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Expro CaTS Technology

Expro’s Cableless Telemetry System (CaTS) is a field-proven, battery powered, wireless data transmission system that offers operators immense advantages in the monitoring and control of both new and existing wells.
by

Nicholas Yarr

on 11 December 2015

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Transcript of Expro CaTS Technology

What is CaTS Technology?
System summary
CaTS Features
ART
Advanced
Reservoir Testing

BP Clair
Petrobras
Santos Basin
ART Overview
Wireless
Well Integrity
Monitoring

Wireless
Long Term
Monitoring

Enquiry process
Applications through the well life-cycle
Key Milestones
Well integrity
introduction
Below plug verification
Annulur Barrier
Verification
SEPCo
Pinedale Wyoming
Hardware and
Equipment
Gauge specification
Operations
Seabed Equipment
ADL
CaTS Subsea
Receiver
ADL
Funnel
Seabed
Anode
Counter
balance
weights
Subsea
cable
Debris cap
Expro can adapt the CaTS subsea receiver funnel receptacle for deployment on any 3rd party vendor’s debris cap

Acoustic dunking transceiver
Pre-job testing
Mobilise
Gauge deployment
Program & test gauges

Record all assets that are to be deployed

Transfer tools and equipment to rig floor

Rig up gauge to suspension device

Deploy gauge to depth

Verify gauge is operating in accordance with required test procedure
Subsea Equipment
Debris cap:

Client preference
Minimal equipment on seabed
Straight forward to install
Rig time critical


Basket:

Installed and verified offline from rig activities
Cable friendly
System commissioning
Data uploaded from seabed using the surface acoustic transceiver system

The transceiver is connected to the surface PC via the dunking and deck cables

On the MODU, the transceiver can be deployed through the moonpool or over the side of the rig

A support or supply vessel is normally used for routine data uploads

The transceiver is deployed on a winch or crane line ~10m below water line

P, T, date and time are decoded by the surface PC and presented as a csv file
Basket deployment
Debris cap deployment
System Schematic
Key system components comprise:

1. CaTS Downhole gauge

2. Wellhead/guidebase signal connection

3. Subsea Receiver and Remote Reference

4. Topside Data Retrieval unit with Dunking Sonde
Well placement and spacing is critical to the effective development of tight gas reservoirs

Tight matrix and micro darcy permeabilities make formation pressure measurements challenging

It can take months for pressures to stabilise and provide sensible readings due to transient impairment caused by overbalanced drilling etc.

Wireless monitoring provides a long term, retrofit, real time monitoring solution that can provide accurate measurements of the formation pressure

By monitoring for depletion driven reservoir pressure variations over extended time periods in multiple wells it is possible to determine the lateral continuity of the reservoir layers, the drainage area and shape
Developing tight gas reservoirs
Tight gas in Pinedale Wyoming

Micro Darcy sands

Up to 50 fluvial sands spread over a 6,000ft gross section

Discontinuous lenticular sand bodies

Significant uncertainty over lateral continuity, drainage area and optimal well spacing

Reducing reservoir uncertainty
10 wireless gauges installed in an old production well that was due to be abandoned

Used to monitor existing, plus some newly perforated zones

New well drilled 450ft away

Old well converted to a high value, multi-zone monitoring asset

Data was used to construct a detailed static and dynamic model

Helped to determine drainage area and optimise the future field development and well spacing

Reference: “From Liability to Cost Effective Data Gathering Opportunity” – presented at the SPWLA 46th Annual Logging Symposium 2005
CaTS
TM
is a
field proven

Ca
bleless
T
elemetry
S
ystem capable of transmitting real-time pressure and temperature data from a downhole battery powered gauge at depths of over 12,500ft
CaTS
TM
uses the
metallic structure of the well
as a conduit to transmit electromagagnetic signals (EM)
CaTS
TM
technology is
retrofittable
and can be installed into an existing completion using conventional methods
CaTS
TM
technology is
addressable
, this enables multiple system installations in a given well
CaTS
TM
telemetry is
duplex
and is also capable of transmitting commands from surface to a downhole receiver; this enables the control of downhole components
Over 175 Wireless gauge systems installed for monitoring applications globally

Wireless transmission ranges of >12,600ft

Monitoring durations of > 3 years

Up to 20 individual zones monitored in a single well

Advanced Reservoir Testing - “World first” long term monitoring of permanently abandoned subsea appraisal wells – 18 installations

