complement
Reservoir
Energy from Day 1
Late Introduction of
Artificial Lift
“Accelerate
production”
approach

The Need: Business!
• In technical terms, we are always doing the same thing:
– adding energy to the fluids in the wellbore to produce them to
the surface
• In terms of managing the reservoir and the production, the
approaches generally produce different resultsapproaches generally produce different results
– Field life
– Reserves
– Economics
AL screening and selection is more than a technical exercise,
IT’S BUSINESS!

Agenda
• Step 1: Screen
• Step 3: Select
• Summary

AL Selection
AL Selection as a Business Process
• What are the desirable characteristics in this process?
Unbiased Documented Repeatable Reliable
Incremental Improvements
Quality Assurance
9 Sep 2013 Page 8Artificial Lift Screening and Selection

AL Selection During the Life of the Asset
Exploration and
Appraisal
•Data gathering
•Well
performance
testing
Development
•FDP definition
•Completion
design
•Artificial lift
selection
Operation
•Monitor
performance
•Evaluate failures
•Re-design and re-
select equipment
if needed
Life Stages of an Asset
selection
•Well operation
philosophy
•Implementation
select equipment
if needed
Little data
•AL selection unimportant
Data for FDP
•Little constraints on selection and design
Operations Data
•Regular data acquisition
•Production
•Artificial lift KPIs
Artificial Lift Screening and Selection Progress

AL Selection Impact on Asset Value
VALUE

AL Selection Process
• Three-step process and tools used
• The process is essentially the same at the stage of FDP or field
operation, except that during operations:
• Designs can be optimized, but
• There can be less flexibility to adopt a different AL method
Attribute tables
LOF Design
Economics
and
Scorecards
1. Screen
2. Evaluate
3. Select
• There can be less flexibility to adopt a different AL method

AL Selection Process: Influence Diagram
Reservoir Data
Pressure and
Temperature
Permeability
Distribution
Productivity Damage
Drive
Mechanism
Net Pay
Distribution
Well Location
Onshore Offshore Platform
Subsea
Well Trajectory
Productivity Damage
through Completion
or Production
Well Reservoir-Face
Completion
Fluid Data
PVT properties
Viscosity
Corrosive
Conditions
Potential for organic
/ inorganic
depostions
Well Upper
Completion (casing
and tubing)
AL Method
Surface Facilities
Economics

AL Selection Process Overview
• The main points are
– In the planning phase
• AL selection and performance prediction has to provide feedback
into the FDP
• Improve concept selection and planning• Improve concept selection and planning
• Increase asset value
– In the operating phase
• Important decisions like surface facilities and well completions are
largely fixed
• Main scope could be reduced to optimization

Agenda
• Step 1: Screen
• Step 3: Select
• Summary

Widely Used ...
• GL
• ESP
• SRP
Even Less Used
• HSP
• ESPCP
• HDESP
Some AL Options
Less Used ...
• HPP
• JP
• SRP
• PCP
• PL
• HDESP
• Wellhead Ejectors
9 Sep 2013 Artificial Lift Screening and Selection Page 15

Advantages
• High degree of flexibility
for design rates
• Very few moving parts
• Allows full-bore tubing
access
Limitations
• May be uneconomical
for few wells
• Fluid viscosity
• Achievable BHP
GL: Typical Pros and Cons
access
• Minimal space
requirements for surface
equipment
• Multi-well production
from single gas source
• Multiple or slimhole
completion
• Achievable BHP
• Higher FTHP for same
liquid rate
• Limited gas injection
rate (depending on
orifice)
• Well integrity concerns
Image courtesy of Weatherford

GL: Some Options to Enhance The System
• Well integrity
– Dual valve side-pocket mandrels
– Metal to metal seal valves
– Use of corrosion-resistant materials (inconel)
– High-pressure injection valves
• Higher flexibility• Higher flexibility
– Surface-operated electric GLV
– Breaking-out gas device to improve stability
• Better rate control
– Venturi GLV
• Application to few wells or marginal fields
– Option to buy HP gas from external source

Advantages
• High rates and depth
• Good efficiencies at
Q>1000bpd
• Minor surface
Limitations
• Available electric power
• Casing size limits pump size
• Limited capacity to adapt to
reservoir performance
changes
ESP: Typical Pros and Cons
• Minor surface
equipment needs
• Good in deviated wells
• Can be used for well
testing
reservoir performance
changes
• Difficult to repair in the field
• Free gas and solids handling
• Emulsions might be formed
with high viscosity fluids
and water
• Workover required to
change

