Production Logging

Production Logging Training Material

Location & date Instructor - xxx

Objectives of course? 1. What is your background? 2. What do you want to learn this week?

Schedule Morning

Afternoon

Monday

PL Theory

Warrior practical

Tuesday

Tools part 1

Spinner Practical

Wednesday Tools part 2 Memory Thursday operations

Tools practical

Friday

Wrap up

MAPS tools

Memory practical etc

What is Production logging? 1. Measuring Flow in wells

2. Fluid Identification 3. + auxiliary measurements e.g • Pressure • Temperature • Diameter

Why perform cased hole logging? Production logging data is used to maximise production and recovery

Oil Production

Reduced Decline

Production Logging Data is vital to achieve this

Additional Recovery Natural Decline Time

Maximising Field Recovery

How much oil, water & gas from a zone? A

B

Zone A

Zone B

C Zone C Zone D

Sample Analysis of Objectives for PLT jobs Production Profiles 24%

Injection Profiles 10%

Mechanical Problems 7%

Water Problems 45%

Excess gas Problems 14%

Some objectives of production logging:

• We want to manage the reservoir and maximise recovery • Not as much oil / gas is being produced as expected. • There is too much water being produced. • There is too much gas being produced (no pipelines). • The well has leaks or may be becoming mechanically unsound. 7 7/5/2019

Why is water a problem? What makes a well flow? A well will flow if the bottom hole pressure in the wellbore is less than the pressure in the formation. e.g. IPR (Inflow Performance Relationship) plot of bottom hole pressure against flowrate. Pressure at zero flow is the formation, or reservoir, pressure. The greater the pressure difference between the wellbore and reservoir (i.e. the ‘drawdown’) the more the well can flow. The lower the pressure the greater the flowrate.

What makes a well flow? Wellbore pressure must be less than formation pressure Hydrostatic Pressure of formation water = 0.435psi/ft, Oil = 0.300psi/ft, of Gas 0.043 = psi/ft Surface

WHP with Oil = 1,350 psi WHP with Gas = 3920 psi

WHP with Oil = 0 psi WHP with Gas = 2570 psi This well will not flow oil without Artificial Lift

Wellbore

Hydrostatic Pressure of Oil column = 3000 psi Hydrostatic Pressure of Gas column = 430 psi Depleted Reservoir

Virgin Reservoir 10,000ft depth

Reservoir Pressure 4,350 psi

Reservoir Pressure 3000 psi

WHY makes IS WATER SUCH A PROBLEM? What a well flow? BHP = Preservoir + Phydrostatic column + Pfrictional pressure drop due to flow If the well starts to produce water, hydrostatic pressure increases so the bottom hole pressure increases. ==> flowrate decreases, so less oil at surface, and the well will die. Inflow Performance Relationship

This is called ‘Loading up’ in gas wells; the gas is too ‘thin’ to lift water out of the well. Disposal of the water, which can limit flow by overloading the surface facilities, is a problem. Water has to be stored & treated before it can be disposed of.

Water Injection Injection Well

Water is injected

Production Well

Water & Oil are produced

Log an INJECTION Log a PRODUCTION profile in this well profile in this well

OIL IS FLUSHED or SWEPT FROM THE RESERVOIR TO THE PRODUCTION WELL

Water injection is the most common secondary recovery method, It is also used to maintain reservoir pressure to prevent premature gas breakout within the reservoir. Both the injection well and the production well need to be logged.

Water breakthrough During water injection, water pumped into a well travels through high permeability rock to the producing well faster than through low permeability rock. This will cause premature breakthrough of injection water reducing the flushing efficiency or sweep of the reservoir.

Unwanted water scenarios PL would be used to identify the watered out zone before plugging it off.

Casing leak Channeling Leaking Plug

Water “Coning”

Water production due to ‘coning’

Formations have horizontal and vertical permeability. Horizontal permeability is about 3-10 times higher than vertical in sand zones. With high drawdown water, with lower viscosity, gradually moves up. After break through, water is preferentially produced and the higher viscosity oil will remain in the formation.

Gas “coning”

Gas production due to ‘coning’

In oil wells with gas caps the reverse can happen. The ‘cone’ is upside down and gas is drawn down through the formation. Once gas enters the wellbore it is produced preferentially to oil and the oil is left in the formation.

or possibly both!

Types of Production Logging Tools: 1. 2. 3. 4. 5.