New wireless safety valve trialled successfully

Barrier integrity verification in 11 subsea wells

Duplex (2-way) wireless communications from sand face to onshore control room in deepwater subsea wells
How does ART add value?
What reservoir uncertainties exist during field appraisal and development?
Drainage area
Reservoir shape
Size and volumes of reserves
Permeability
Connectivity of layers
Risk of compartmentalisation
Far boundaries
Reservoir model assumptions
Number of wells
Placement of wells
EUR
CaTS - Advanced Reservoir Testing
Well cost vs. value
CaTS Surface Read Out for DST
CaTS SRO
TM
is based on
field proven
downhole CaTS technology
transmits
real-time Electromagnetic EM
signals into the DST string and casing
facilitates early termination of the shut-in period,
saving rig time
TM
allows modification of tests to
maximise data capture
and avoid costly retests
provides a
diagnostic tool
to help analyse flow performance issues or uncertainties during the test
CaTS SRO
TM
CaTS SRO
TM
CaTS SRO
TM
CaTS SRO
TM
EXtract II - E-line SRO
15K psi / 150 deg C rated

20s – 2mins per data point real-time SRO updates

Access to historical data points from surface

Up to 21 days battery life

1s data logging to internal memory

1.8M data point memory capacity (40 days)

Dual gauge system redundancy

Bespoke gauge carrier integral to DST string

Premium thread connections

Options to externally mount gauges below packer

Sensor station
Active Pick-Up
EXchange - Fully Wireless SRO
15K psi / 150 deg C rated

2 – 15mins real-time SRO updates

Access to historical data points from surface

Up to 21 days battery life

1s data logging to internal memory

1.8M data point memory capacity (40 days)

Relay stations every 2,000ft (on average subject to well conditions)

Dual system redundancy throughout

Bespoke gauge carrier integral to DST string

Premium thread connections

Options to externally mount gauges below packer

Various clamp sizes available to suit all DST strings
Sensor station
Repeater station
TM
TM
No audio
No audio
Jack-up signal pick-up
Active Pick-Up mounted on DST string below mud line

Ported slickjoint feed-through required

1/4" TEC cable run from surface to APU tool

Cable connection from Data Aquisition Unit to cable spool

Optimal configuration to prevent interference from surface background noise
Offshore floater signal pick-up
Active Pick-Up mounted on DST string inside the riser, above the BOP

Hydrobond cable connected to APU

Hydrobond cable spooler located on drill floor

Cable connection from Data Aquisition Unit to cable spool

Optimal configuration to prevent interference from surface background noise
Job locations
Track record
Job planning
Job planning
Well resistivity
Downhole P/T
Tail ratio
Completion design
Surface background noise
Information gathering
Client questionnaire
Wellbore schematic
DST toolstring diagram
Well resistivity LAS file
Performance modelling
Response to client
Date rates
System longevity
Technical and commercial proposal
Well integrity overview
Norsok guidelines state that:

“There should be
two well
barriers available during all well activities and operations, including suspended or abandoned wells where pressure differential exists that may cause uncontrolled outflow from the borehole / well to the external environment”

..........Also states that for Initial Verification:

“When the well barrier has been constructed, its integrity and function shall be verified by means of
leak testing
by the application of differential pressure” or to perform “verification by other specified methods”

Pressure barriers and verification requirements
Australian Government report into the Montara Field blowout in the Timor Sea in 2009 concluded that ……

“The proximate cause of both disasters was failure of untested cement barriers. Both cement jobs failed to achieve proper zonal isolation”

So to be safe……

Barriers need to be
In- Place
and
Verified
The importance of verifying pressure barriers
During workover or P&A operations it is common to install both deep and shallow set plugs as pressure barriers

These barriers maybe located deep in the well

The sealing integrity of the deepest barrier can be verified by the application of a differential pressure from surface and using surface pressure sensing equipment

Due to the relatively small volume of fluid trapped between the upper and lower plugs, compared with the large volume of fluid above the plug, the application of pressure from surface, when used with surface pressure monitoring equipment, will not be able to verify the sealing integrity of the upper plug

Using the e-line and CCL used to deploy the upper plug as a signal pick-up, a solution was identified that allowed the pressure from below the upper plug to be transmitted to surface in real time when the differential pressure test from surface was being applied

A single RIH operation sets the plug and then verifies its sealing integrity when pressure testing from surface
Verification challenges of double barriers
Annulus Pressure
Monitoring
A light well intervention campaign was performed on 6 wells during 2011

Objective of the interventions was to prepare the wells for a rig workover

Operational programme called for the installation of 2 deep-set plugs
Project overview
System components - Topside equipment
5/16” monoconductor e-line unit

CaTS Receiver setup in the e-line control room - connected to the e-line via break-out box

Receiver easily switched in and out of the eline circuit
1. RIH and set lower plug in the 7" liner
Caliper survey run to confirm the tubing drift ID was clear, the general condition of the tubing and liner, particularly the condition at the plug setting depths…..