ESP: Some Options to Enhance The System
• Higher flexibility
– Use of VSDs
– Use of gas separators
• Lower costs
– Alternative ESP deployment (cable, CT, WRESP)– Alternative ESP deployment (cable, CT, WRESP)
– ESP dual systems
– Improved monitoring
• Use in Reduced wellbore sizes
– Application of permanent magnet materials to reduce motor
size, enabling through-tubing installation

Advantages
• Adaptable to a wide range of
well depths and deviations
• Good handling of entrained
gas and solids
Limitations
• Some require
specific bottom-hole
assemblies
• High-pressure
JP: Typical Pros and Cons
gas and solids
• No moving parts
• Can be circulated into and
out of operating position for
repairs
• Typical repairs (change
nozzle and throat or o-ring
seals) can be done on site
• High-pressure
surface line
requirements
• Lower horsepower
efficiency

JP: Some Options to Enhance the System
• Avoid water-handling challenges
– Use dead crude as a power fluid
• Economics
– JP inefficiency (higher CAPEX for power fluid requirements)
might be offset by lower OPEX through LOFmight be offset by lower OPEX through LOF

Advantages
• Adaptable to a wide range
of well depths and
deviations
Limitations
• Solids handling
• Requires specific
bottom-hole
assemblies
HPP: Typical Pros and Cons
out of operating position
for repairs
• Positive displacement
pump allows greater
drawdown
• Multi-well production from
single surface package
assemblies
• Medium rates
• Requires service
facilities
• Free gas
• Requires high-pressure
surface lines

Advantages
• High system efficiency
• Economical to repair and
service
• Positive displacement pump
allows high drawdown
Limitations
• Potential for tubing
and rod wear
• Limited gas-
handling capability
SRP: Typical Pros and Cons
Positive displacement pump
allows high drawdown
• Upgraded materials can reduce
corrosion concerns
• Can adapt to production
changes through stroke length
and speed changes
• High salvage value for surface
and downhole equipment
handling capability
• Limited to ability of
rods to handle
loads
• Environmental
concerns
• Visual impact

SRP: Some Options to Enhance the System
• Enhance fluid handling capability
– Gas separators
• Reduce rod string wear
– Use centralizers
– Use COROD– Use COROD
• Minimize surface impact
– Different choice of surface units (e.g. LRP)

Advantages
• Low capital cost
• Low surface profile
• High system efficiency
• Simple installation, quiet
Limitations
• Limited depth
capability
• Temperature
• Sensitive to produced
PCP: Typical Pros and Cons
• Simple installation, quiet
operation
• Pumps liquids with solids
• Low power consumption
• Portable surface equipment
• Low maintenance costs
• Use in directional /
horizontal wells
• Sensitive to produced
fluids
• Low volumetric
efficiencies in high-
GOR wells
• Potential for tubing
and rod coupling wear

PCP: Some Options to Enhance the System
• Temperature and Fluids Sensitivity
– Alternative elastomers
– Metal stator PCPs
• Challenging well conditions with sand or gas
– Use charge pumps– Use charge pumps

Advantages
• Uses the well’s energy
• Dewatering gas wells
• Rig not required for
installation
Limitations
• Low potential rates
• Poor solids handling
• Greater effort to
optimize
PL: Typical Pros and Cons
installation
• Easy maintenance
• Keeps well cleaned of
paraffin deposits
• Handles gassy wells
• Good in deviated wells
• Can produce to depletion
optimize

Other Systems
• Hydraulic Submersible Pump (HSP)
• Electrical Submersible PCP (ESPCP)
• Hydraulic Diaphragm ESP (HDESP)
• Wellhead Ejectors (Surface Jet Pumps)
• ... and others...• ... and others...

AL Options: The Message
• Do not narrow down options too much at an early stage
– There are more things to consider than the ‘typical’ scenarios
for AL system application
– New technologies and developments can enhance the
applicability and performance of AL systems for differentapplicability and performance of AL systems for different
scenarios
– There are less commonly used AL systems which could work for
your asset
– Use industry experience to assess track record (papers, case
studies, colleagues)

Agenda
• Step 1: Screen
• Step 3: Select
• Summary

AL Selection: Screen Phase
• Qualitative comparison – eliminate unsuitable technologies
• Charts and attribute tables might be used
Attribute tables1. Screen
• Attribute tables are preferred, and should be customized for
the development in question
LOF Design
Economics
and
Scorecards
2. Evaluate
3. Select