Flowmeters (Spinners) Fluid Identification tools Pressure & Temperature Depth control Auxiliary tools

1. Spinner Flowmeters Measure volumetric flowrate Have no idea about gas, oil or water 6 Arm Caged Full Bore

3 Arm Caged Full Bore

Continuous Flow Spinner

In-Line Spinner Array spinner SAT

Types of Flowmeters (Spinners)

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2. Fluid Identification Tools Density Tools (FDR, FDD, FDI) Can only give % split between any 2 fluids, i.e.: Oil & water Gas & water Oil & gas

But often 3 fluids present in the well, need more data!!.

Holdup Tools (CWH, GHT) Combine either water HU or gas HU data with density and we can find % water % oil % gas at any point in the well.

3. Pressure & Temperature Quartz Pressure Gauges (QPS, QPC) Temperature tool (PRT)

4. Depth Control Gamma ray (PGR)

Casing Collar Locator (CCL)

Naturally occurring radiation in formations

Reacts to change in metal volume – where 2 joints of pipe screw together.

Radioactive scale Can indicate where water is entering the well.

5. Auxiliary tools Production Dual caliper (PDC) 2 independent orthogonal caliper measurements

Production inclinometer Accerometer (PIA) single axis accelerometer to measure deviation

Centralisers (PRC) • Roller 3-arm - standard; easy entry option; various spring forces e.g. 25 or 40lbs • Roller 4-arm - for critical centralisation; 110lbs force, option 60lbs • Bowspring (PSC)- required for barefoot completions; 50lbs force

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Deployment tools Knuckle joints • remove excess weight from centralisers • flexibility of string (buckled, twisted pipe) • 10 deg displacement • Use in pairs - i.e. space out with short tool e.g. PGR in larger pipe

Swivel joints • Tractor jobs • eliminate tool rotation due to wireline torque

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Head Tension Unit (HTU) Head Tension Unit • to avoid breaking the wireline weakpoint • monitoring of tool sticking • Coiled Tubing operations in horizontal, highly deviated wells

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Tool operating characteristics Standard tool ratings: 15,000psi (103MPa) & 350F (177C) 0

0 Pressure

Depth, ft

1.2 g/cc Gradient

Venezuela, Indonesia US Gulf Coast etc High Temp

Depth, ft

Normal Geothermal Gradient, ≈ 1.5F/100ft 20,000 0 Pressure, psi 10,000 1.0 g/cc gradient => 8,700psi @ 20,000ft 1.2 g/cc gradient => 10,400psi @ 20,000ft

20,000

0 Temperature, F 350 Normal gradient => 360F @ 20,000 ft High gradient => 833F @ 20,000 ft

Standard Length Production Logging Toolstring TELEMETRY / MEMORY + BATTERY QUARTZ PRESSURE TEMPERATURE

CCL GAMMA RAY

Wellbore/Reservoir pressure, density by press gradient

Fluid movement and fluid identification Depth correlation and perforation Depth correlation and radioactive scale deposition

KNUCKLE JOINT KNUCKLE JOINT CENTRALISER

DENSITY

Fluid identification by density

IN LINE SPINNER

Backup flowmeter / SSD inflow

CAPACITANCE

Fluid identification by dielectric constant

CENTRALISER

FLOWMETER MECHANICAL SECTION

Total flow of all the phases (ideally)

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Short Combination Tools Minimize length with combined tools QPC (=QPS +CCL) & CTF (= Capactitance/Temperature/Flow) 1.3/8" (35mm) & 1.11/16" (43mm) OD options.

Centralizer QPC Quartz Pressure Casing Collar Locator

Data quality improved by reduced sensor spacing. Interchangeable flowmeter mechanical sections to suit completion. Easy portability and reduced rig up height.

Gamma Ray

Centralizer

Surface readout or memory mode.

Length of XTU/PRC/QPC/PGR/PRC/CTF/CFBM Toolstring = 3.53m Length of “Standard” toolstring = 4.72m

CTF Capacitance Temperature Flowmeter

Well Completion design determines PL tool sizes – hence 1 3/8” option Single String Tubing In 9 5/8”csg 4.5-5.5” In 7”csg 3.5”

Dual String Long String

SSD’s may be opened and closed by tools run on wireline Sliding Side Door (Sleeve Valve)

Short String Tubing In 9 5/8” Casing 2.875” In 7” Casing 2.375” (i.d. ≈ 1.8”) 1 11/16” = 1.6875” & 1 3/8” = 1.375”

Zone A Nipple for Plug

Zone B Log in tubing with continuous spinners. Log in casing with fullbore spinners.