Lower plug run in hole on electric line

Correlate plug setting depth using the CCL

Activate plug setting tool and set plug inside the 7” liner
7" tubing
PBR
Production packer
7" tail pipe
PBR
7" liner hanger
7" liner
9 - 5/8" casing shoe
7" screen
2. Perform pressure test on lower plug

Perform inflow test on plug

Perform leak test on plug by applying approximately 210 bar differential pressure across it

Observe for leakage using surface pressure sensing equipment
7" tubing
PBR
Production packer
7" tail pipe
PBR
7" liner hanger
7" liner
9 - 5/8" casing shoe
7" screen
3. Punch holes in tubing and tail pipe
Punch holes in the tailpipe to evacuate any trapped gas behind the tail-pipe

Punch holes in the tubing to displace kill fluid
7" tubing
PBR
Production packer
7" tail pipe
PBR
7" liner hanger
7" liner
9 - 5/8" casing shoe
7" screen
4. RIH and set upper plug and CaTS Gauge
Test Wireless gauge on the deck

Rig up the gauge below the upper bridge plug

RIH and correlate plug setting depth above the perforations in the tailpipe

Activate plug setting tool and set plug inside 7” tail-pipe
7" tubing
PBR
Production packer
7" tail pipe
PBR
7" liner hanger
7" liner
9 - 5/8" casing shoe
7" screen
5. Perform pressure test and monitor pressure below plug at surface
Position CCL approximately 5m above plug

Leak test plug by pressuring up the well head pressure to 200 bar for 30 minute

Pressure data from below the plug is transmitted to surface via the e-line cable
7" tubing
PBR
Production packer
7" tail pipe
PBR
7" liner hanger
7" liner
9 - 5/8" casing shoe
7" screen
Results for well No. 1 - Upper pressure barrier verified OK
Results for well No. 2 - Upper pressure barrier verified OK
Results for well No. 3 - Upper pressure barrier not verified
Results for well No. 3
Full data set recovered from the CaTS gauge memory after workover
Conclusions
A key element of achieving Excellence in Well Integrity is about having the necessary barriers in place and being able to verify them

Using a new wireless gauge technology it is now possible to verify the sealing integrity of the upper plug in a dual barrier sealing arrangement

Uses standard completion hardware with no requirement for electrical penetrations through the plug and is not influenced by cement plugs

Requires no additional components in the logging string – meaning no additional risks in tool performance or reliability

Compatible with any 3rd party e line provider’s cable, CCL and plug setting tools, providing for flexibility in deployment options

Plug depth correlation, setting and pressure sealing verification can be completed in a single run in hole, resulting in operational efficiencies
No audio
System components - Downhole
DST
Surface Read-Out

CaTS
TM
Background
Track Record
Wireless Downhole
Flow Control

SPE 102745
Tight gas monitoring - delivering a dual purpose well to satisfy monitoring and production objectives
SPE 108435
Clair Field - Reducing uncertainty in Reservoir Connectivity during reservoir appraisal
SPE 124100
Mungo Platform - A new wireless retrofit solution to restore real-time BHP/BHT data after a permanently installed monitoring system has failed
SPE 130427
Development and qualification of a new wireless controlled retrofit safety valve
SPE 145581
Ormen Lange: Delivering Production Optimisation and an improved reservoir understanding using a new cableless sandface monitoring system
IBP2274_14
Expro CaTS for Advanced Reservoir Testing in the Santos Basin pre-salt
Published Papers
Countries and Clients
Downhole battery management
What is Wireless Well Solutions?
Aberdeen
Stirling
Great Yarmouth
Reading
Chandlers Ford
Ringwood, Hampshire
Business unit within Expro

Specialises in downhole wireless telemetry

Located in Hampshire, Southern England

In-house research, design, assembly and installation

90+ Employees

Software, Hardware, Mechanical Engineers

Production department

Operations Team

Research & development

Technical sales

Deliver technology directly to our clients or through our in-country teams

Where did the technology come from?
2015
2003
1997
2009
1999
2001
2005
2007
2011
2013
1993
1995
Development of the cableless telemetry system for pipe-line and in-well communications by Flight Refuelling Limited (FRL). Early trials for both subsea and land applications supported by BG
Initial trials of pipeline communications and in-well systems with BP
Extended field trials on in-well systems and further development by FRL in partnership with Shell Expro. First commercial installations.
Expro acquire Technology