Screening Common Options: ‘Quick-look’
Charts For High Rates
• Screening of High Rate Applications
25,000
30,000
35,000
AL Applicability Based on Rate and Depth
GL
ESP
JP
0
5,000
10,000
15,000
20,000
25,000
0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000
LiquidRate(bpd)
Lift Depth (ft TVD)

Charts For Low Rates
• Screening of Low Rate Applications
3,500
4,000
4,500
AL Applicability Based on Rate and Depth
HPP
SRP
PCP
0
500
1,000
1,500
2,000
2,500
3,000
0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000
LiquidRate(bpd)
Lift Depth (ft TVD)
PL

Attribute Table
Sucker Rod Pump
(SRP)
Progressive Cavity
Pump
(PCP)
Gas Lift
(GL)
Plunger Lift
(PL)
Hydraulic Piston
Pump
(HPP)
Jet Pump
(JP)
Electric
Submersible Pump
(ESP)
Operating depth (ft TVD)
100 -
16,000
2,000 -
6,000
5,000 -
15,000
8,000 -
19,000
7,500 -
17,000
5,000 -
15,000
1,000 -
15,000
Typical operating rate (bpd)
5 -
5,000
5 -
4,500
200 -
30,000
1 -
5
50 -
4,000
300 -
15,000
200 -
30,000
Operating temperature (°F)
100 -
550
75 -
250
100 -
400
120 -
500
100 -
500
100 -
500
100 -
400
• Typical vendor-provided screening table
Operating temperature (°F)
550 250 400 500 500 500 400
Corrosion handling
Good to
Excellent
Fair
Good to
Excellent
Excellent Good Excellent Good
Gas handling
Fair to
Good
Good Excellent Excellent Fair Good
Poor to
Fair
Solids handling
Fair to
Good
Excellent Good
Poor to
Fair
Poor Good
Poor to
Fair
Fluid gravity (°API) > 8 < 35 > 15
GLR = 300 scf/bbl
/1000ft depth
> 8 > 8 > 10
Servicing
Workover or
Pulling rig
Workover or
Pulling rig
Wireline or
Workover rig
Wellhead Catcher
or Wireline
Hydraulic or
Wireline
Hydraulic or
Wireline
Workover or
Pulling Rig
Prime mover
Gas or
Electric
Gas or
Electric
Compressor Reservoir energy
Multicylinder or
Electric
Multicylinder or
Electric
Electric Motor
Offshore application Limited Good Excellent N/A Good Excellent Excellent
Overall system efficiency (%)
45 -
60
45 -
70
10 -
30
N/A
45 -
55
10 -
30
35 -
60

Use of Tables and Charts
• ‘Standard’ screening charts and tables
– Good for a ‘quick-look’ screening
– Generally more useful to discard a few options than to pick a few
– May be limited in the options included
– May ignore extended applicability of particular systems using– May ignore extended applicability of particular systems using
materials or accessories not provided by them
– May not provide a full picture in terms of factors that can work against
the applicability of systems under specific conditions
– Ignore economics considerations
– Ignore people-related considerations
– Experts in specific systems can find ways to ‘push the envelope’
• A customized attributes table can overcome these limitations

Building a Better Attributes Table

Uptime
Surface Facilities
Factors
Well Factors
Start-up from Shutdown
Possibility of Expansion
Gas Availability
Power Availability
Location
Capacity Constraints
Remote
Offshore
Onshore
HSE Factors
Budget-Related
Factors
Vendor-Related
Factors
Staff-Related
Factors
Artificial Lift
Screening
Attributes
Reservoir
Management
Factors
Fluid Properties
Flow Assurance
Factors
Production
Factors Through
Field Life System Efficiency
Start-up from Shutdown

• Possibly, not all
the attributes are
important for a
given case
• Refine...
• Refine...

• Attribute Scoring Keep it simple
• Promote transparency
– No more than ‘good option’, ‘average option’, and ‘poor option’
(or ‘1’, ‘2’, and ‘3’ scores or similar)
– Define the options– Define the options
• ‘good’ = applicable, works, no problem
• ‘average’ = may be applicable, requires further analysis
• ‘poor’ = not recommended, known issues, not applicable

ALS # 1 ALS # 2 ... ALS # n
Attribute # 1
Attribute # 2
Attribute # 3
• Typical presentation (easily implemented in a spreadsheet)
Attribute # 3
...
Attribute # n
• Is documented
• Includes all important attributes
• Considers inputs from other disciplines