Dual strings allow production from zones at very different pressures Zone C Zone D

Dual Completions offer more flexibility such as injecting down one string and producing the other but tubing size is limited.

Short Combination Tool String Short Combination Tool, SCT 1 11/16in (43mm) or 1 3/8in (35mm) 350oF (177oC) & 15,000psi (103MPa)

Pressure Casing Collar Locator Platinum Resistance Thermometer (Gamma Ray) (Density) Capacitance Water Hold Up Flowmeter Additional tools may be added as required

Typical toolstring about 3-4m long – very short!

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How long is SCT toolstring? XTU002 PGR020 PRC001 QPC003

Length of SCT toolstring 48.3 58.7 58.3 48.3

PRC001 CTF004

58.3 47

CFBM

34.9

XTU002 PGR020 PRC001 QPS019 CCL015 PRC001 CWH013 PRT016 CFBE05 CFBM

Total

353.8

Total

1.18 m length saved (All measurements in cm) CFSM typically 20cm +/PRC034 = 84.45cm

Length of standard toolstring 48.3 58.7 58.3 48.3 47 58.3 66.6 31.7 20 34.9

472.1

How many tools? Different tool strings are required to achieve different objectives. A water injection well does not require fluid identification tools. It is better to have too much information than to have too little! You can ignore the data you do not need. Too little data is a big problem!

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PL analysis is like a detective story. Each tool gives a different clue towards the correct solution to the mystery.

CCL tells us the perfs are in the right location

Gamma Ray indicates that only the cleanest sands (below 30 API) are productive.

Temperature indicates cooling with gas production Flowmeter shows that this section of perforations is not productive. Density and Capacitance tell us which fluids are being 34 produced 7/5/2019

PLT Interpretation Example The total water cut is 76% of which: Zone 1

Zone 1: 89% Water Cut Zone 2

Zone 2: 72% Water Cut

Zone 3

Zone 3: 68% Water Cut

Zone 4

Zone 4: 77% Water Cut

Log run prior to a planned workover to set a bridge plug above lowest zone. If the client had set the bridge plug: A lot of money would have been spent and 515 BOPD of production from Zone 4 would have been left in the ground. There would be little gain: The well would remain at 76% water cut (total of zones 1 to 3)

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Question? Which zone is producing? A B

C D E

Oil Well with five sets of perforations

A, B, C, D or E? Can you tell quickly from the spinner curves? 36 7/5/2019

This log has flowmeter, density, capacitance and gas holdup data.

Which zone is producing gas? A

A, B or C?

B

C

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Volume factors Bx = vol at Reservoir conditions vol at Standard conditions Boil = 1.2 – 2 Bwater = 1 Liquids smaller volume at surface conditions

Oil

Gas

Water

Volume factors Bx = vol at Reservoir conditions vol at Standard conditions Bg ≥0.005 1/ Bg ≤ 200 Gas much larger volume at surface conditions

Oil

Gas

Water

Horizontal wells

Some Reasons for horizontal wells: Maximise Reservoir Drainage from a Single Well Reduce the Drawdown on the Well Produce From Thin Oil Zones close to Water or Gas Low Permeability Reservoirs Maximise the Interception of Orientated Natural Fractures

Horizontal wells often do not perform as well as planned. They cannot be logged by conventional methods. Coiled Tubing or Well Tractors are required.

Horizontal Wells

HorizontalSection is never perfect

Flow downwards

Flow upwards 41 GE Title or job number 7/5/2019

There is no such thing as a horizontal Horizontal well: We need across wellbore measurements. Example: Gas downward ‘Coning’ in a Horizontal Well.

Once Gas enters the wellbore, because it has lower viscosity it is preferentially produced. This can reduce or even block the flow of oil from further down the well. In one documented case producing the gas cap allowed the oil zone / oil water contact to move upwards until the well started to produce water. 42 7/5/2019

Water producing horizontal well logged with centre-sampling standard PL tools

The tools only tell you what is in the middle of the wellbore. It is hard to say with confidence what is coming from where.