Prove the technology in the market place

Standardise components

Continued development of well monitoring and In-Flow control solutions

Surface flowline data transmission – BP Colombia
Subsea Pipeline Communications – North Sea in 1998
Downhole trials – FRL & Shell Expro – Falmouth UK
Downhole early production
Standardised products - downhole
Onshore and offshore applications

Allows data transmission in the absence of any other communications infrastructure

Long transmission distances are possible

Pipeline security applications

Geothermal test well in UK

To prove feasibility and performance of a retrofit downhole wireless gauge

5.75” OD downhole development gauge

2000m data transmission range from downhole to surface

Results confirmed the product development strategy

Continued research and development

Commercial installations

2.5” OD downhole gauge

Transmits real time downhole pressure and temperature data to surface

>12 500ft transmission range

2 – 5 years gauge battery life expectancy

Data interface to clients SCADA systems providing data-to-desk

1-11/16" OD downhole gauge
Standardised products - surface
Technology Overview
No audio
FlowCAT
Storm chokes (SSCSV) are being deployed on mature assets where SCSSSV’s have failed or control lines are plugged and the cost of a workover cannot be justified

SSCSV’s (Storm chokes / velocity valves) are:-
Unreliable
Can shut-in unpredictably
Cannot be controlled from surface

A retrofit wireless flow control valve offers an attractive alternative and delivers increased production

Valve will remain open in response to repeated EM commands from surface

Failsafe close - Loss of the EM signal will cause the valve to close

Valve is reset from surface (without intervention) by the application of pressure

FlowCAT Downhole Wireless Safety Valve
Installation and Deployment
Key Performance Specification
Toolstring Drawing
Equalising Assembly
TM
TM
Audio
Prototype Size:

Maximum OD:

Length:

Pressure rating:

Temperature rating:

Metallurgy:

Seals:

Qualification:

Operation:

Response to close:

Response to open:

Flow Performance:

Intervention method:

Target life expectancy:

Range:

To suit 4.5” tubing and 3.812” nipple


3.6”

30 ft (excluding lock)

5,000 psi

Ambient to 125 deg C

Suitable for sour service (to NACE MR0175 – 2003)

Suitable for sour service

Tested in accordance with ISO 10432 (API 14A Class 1) - with exceptions

Failsafe closed

10 - 60 seconds

Typically 10 minutes

Equivalent to 1.9” ID

Wireline deployed / retrieveable

6 to 12 months between battery change out

0 - 2000 ft (offshore)

Cross section
Equalising sub
with adapter
Prong used to
jar sleeve open
Surface Equipment
Onshore transmitter
Offshore System Overview
Offshore transmitter
System Concept
The topside equipment certified under the ATEX directive

Output voltage and current limited

Certification is dependant on regular maintenance – cables and connections to the wells must be visually inspected for physical integrity and absence of significant corrosion every 6 months

Two types of signal transmitted – stay open & close now

Closure can either be fail safe (loss off power to surface equipment – no signals) or “forced” closure using the close now signal

Forced closure time ~ 10s and fail safe closure time ~60s

Forced closure initiated by button on TDU or by external interface switch
Offshore equipment - Transmitter Drive Unit (TDU)
Generates an encoded signal that drives the Wellhead Transmitter Assembly

19” enclosure x 3U height for mounting in suitable cabinet

Requires mains 110 or 240Vac, rated at 5A (fused at 3A)

ESD input 240Vac, 110Vac, 24Vdc, 12Vdc

Option to interface close signal
Mains IEC
power connector
ESD
connector
FlowCaT
signal
connector
Offshore equipment - Wellhead Transmitter (WHT)
Converts the signal from the TDU into the required voltage and current levels for transmission via the wells

Must be mounted close to the wells as defined by output cable lengths

No mains input

5 cable entries – 2 x output cables per well & 1 x cable from TDU

ATEX Flameproof EExd certified 640 x 520 x 332 mm (l x w x h)

Weighs 140 kg
Offshore equipment - Connection plates and cable
Cables

Cable from TDU to WHT should be rated for 5A, screened twisted pair, max length is 150m

2 qty output cables from WHT to each well, 4 in total. Each cable 95mm2, min length 10m (1.95mΩ), max length 15m

Connection plate (to well)

Made from ¼” copper plate and sized to suit flange / stud size

Usually attached to annulus wing valve – to allow longer studs to be installed if required
Installation Considerations
Requires stable mains power supply at surface to avoid false closures