Agenda
• Step 1: Screen
• Step 3: Select
• Summary

AL Selection: Evaluate Phase
• Quantitative analysis – find conditions for AL systems operation
• Design systems to operate in the field
• Provide feedback to wells and facilities design
• Assess performance of the system under changing conditions
• Generate estimates for economics
LOF Design
Economics
and
Scorecards
2. Evaluate
3. Select

Formation-Face
Operating Envelope
• Realistic inflow
potential
• Well issues, related
to mechanical
integrity and flow
assurance. E.g.
Design AL for LOF
Conditions
• Different scenarios
• Early-life
• Middle-life
• Late-life
• Assess suitability for
changing conditions
Outputs
• Budget requirements
• CAPEX
• OPEX
• Production profiles
assurance. E.g.
Erosion produced
by sand and fines at
high rates,
formation collapse,
tubular collapse,
scale / asphaltene
deposition
• Reservoir issues,
e.g. gas or water
coning, or
problems
producing below
Pbp
changing conditions
• Provide feedback
• Well design
• Facilities design

• Formation-Face Operating Envelope – an example
BHP
VLP to be achieved
P
Minimumrate
orstableoperation
Qliq
Pbp
Pformation integrity
Qmin Qmax
Pres initial
Pres abandon Minimum allowable BHP
Minimumrate
forstableoperation

• Design AL for LOF Conditions
Expected
Production
Profiles
•GOR vs. Cumulative
•WC vs. Cumulative
•Reservoir Pressure vs. Cumulative
•Early Life
Define
Scenarios
•Early Life
•Middle Life
•Late Life
Design AL
for each
Scenario
•Determine power required to lift target rate
•Assess feasible target rate
•Design system
•Test design against uncertainty in production conditions and improve it
Generate
Outputs
•Feedback for well and facilities design
•Well performance for production profile forecast
•OPEX and CAPEX requirements, bearing in mind MTBF and production deferment

• DON’Ts:
– Create a single design for worst conditions: that is good as a
feasibility check but not to understand LOF requirements
– Ignore production losses / deferment due to equipment failure
• DO’s:• DO’s:
– Compare methods using a single formation-face operating
envelope
– Discuss options and requirement with other disciplines before
estimating budget needs

Agenda
• Step 1: Screen
• Step 3: Select
• Summary

AL Selection: Select Phase
• Quantitative analysis – economics
• Evaluate NPV of using different systems
• Understand where value is generated and lost
• Optimize design
LOF Design
Economics
and
Scorecards
2. Evaluate
3. Select

• Build cash flows for different alternatives and calculate NPV
– CAPEX (surface and well equipment)
+ Production
– Operating costs (energy. personnel, normal maintenance)
– Downtime deferred / lost production (due to failure)– Downtime deferred / lost production (due to failure)
– Intervention costs
– Equipment replacement
– Abandonment costs
+ Salvage value

• Compare NPVs
40
50
60
70
NPV(MM$)
Value Comparison
• Don’t stop here!
0
10
20
30
40
ALS #1 ALS #2 ALS #3
NPV(MM$)

• Understand where value is gained or lost
100
120
140
160
NPV(MM$)
0
20
40
60
80
100
NPV(MM$)

• Understand the prize for improving different areas
20
25
30
35
40
NPV(MM$)
0
5
10
15
20
NPV(MM$)
CAPEX
Interventions
OPEX
Production Losses
ReplaceEquipment
Abandonment

• Maximize option NPV
– CAPEX
• Phase investment
– Interventions and production losses
• Have rig available on the field full time• Have rig available on the field full time
• Design equipment to extend MTBF
– OPEX
• Analyze expenditures and identify opportunities for savings

Refine options
Refine budget Select and AL Contracting and
Refine options
for design and
implementation
Refine budget
requirements
Select and AL
system
Contracting and
Procurement

Agenda
• Step 1: Screen
• Step 3: Select
• Summary

Summary
• Overall Process
– AL screening and selection is a process that needs to be clearly defined
and documented for quality assurance
– Most value can be created or lost at the design phase
– Multidisciplinary collaboration is required for optimized solutions
• Screening
– Attributes for screening can be defined based on project needs– Attributes for screening can be defined based on project needs
– Scoring should be simple and documented to promote transparency
• Evaluation
– Formation-face operating envelope needs to be defined
– Design scenarios have to be considered for early, mid, and late life
– Test designs for suitability under uncertain scenario conditions
• Selection
– Calculate NPV
– Understand where value is gained or lost

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