Deviated or Horizontal well flow regimes Low velocity, low to medium heavy phase content Medium velocity, low heavy phase content High velocity, medium heavy phase content. Light phase in the middle (very rare) Low velocity, high heavy phase content

Low velocity, medium heavy phase content

Medium velocity, high heavy phase content

High velocity, low to medium heavy phase content

Horizontal Phase Profiles Oil Bubbles

Wavy stratified flow

Water

Bubbles Distributed Bubble flow Water

Flow Regime and MAPS Tool Use Segregated and Intermittent Flow Suitable

for CAT, RAT and SA

Dispersed Bubble Flow

Suitable for RAT and SAT

Flowloop Comparison – Gas & Water MAPview

Slugs of water lifted up with gas

Some water falls back

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MAPS - Multiple Array Production Suite The CAT, the SAT and the RAT

Spinner Array Tool, SAT

Resistivity Array Tool, RAT

Capacitance Array Tool, CAT 48 7/5/2019

Flowloop video

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Multiple sensors mean that we can image the data. “A picture tells a thousand words.”

Gas has entered the well

Wavy flow oil at the top

No water is passing Bubbles of oil passing over the peak through the trough

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The tools work!

Flowloop Proof of Concept – Oil & Water MAPview image of the data

Red: Oil Blue: Water A little fallback of water on the low side 51 7/5/2019

3D flow imaging of the complete well.

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Individual Tools in detail: 1. 2. 3. 4. 5.

Flowmeters (Spinners) Fluid Identification tools Pressure & Temperature Depth control Auxiliary tools

Types of Flowmeters (Spinners)

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Continuous Spinners - Bearing & Jewelled CFS & CFJ

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Caged Fullbore Flowmeter - CFBM

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Inline Spinner - ILS

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Diverter Basket Flowmeter - DBT

Ideal for low flow rates Captures hydrocarbons flowing on high side of well 58 7/5/2019

Diverter Basket Flowmeter

Diverter Tube

Flowmeter Measurement

Density Measurement

A diverter tube may be added to feed flow through a radioactive density tool, FDR for across well bore density 59 GE Title or job number 7/5/2019

SAT – Spinner Array Tool

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Electronic section

Magnet present = 0V 0V

No magnet present = 5V

1 5V

4

5V

3 5V

Magnets 5V

Hall Effect Switches

2

5 Rotation of Spinner 61 7/5/2019

FLOWMETERS Operating Principle, Sensor Magnet present = 0V

The Sensor design is the same for all of the Sondex spinner family. The flow sensor comprises of 5 hall effect sensors, arranged in a circle on a titanium carrier, which acts as a pressure barrier. Two magnets on the other side of this barrier, rotate with the spinner shaft, resulting in 10 pulses per revolution. (gain of 0.1)

0V

No magnet present = 5V

1 5V

4

5V

3 5V

Magnets 5V

Hall Effect Switches

2

5 Rotation of Spinner

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Short Compact Toolstring – SCT CTF section Capacitance/Temp/Flowmeter

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So what do we do with our impeller?

It measures revolutions per second or “rps” If we know the diameter of the pipe we can work out the volume of flow 64 7/5/2019

We could take a series of readings at various depths in the well: RPS 0

20

40

60

0

C = 50 rps

10 20 30 40

B = 25 rps

50 60

Oil flowing upwards

70 80

A = 10 rps

90 100

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And then draw a line in between the points 0 0

C = 50 rps

20

RPS

40

60

10 20 30 40

B = 25 rps

50 60

Oil flowing upwards

70 80

A = 10 rps

90 100

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But it would be much better to actually take lots of measurements in between in case it changes. 10 readings RPS

Original RPS 0 0 10 20 30 40 50 60 70 80 90 100

20

40

60

0

20

40

60

0 10

20 30 40 50 60 70 80 90 100

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This is all very time consuming, so it would be much better to take readings continuously whilst moving down the well.

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The problem is that if we move the tool down in a fluid or gas the blades will turn as we move.

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To overcome this we make a log downwards at constant speed in part of the well where there is no flow. This should show us how many turns (rps) we get due to the downward movement.

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The convention is that Production = +ve rps Injection = -ve rps

Clockwise viewed from underneath

Anticlockwis e viewed from underneath 73 7/5/2019

Now we know the rps value at each point – lets work out the flowrate = Q (bpd) Q = 1.4 x (i.d. velocity bpd

i.d.(inches )

inches

)2 x fluid (Feet per minute)

but that’s velocity in feet/minute, not rps! 74 7/5/2019

So we need to relate the rps value to movement in feet per minute If we log down or up in a stationary fluid at a constant speed the spinner impeller will turn at a constant rate

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If we go up & down at different speeds we can build up a graph like this: + rps 90 down