Valve OD is 3.6” so only available in a size for 4 ½” completions or larger

Need to apply pressure from surface of 1,500psi above the closed in wellhead pressure after every valve closure event to re-open or commission the valve

Control panel to be located in a safe area

Valve is temperature rated to 125 deg C, need to be aware that BHT affects battery life at higher temperatures
Qualification Status
HALT testing completed at 125 deg C and 20g vibration

100 valve cycles completed during logged function and life expectancy testing, with >500 cycles completed in total

Valve pressure tested from below to 7,500psi (1.5 times working pressure)

Flow testing completed in a flow loop – observed 34psi pressure drop across the valve at 10,000 bbl/d

System integration test completed

Full system test in a land test well completed

Testing completed by an independent 3rd party test house in accordance with a modified ISO 10432 / API 14A class 1 procedure

6 month trial in an onshore gas well completed successfully
System benefits and advantages
Installed using standard wireline intervention equipment and procedures

Fail-safe closed design

Robust wireless telemetry protocol minimises the opportunity for “false-close” events

Compatible with both onshore and offshore platform environments

Requires no wellhead modifications, penetrations or additional spool pieces

Valve is resettable from surface without well intervention

Flexibility over setting depth using standard suspension devices

Ceramic sealing faces provide high integrity sealing; zero leak rate observed during repeated valve function testing

The surface transmitter has a flexible interface to the existing ESD control system

Retrofit Downhole Monitoring
Failed Permanent Downhole Gauge Replacement
Real time reservoir monitoring is critical for the effective management of any reservoir. Permanently installed reservoir monitoring instrumentation is generally installed as standard practice in the majority of offshore wells and whilst the reliability of such systems has improved significantly over the last decade, there are still many examples of wells around the world where these systems have failed prematurely.
Application background
Bore-Big, High-Rate Gas Wells
Big-bore, high flowrate completion designs can feature a high-set production packer and large bore 9-5/8” production liner.

This completion design makes it impractical to install a traditional cabled Permanent Downhole Gauge (PDG) system close to the producing sandface.

With separation distances of greater than 1,000 meters between the producing sandface and the PDG, and frictional pressure drops and gravity head differences to contend with, there is significant uncertainty in how the pressure measurements recorded by the cabled PDG relate to the true flowing sandface pressures.

For wells operating on drawdown constraint, reducing these uncertainties allows the drawdown to be optimised, which is critical to maximising production and exploiting the field reserves effectively.
Application background
System schematic
Equipment - Downhole
Equipment - Subsea
CaTS duplex mandrel – conveyed with completion

8.0” OD, 4.6” ID, ~10m long

5k psi differential, 10k psi absolute rating

Quartz crystal pressure sensor

Lithium battery powered

Bi-directional communications - from "reservoir to beach"

4 modes of operation:

Mode 1 - Data transmitted to a schedule
Mode 2 - On-demand Pressure Build-up
Mode 3 - Sleep mode
Mode 4 - System Diagnostics
Big-bore high-rate gas completion design - 9-5/8" Production Liner

CaTS Gauge instlled as part of the sand screen BHA

CaTS Downhole pick-up located at lower PDG mandrel

1/4" TEC cable installed from downhole pick-up to subsea tree

CaTS wireless hop between gauge mandrel and downhole pick-up
CaTS subsea transceiver - IWIS option 3 compliant
CaTS Downhole signal pick-up clamp assembly
Ormen Lange - Big bore completion design
7” lower completion with gravel pack

9 5/8” production liner

High set production packer with cabled PDG 1000m -1200m above the producing sandface

Cableless gauge mandrel located at the top of the sand screens
Ormen Lange - Results
6 systems were installed between 2009 and 2011:

20 months of data collected from A-5H
33 months of data from B-7H
24 months of data from D-3H
14 months of data from D-8H
25 months of data from D-7AH
No data from the system in D-1H

With deployment of the D-3H upper completion delayed, data was collected via the D-7AH subsea receiver, providing valuable data regarding the reservoir performance at the D template location

Useful diagnostic data during early stage well clean-up – data was used to confirm fluid gradient

Pressure build-up data collected in wells A-5H, D-7AH and D-8H
Ormen Lange - Pressure build-up data from the sandface
Ormen Lange - Conclusions
The high-rate big-bore completion design prevents placement of a traditional cabled pressure/temperature monitoring system in close proximity to the producing sandface, which introduces several uncertainties when looking to optimise production and manage the reservoir effectively. A cableless communications technology, based on EM communications, has been successfully applied to reduce uncertainties in the well bore and to gain an improved reservoir understanding. A cableless gauge system located close to the producing sandface in these big-bore high-rate gas wells offers several benefits:-

In drawdown constrained wells, having access to high accuracy flowing pressure measurements at the producing sandface enables the drawdown to be optimised and the flow rate to be maximised.

