presentation villahermosa 2014
TRANSCRIPT
![Page 1: Presentation Villahermosa 2014](https://reader034.vdocuments.us/reader034/viewer/2022051522/589d92a41a28abcc498bbd2c/html5/thumbnails/1.jpg)
MULTIPHASE MEASUREMENT FOR CONTROL OF PRODUCTION FROM OIL AND GAS WELLS
EXPOSITOR - ANDREW JAMIESON
COMPAÑÍA - NEFTEMER LTD
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Objectives of presentation
Review role of Multiphase Measurement
Pipeline management
Well management
Review history of multiphase metering
Emphasis on the different approaches
• Western oil industry and Russia
Illustrations of continuous well monitoring
Large potential benefits
Slug detection and suppression
Example of use of multiphase measurements
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Introduction
Oil and gas industry has thrived for 150 years
Limits to world reserves
• Much wider range of hydrocarbons produced
• Must be done in cost-effective manner
A “Multiphase Infrastructure” has grown
Multiphase well management
Multiphase pipeline operation
Multiphase measurement and monitoring
Plays critical role in this infrastructure
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Multiphase Technologies
Multiphase pipeline operation
Multiphase pumping
Multiphase pipeline integrity systems
Severe slug suppression
Multiphase well management
Intermittent well testing
Continuous well monitoring
Severe slug suppression
Multiphase flowrate and composition
Important in all of these technologies
Severe slugging appears in both
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Multiphase pipeline operation
Multiphase pumping
Unseparated well fluids transported
• production facilities at much longer distances
Work over a specific range of gas volume fractions
Need flowrate and composition
• For pump control and protection
Multiphase pipeline integrity systems
Don’t exist yet, to my knowledge
Long multiphase pipelines installed
• Subsea tiebacks of 50 km
BP Gulf of Mexico oil spill
• can be regarded as failure of pipeline integrity
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Impact of multiphase technologies
Changing to multiphase technologies
Forces changes to whole field development plan
Requires a change in ways of thinking
Example
Gas condensate field development
• Utilises multiphase pipeline
Wanted to use wet gas metering
• Would save high cost of separators
Critical to know when formation water appeared
• Pipeline must be protected against hydrates
• No multiphase formation water detector available
Conventional separator metering installed
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Production Reporting Requirements
Allocation and Sales Agreements
Safety, Environmental and Operational Requirements
Local
Processing
Secure
Data link
Office
Processing
Secure
Data link
Further
Processing,
Reporting
INFORMATION
Packaging:
e.g. land,
offshore,
subsea
Comms link
e.g. wire,
radio,
microwave
Packaging
Comms link
e.g. wire,
radio,
microwave
Packaging MECHANICAL
Data Integrity checks
Process simulation models
Calibration information
CONTRACTUAL
LEGISLATIVE
BUSINESS NEEDS
Sensors
Sensor
packaging
and
installation
FUNCTIONAL ASPECTS OF MODERN METERING,
MEASUREMENT AND MONITORING SYSTEMS
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Why have a multiphase
infrastructure?
What is the business case?
Are there significant cost savings?
• In development, operations and maintenance
Are there significant improvements in ability to
manage operations?
• own production, third parties, governments, environment
If answers are “yes”, then we should go further
What is the applicable regulatory framework?
Can the existing framework be used or extended?
• This should be answered in a structured manner
Is there sufficient knowledge to allow this?
• In some area “yes” and in others “no”
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Development of Multiphase Meters
We have answered “Why measure?”
Next: - “What do we want to measure?”
There are types of multiphase fluid
• Many ways to classify them
Wells and fields change with time
Need to estimate field or well production profile
• How else can we specify the measurement equipment?