60 down 30 down

- cable speed up

+ cable speed down 30 up

60 up

90 up

- rps

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all the points should lie on 2 lines why 2 lines? + rps

- cable speed up

+ cable speed down

- rps

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What do points A & B represent? + rps

B - cable speed up

+ cable speed down

A

- rps

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A real life example

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A real life example

Why not symmetrical about the origin? 80 7/5/2019

This side represents Production

+ rps

- cable speed up

+ cable speed down

This side represents Injection - rps

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This side represents Production

+ rps

- cable speed up

+ cable speed down

This side represents Injection - rps

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There are actually a few more complications: •

Tool body influence

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Fluid type

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Pipe size

5” liner 3.1/2” tubing

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Friction effects

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Johann Nikuradse Georgian (Imperial Russia) 1894 – 1979 Hydrodynamics Professor at University of Breslau He saved many Georgians during WW2. 90 7/5/2019

Friction effects

Nikuradse correction factor = 0.83 (or 0.94)

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Friction effects

For turbulent flow this factor can range from 0.75 to 0.9, depending on the impeller size; nominal value is 0.83. Full-bore spinners in casing tend to have a correction factor of about 0.85-0.90. 92 7/5/2019

FLOWMETERS Flow Regime vs Pipe water, 0.92g/cc, 0.15cp 70 60

Turbulent Flow

BPWD

50 40 30

9.5/8in pipe

7in pipe

20

3.1/2in pipe

10

Laminar Flow

0 0

2

4

6

8

10

Pipe ID (in)

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THRESHOLD VELOCITIES Vth in fpm guideline only

Water

Light oil

Heavy oil

Gas (2000psi)

Caged Fullbore

1.8 - 2.5

2.3 - 3.0

4.3 - 7.0

7.0 - 12.5

Continuous jewelled

3.5 - 5.5

4.0 - 6.0

6.0 - 10.0

8.5 - 15.5

Continuous bearings

5.0 - 8.0

5.5 - 8.5

7.5 - 12.5

10.0 - 18.0

In-Line

5.0 - 8.0

5.5 - 10.0

7.5 - 14.5

12.0 - 20.0

FLOWMETERS Choice Of Spinner

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SPINNER CALIBRATION

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SPINNER CALIBRATION

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CAGED FULL BORE

For specific pipe size, 4.1/2 – 9.5/8” Collapses to pass restrictions 3-arm roller type

• impeller damage at GLMs • less friction due to rollers • better threshold as less shielding 6-arm bowspring type

• protects spinner • better centralising in deviated wells • shielding from flow  increases threshold 98 7/5/2019

Flowmeters Cage fullbore flowmeter is closed in tubing

Opens in casing

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CAGED FULL BORE DOWN FLOW IMPELLERS injection rates > 4 ft/sec

When to use down flow spinner assemblies CSG WT (lb) BWPD M3/D 4.5 11.6 > 5400 > 855 5 18 > 6150 > 975 7 29 > 12850 > 2040 7 5/8 29.7 > 15900 > 2525 8 5/8 36 > 20550 > 3270 9 5/8 53.5 > 24450 > 3890 9.5/8” CFB is fitted with a down flow assy as standard

Injection rates so spinner will not close logging up at 90fpm.

CAGED FULL BORE 7” & 9.5/8”CFBM

SOLID SHAFT flexible joint oscillation > 25 rps

for 5.5”, 5” & 4.5”CFBM

Standard Downflow

Solid Solid Downflow

CAGED FULL BORE COMPRESSION SPRINGS •

more resistance to down flow, tighten the springs

WORKING RANGE •

7” CFB working ID range 5.90 – 6.20”

(7” 38# has ID of 5.92”)

CONTINUOUS FLOWMETER SPINNERS CFS – bearing mounted • •

for tubing or screened wells helical spinner, better in viscous oil

CFJ – jewel mounted • • •

for high velocity wells jewel better in presence of sand lower pitch, can go to higher revs

CFS & CFJ • •

use spinner larger than tool body protection from lateral jets

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IN-LINE SPINNERS Back up for end-of-string Symmetrical for flow By-pass tube 2.1/8” spinner option

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RUN A BACK-UP SPINNER

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MAXIMUM FLUID VELOCITY What are the upper limits of flowrate for PL jobs, particularly in gas wells? Calculate downhole rate (ft/min) using the Tool Lift Estimation spreadsheet.