The cabled PDG, typically located 1000 to 1200 m higher up in the well, above the high-set production packer, can be correlated with the cableless gauge data across a range of flow rates to reflect sandface flowing conditions.

The data collected has been used to tune the lift curve correlations across the wider Ormen Lange Field.

Pressure transient analysis performed on the CaTS PBU data provides more representative permeability and skin values than the remotely located cabled PDG.

Having access to both the cableless gauge pressure data at the sandface, and the PDG data at the production packer, enabled calculation of the fluid gradient during early stage production clean-up. This proved valuable as a diagnostic tool in reducing uncertainties regarding the nature of the produced fluids and progress of the clean-up.

The CaTS Gauge installed in well D-3H is being used to monitor the reservoir pressure response even though there is no upper completion installed in the well. The D-3H data is being communicated through the formation and is being picked up using the cableless gauge infrastructure installed in well D-7AH.

Having two-way communications functionality between the onshore control room at Nyhamna and the cableless gauge provides the flexibility to request the sandface pressure temperature data at the time and frequency required, which has proved critical to the success of the project.
SPE 145581
Ormen Lange: Delivering Production Optimisation and an Improved Reservoir Understanding Using a New Cableless Sandface Monitoring System
SPE 145581- Ormen Lange: Delivering Production Optimisation and an Improved Reservoir Understanding Using a New Cableless Sandface Monitoring System
SPE 145581- Ormen Lange: Delivering Production Optimisation and an Improved Reservoir Understanding Using a New Cableless Sandface Monitoring System
SPE 145581- Ormen Lange: Delivering Production Optimisation and an Improved Reservoir Understanding Using a New Cableless Sandface Monitoring System
SPE 145581- Ormen Lange: Delivering Production Optimisation and an Improved Reservoir Understanding Using a New Cableless Sandface Monitoring System
SPE 145581- Ormen Lange: Delivering Production Optimisation and an Improved Reservoir Understanding Using a New Cableless Sandface Monitoring System
- Cableless Telemetry System
Equipment - Surface Receiver
Reducing reservoir uncertainty
SPE 124100 - Mungo Platform: A New Wireless Retrofit Solution to Restore Real Time BHP / BHT Data After a Permanently Installed Monitoring System has Failed - A North Sea Case History
Gauge specification
Thru-tubing gauge

Modular design

Lithium battery powered

28ft to 50ft long
(depends on battery pack quantity)

1-11/16" or 2-1/8" OD
(depends on battery pack type)

Corrosion resistant alloy

Full metel-to-to metal primary sealing

Additional battery sections can be added

on board memory capacity (100,000 data sets)

CaTS Relay Station means no limit to achievable transmission range
Pressure range: 0 - 10,000 psi (0 - 15,000 psi optional)

Pressure transducer: Quartz Crystal

Pressure accuracy: +/- 0.025% psi FS
(i.e. +/- 2.5 psi for a 10K transducer)

Pressure drift: Max. 0.02% of full scale per year
(i.e. 2 psi / year for a 10K transducer)

Temperature range: -20 to 125 deg C

Temperature accuracy: +/- 1 deg C

Pressure resolution: 0.1 psi transmitted
0.01 psi stored on tool

Optionally, high resolution (0.01 psi)
pressure can be transmitted to surface

Temperature resolution: 1.0 deg C transmitted
0.1 deg C stored on tool

SPE 124100
Mungo Platform: A New Wireless Retrofit Solution to Restore Real Time BHP / BHT Data After a Permanently Installed Monitoring System has Failed - A North Sea Case History
This world first proof of concept trial has proved the ability to use wireless gauge technology to restore real time pressure / temperature data in an offshore platform well after a permanently installed gauge system has failed.

The relatively short 66m signal transmission range required in this application meant that the wireless gauge could be optimally configured to provide maximum data points and also to conserve battery power, thus extending the system longevity.