I like to use “Multiphase triangle”
Pictorial way to represent applications
• Easily display well profiles
There will NOT be a universal “multiphase meter”
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Multiphase triangle
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Multiphase triangle
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Multiphase Volume Fraction Triangle
Wet gas categories:
- Humid gas from separators
- Humid gas with entrained liquid
carryover and/or occasional
slugs of liquid
- High GVF multiphase fluids,
GVF > (say) 90%
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Mass Fraction Triangle - Gas 10 kg/m3
10%
20%
30%
40%
50%
60%
70%
80%
90%
10%
90%
20%
80%
30%
70%
40%
60%
50%
50%
60%
40%
70%
30%
80%
20%
90%
10%
Gas
Water Oil
LVF 0.1%
LVF 0.2%
LVF 0.5%
LVF 1%
LVF 2%
LVF 5%
LVF 10% LVF 15%
LVF 50%
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Mass Fraction Triangle - Gas 50 kg/m3
10%
20%
30%
40%
50%
60%
70%
80%
90%
10%
90%
20%
80%
30%
70%
40%
60%
50%
50%
60%
40%
70%
30%
80%
20%
90%
10%
Gas
Water Oil
LVF 0.2%
LVF 0.5%
LVF 1%
LVF 2%
LVF 5%
LVF 10%
LVF 15%
LVF 50%
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Mass Fraction Triangle - Gas 200 kg/m3
10%
20%
30%
40%
50%
60%
70%
80%
90%
10%
90%
20%
80%
30%
70%
40%
60%
50%
50%
60%
40%
70%
30%
80%
20%
90%
10%
Gas
Water Oil
LVF 1%
LVF 2%
LVF 5%
LVF 10%
LVF 15%
LVF 50%
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Wet gas at different densities
Figures for gas densities
10, 50, 200Kg/m3
At low densities, wet gas dominates
At high densities, wet gas significant
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Measuring “unseparated flow”
Multiphase measurement techniques
Compact separation systems
• Rough separation into liquid and gas
• Detailed measurements on separated phases
Phase fraction and velocity measurement
• Identify fractions of oil, water and gas
• Determine the usually different phase velocities
Tracers
• Injected dyes for water and oil
• Useful for wet gas
Pattern recognition
• Low cost sensors and sophisticated computation
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Development approaches – West
Multiphase test loops seen as way forward
Oil (refined), water, gas(air) mixed
• Passed through horizontal or vertical test sections
• Fluids separated for recombination and recirculation
Concept meters designed to operate
On these artificially generated multiphase flows
Recognised that test loop multiphase flow
• might not be the same as real well flows
Difficulties arose when applied in field
In practice difficult to verify meters in the field
Slowly operational experience has built up
Multiphase meters are slowly being accepted
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Development approaches – Russia
Relatively low production rates
Low cost meter was essential
Clamp on fast gamma densitometer available
Could survey large number of wells
Establish flow characteristics
Investigate fluctuating density signal
For suitability for multiphase flow measurement
Now meter-per-well installed on field
Heavy oil in Arctic Russia
Russian standards for fluids extracted
Development of field verification system
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Outlook for development
Neither approach is ideal
Test loops don’t simulate well fluids accurately
Manufacturers can’t easily get access to real wells
Can test loops simulate wells better?
Need to redesign test loops
Generate more realistic multiphase flows
Field verification techniques required
Oil companies are not investing in multiphase
research
The potential benefits are still large
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Well management
Current practice
Not to monitor wells continuously
Well testing for several hours per month
• Fixed or mobile test separators
• Mobile multiphase meter assemblies
• Problem wells may receive more attention
Key assumptions
Wells produce in a stable manner
Switching to test does not affect production
BUT THESE ASSUMPTIONS ARE SELDOM VALID
• Later slides will demonstrate this
Continuous monitoring
Long recognised as key to optimising production
Requires inexpensive measurements per well
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Дебит по жидкости (т/сут) Обводненность (%) Расход газа (м3/сут)
Скважина 8331 (НН2Б 44-30)
Liquid flowrate (T/day) Watercut (%) Gas flowrate (m3/day)
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Дебит по жидкости (т/сут) Обводненность (%) Расход газа (м3/сут)
Скважина 8331 (НН2Б 44-30)
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Дебит по жидкости (т/сут) Обводненность (%) Расход газа (м3/сут)
Скважина 8331 (НН2Б 44-30)
Liquid flowrate (T/day) Watercut (%) Gas flowrate (m3/day)
JuneJuneJuneJuneJune JuneJuneJune
Beam Pumped Well
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Downhole centrifugal pump
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Liq
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Скважина 3026 (ЭЦН 80-1400)
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Скважина 3026 (ЭЦН 80-1400)
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Down-hole screw pump
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Дебит по ж идко сти (т/сут) О бв о дненно сть (% ) Р асхо д газа (м3/сут)
Скважина 3308 (ЭВН 25-1500)
Liquid flowrate (T/day) Watercut (%) Gas flowrate (m3/day)
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Дебит по ж идко сти (т/сут) О бв о дненно сть (% ) Р асхо д газа (м3/сут)
Скважина 3308 (ЭВН 25-1500)
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Дебит по ж идко сти (т/сут) О бв о дненно сть (% ) Р асхо д газа (м3/сут)
Скважина 3308 (ЭВН 25-1500)
Liquid flowrate (T/day) Watercut (%) Gas flowrate (m3/day)
4 June 5 June 6 June 7 June 8 June 9 June 10 June 11 June
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Comments on pumped wells
These are representative of TYPICAL wells
Beam pump well
Liquid flowrate steady; gas breakout in well bore
Centrifugal pump well
Liquid flowrate similar to that from formation
Liquid production varies by ~50% in one day
When do you test such a well?
Screw pump well
Similar to the centrifugal pump well
Again, when does one test such a well?
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Well data 1:
Density vs. Time (5 hours)
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Well data 3:
Density vs. Time (10 hours)
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Well data 5:
Density vs. Time (3 hours)
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Well data 6:
Density and Flow vs. time (21 hrs)
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Comments
Problem well
Operators unable to test it
Five slides illustrate different patterns
Multiphase data taken from 15 day record
One slide illustrates density and flow
Over a 21 hour period
Wide variations in flow pattern
Low and high liquid “wet gas”
Various slug flows
Surging flow
Not suitable for intermittent testing
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Nasty oily slug must
be controlled
Dregs of ice cream, ice &
lemonade, 3 phase flow Dregs of oil, gas & water,
3 phase flow
Slug Suppression
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Problems with
Slugging is due to reduced well pressure
In brown ‘older’ fields like the North Sea
Slugging gives operational problems
Most in deep-sea fields
In oil fields where there is proportionally a higher
amount of water in the oil.
Big problem - losses in production.
World wide loss - estimate $200bn p/a
• ~5MMBbl/d or ~6% of world oil production
North Sea, one major oil company $18m p/a
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Slug control and TSB
In 2007 UK government (TSB) funded a 2 year programme
Extend the life of North Sea reserves with cost effective
solutions.
Generate benefits to the UK
In places there is still 50% oil reserves left in the North Sea - but
the dregs are difficult to extract.
The innovators of the slug control system (named below) can
now export the technology for world wide applications.
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TSB 2-year programme activities
VR
Ethernet
Neftemer
DeltaV
Three-phase Facility
Inferential Slug Controller
RS232OPC Link
Coriolis
Method
Using Cranfield test rig
Neftemer meter (data up to 250 Hz)
SPT OLGA software
Data from Chevron
Extensive well data
Visits to Alba platform
Object
Forecast slug imminent arrival.
Taming the slugs by regulating the control valve
Cranfield Developed System
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Our answer to the problem is regulating
the flow through the control valve
PCA
3
6
0 200 400 600 800 1000 1200 1400 1600 1800
Riser Top Valve
20
35
50
0 200 400 600 800 1000 1200 1400 1600 1800
%
Riser DP
0.5
1
1.5
0 200 400 600 800 1000 1200 1400 1600 1800
Barg
Riser Top Density
0500
1000
0 200 400 600 800 1000 1200 1400 1600 1800Time [s]
kg/m
3
Before slug control < > After slug control
Control valve has been alerted
by the slug control system.
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Energy Innovation
and future benefits.
Extends life of North Sea revenue.
Existing platforms can be upgraded
With standard off-the-shelf equipment
Our system is simple Installed on the platform above the sea.
NO complicated subsea, seabed or down well instrumentation required.
Equipment is easily attached onto existing piping Slug control system interfaces with existing control equipment.
Can increase production by about 11% per day Most end users happy with 4%
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Conclusions
Multiphase technologies important
for the oil and gas industry
• Huge savings can be made
Necessary to consider production system afresh
Multiphase technologies impact on each other
Continuous monitoring of flow and density
allows better assessment of well production
Suppression of severe slugs good example
continuous monitoring of multiphase parameters
• production facilities stabilised
• production to be enhanced
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Thanks for your attention!
Questions?