The 3 months of real time wireless gauge data collected from Mungo Well W160 proved extremely valuable:

Reservoir optimisation was possible on a daily basis, including optimisation of the reservoir panel water injection response

The pressure response was used in determining the target location of a new well

Conventional memory gauges would not have been able to do this due to there being no opportunity to recover them before the rig arrived at the platform

With a jack up rig located over the NUI, there are no immediate plans to recover the gauge from W160, however once the rig moves offsite, the gauge will be recovered for inspection
Conclusion
Data from the seabed receiver is uploaded using the seawater dunking transceiver system

The transceiver is connected to a command system via the dunking and deck cables

Offshore the transceiver can be deployed through the moonpool or over the side or the rig

A support or supply vessel is normally used for routine data uploads

The transceiver is deployed on a winch or crane line approx 10m below the surface

P, T, date and time are decoded by the PCS and presented in Excel
Monitoring Challenges in Unconventional Gas
Pressure range: 0 - 10,000 psi (0 - 15,000 psi optional)

Pressure transducer: Quartz Crystal

Pressure accuracy: +/- 0.025% psi FS
(i.e. +/- 2.5 psi for a 10K transducer)

Pressure drift: Max. 0.02% of full scale per year
(i.e. 2 psi / year for a 10K transducer)

Temperature range: -20 to 125 deg C

Temperature accuracy: +/- 1 deg C

Pressure resolution: 0.1 psi transmitted
0.01 psi stored on tool

Optionally, high resolution (0.01 psi)
pressure can be transmitted to surface

Temperature resolution: 1.0 deg C transmitted
0.1 deg C stored on tool

NORSOK D-010 defines Well Integrity as:-

“The application of technical, operational and organizational solutions to reduce the risk of uncontrolled release of formation fluids throughout the entire life cycle of the well”

Norwegian Petroleum Safety Authority (PSA) 2006 study concluded that out of 406 wells managed by 7 different operators on the NCS:-

• 18% of the wells exhibited Well Integrity Weaknesses or uncertainties

• 7% of the wells were shut-in completely as a result of integrity issues
Trapped annulus pressure is a recognised well integrity issue

Thermal pressure changes occur in fluid filled enclosed annuli during warm-up and cool down periods

This is particularly challenging for subsea wells as most are unable to access the B and C annulus for monitoring and bleed off in the event of exceeding the maximum operating pressure.

Failing to monitor and control these thermally induced annulus pressure variations can result in serious consequences!

Annulus pressures need to be monitored and managed to avoid ruptured casing strings and loss of well control
Annulus pressure monitoring
CaTS gauges can be installed in the A, B, C, or any annulus without requiring any penetration through the wellhead

Annulus pressure and temperature data can be transmitted to a surface or seabed receiver in real time

Options available to upload annulus data via E-line deployed Active Pick-Up (APU) tool

Accurate and timely monitoring of thermally induced annulus pressure variations enables effective management  of the annulus pressure in all well types and environments including deep water subsea

CaTS Application
Having excellent zonal isolation behind casing is critical when planning to produce from multiple zones or to deploy intelligent well completion hardware

Achieving effective cement placement and bonding between the formation and casing can be challenging, especially in carbonate formations, where channelling and lost circulation are common problems

New generation, none-cemented, annular barrier technology is being used to achieve more reliable zonal isolation. By installing a CaTS gauge in the casing to open-hole annulus it is now possible to verify the sealing integrity of the annular barriers

Annular barrier verification
No audio
Thru-tubing gauge

Modular design

Lithium battery powered

28ft to 50ft long
(depends on battery pack quantity)

1-11/16" or 2-1/8" OD
(depends on battery pack type)

Corrosion resistant alloy

Full metel-to-to metal primary sealing

Additional battery sections can be added

on board memory capacity (100,000 data sets)

CaTS Relay Station means no limit to achievable transmission range
Wireless Well Solutions facility - UK
Production – electronic assembly temperature test
Production – quartz sensor verification
Operations – single gauge FAT
Operations – complete job SIT


In-country pre-mob
Field Team – programme and test gauges
Field Team – test Acoustic Data Logger and Transceiver
Field Team – prepare kit for shipping offshore
Questions?
1. What reservoir uncertainties exist during appraisal & development?
2. How can we reduce these uncertainties?
3. What is the added value for applying new technology?
New Concept - Advanced Reservoir Testing
Well testing beyond abandonment
..........Well testing beyond abandonment
ART Summary
Deployment:
Wireline
Coiled tubing
Completion conveyed


Installation:
Nipple profile
Bridge plug
Clamped externally to well tubulars

Function:
Pressure / temperature data is encoded and transmitted up the completion via an Electromagnetic (EM) signal

Signal is collected at surface using a topside receiver, decoded and stored locally, or transmitted onwards
Retrofit monitoring - Gas Storage Optimisation
Retrofit monitoring - Gas Storage Optimisation
Retrofit monitoring - Gas Storage Optimisation
BP Clair - UK North Sea
BP Clair - UK North Sea
BP Clair - UK North Sea
BP Clair - UK North Sea
Petrobras - Brazil - Santos Basin
Petrobras - Brazil - Santos Basin
Petrobras - Brazil - Santos Basin
Petrobras - Brazil - Santos Basin

Gas Storage Optimisation involves the retro-fitting of thru-tubing CaTS Gauges into existing or newly converted gas storage wells.


This allows real-time downhole pressure and temperature data to be transmitted to surface during the reservoir charging phase. The reservoir charging phase is carried out in the summer months when the demand for gas is low.


One critical aspect of the reservoir charging process is to ensure the quantity of gas can be maximised without exceeding the virgin reservoir pressures.


In newly converted gas storage reservoirs it is also critical to monitor adjacent reservoirs to ensure there is no undesired pressure break-through or interference affects from the charging process.


Real-time data allows the gas storage charging process to be optimised and provides effective field surveillance.
Gas storage facilities typically operate an annual cycle. The gas is injected during the summer off-peak months and produced during the peak demand of the winter months.

Geographically, gas storage reservoirs should be located in close proximity to gas markets and transportation infrastructure, hence converting depleting reservoirs tends to be most economically attractive.

Geologically, depleted reservoir formations that have high permeability and porosity are preferred.
Retrofit monitoring - Dual string completions
Retrofit monitoring - Dual string completions
Retrofit monitoring - Dual string completions
Dual completion downhole wireless monitoring

Onshore location – Port Harcourt, Nigeria

Retrofit installation using slickline

Gauges installed in existing nipple profiles below lock mandrels

Equipment installed – 22nd December 2012

SRO Data rate – 1 T&P data point every 2 days

Memory log rate – Every 12 mins

System duration – 2.5 years

Gauge depths – short string @ 8717ft – long string @ 9022ft (54 deg dev)

Bottom hole temperature – 69 deg C

Receiver interfaced to third party wireless RTU

Monitor both zones with retrofit CaTS Gauges

2 options to set gauge in the short string (above or below packer)

Considerations for flow-bypass included in completion design

Dual string clamp ensures electrical connection between the short and long strings

Dual string tubing clamp installed at the bottom of the short string

Standard 3 battery pack gauges (~28ft)

In many countries there are now legal obligations to submit annual reservoir and production data to a National Data Repository (NDR).

A NDR seeks to promote and preserve a country's natural resource data and reduce the business risks associated with exploration, production and transportation of hydrocarbons.

In existing wells Permanent Downhole Gauge systems may not have been installed at time of completion. In such circumstances the downhole data acquisition relies on the regular deployment of memory gauges. In remote locations this provides a significant cost and operational burden and re-running completion with a cabled PDG is not a practical solution.

Moreover, in new wells running dual string completions there can be many challenges with running and installing cabled permanent downhole gauge systems, in particular the limited space available inside the production casing to accommodate the gauge mandrels and two downhole cables.

By retrofitting CaTS Gauges in wells located in remote locations it is possible to receive data in real-time for long term durations.

In addition, by installing the CaTS gauges through-tubing in new dual string completions it is possible to monitor closer to the sandface and reduce the installation risks and time associated with a cabled PDG system.


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Offshore Retrofit
Onshore Retrofit

In fields where there is the presence of Intermediate-Deep high pressure gas reservoirs it is possible to charge shallower oil reservoirs through fractures and faults.

This has the potential to cause internal blowouts if not effectively managed.

In order to manage these pressure build-ups a set of strategically placed Internal Blowout System (IBO) wells can be used to provide continuous pressure relief.

By installing CaTS Gauges through tubing it is now possible to measure pressures closer to the zone of interest and send this data in real-time to surface.

This provides a much more effective monitoring system compared to deploying memory gauges by allowing early detection of the escalating pressures.


Downhole wireless monitoring of IBO Wells
Reservoirs that consist of hydrocarbon mixtures, which on pressure depletion cross the gas dewpoint line are regarded as Gas/condensate reservoirs.

This can occur during production where the bottomhole pressure is reduced to the dew point pressure of the gas and results with liquid hydrocarbons present at the reservoir.

The condensate banking has the potential to damage formations, impair the permeability and thus significantly reduce gas production.

By installing CaTS Gauges through tubing it is now possible to measure pressures closer to the reservoir and provide early detection of condensate banking.

This allows the operator to optimise gas production by managing the drawdown more effectively and thereby avoiding condensate banking in the reservoir.


Downhole wireless monitoring of
Gas/Condensate reservoirs
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