Remember that with gas, the downhole volume is related to downhole pressure & temperature. The practical upper limit of rotational speed are:

• between 25 / 60 RPS for the CFB tools • 125 RPS for the continuous spinners

Oil / water wells will normally be within these criteria. Gas wells, the maximum flowrate can be achieved with a CFJ type. 106 7/5/2019

SPINNER STATISTICS - CFBM Casing Size

Blade diameter (inch)

Pitch (inch)

Pitch RPS/Ft/Min

4.5” 5” 5.5” 7” 9 5/8”

2.6” 3.15” 3.3” 4.24” 6.08”

4” 4” 4” 4” 4”

0.05 0.05 0.05 0.05 0.05

Pitch Minimum RPS/M/Min Working ID

0.164 0.164 0.164 0.164 0.164

Minimum working ID is the same for CFBM tools whether 3 or 6 arm & with different size body OD.

3.82” 4.27” 4.67” 5.92” 8.53”

SPINNER STATISTICS - CFS Body diameter (inch) 1 3/8”

Cage diameter (inch) 1 3/8”

Blade diameter (inch) 1.15”

Pitch (inch) 4”

0.05

0.164

1 3/8”

1 11/16”

1.4”

4”

0.05

0.164

1 11/16”

1 11/16”

1.4”

4”

0.05

0.164

1 11/16”

2 1/8”

1.77”

4”

0.05

0.164

Ported shroud option

Pitch Pitch RPS/Ft/Min RPS/M/Min

SPINNER STATISTICS - CFJ Body diameter (inch) 1 3/8”

Cage diameter (inch) 1 3/8”

Blade diameter (inch) 1.15”

Pitch (inch)

Pitch RPS/Ft/Min

Pitch RPS/M/Min

5.6”

0.036

0.118

1 3/8”

1 11/16”

1.4”

5.6”

0.036

0.118

1 11/16”

1 11/16”

1.4”

5.6”

0.036

0.118

1 11/16”

2 1/8”

1.77”

7”

0.029

0.095

CFJ (CTF)

All

All

3”

0.068

0.223

Large clearance option Reduces risk of jamming due to debris

SPINNER STATISTICS - ILS

Body diameter (inch) 1 11/16”

Cage diameter (inch) 1 11/16”

Blade diameter (inch) 1.4”

Pitch (inch)

Pitch RPS/Ft/Min

Pitch RPS/M/Min

5.6”

0.036

0.118

1 11/16”

2 1/8”

1.77”

7”

0.029

0.095

Individual Tools in detail: 1. 2. 3. 4. 5.

Flowmeters (Spinners) Fluid Identification tools Pressure & Temperature Depth control Auxiliary tools

Fluid Identification Not required in an injector well Always run 1 in a producing well

2 independent identifiers in 3 phase well Density, capacitance, and/or gas hold-up

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CAPACITANCE WATER HOLDUP Differentiates water from hydrocarbons • dielectric constant Tool response

• chart provided by manufacturer • non-linear Effects of pressure & temperature Yha = (Flog – Foil) / (Fwater – Foil)

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CTF tool – Capacitance /Temperature/Flow

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CWH contd

CWH

CAPACITANCE WATER HOLDUP Operating Principle The dielectric constant of water is about 80, oil is  6-8 and air lower at around 1.

A measure of the dielectric constants can be made by introducing the fluids to be measured between the plates of an electrical capacitor whose value is then measured. The Capacitance Water Holdup tool is designed as an annular capacitor, with an insulated rod as the centre electrode and a cylindrical tube around it as the outer electrode. The frequency of a free running oscillator which incorporates this capacitance is measured. The frequency of the oscillator varies inversely with the effective capacitance of the fluid between the plates. Changes in water salinity have a negligible effect on this measurement.

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CAPACITANCE WATER HOLDUP Operating Principle The frequency of the oscillator with the tool immersed in water is generally made to be 25-28kHz and in air about 30-32kHz. The frequency of the tool varies almost linearly with the change in water fraction if hydrocarbon is the continuous phase and water is evenly distributed throughout the volume of the measured fluid. This is usually true up to about 35 to 40% water but depends slightly on the type of oil and other flow conditions met downhole. When water becomes the continuous phase the capacitor becomes progressively ‘short circuited’ by the water and the tool response is no longer linear.

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CAPACITANCE WATER HOLDUP Enhanced vs Standard CWH 1.00 0.90 0.80

Y measured

0.70 0.60 0.50 0.40 0.30 0.20 0.10 0.00 0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

Y actual standard CWH

enhanced CWH

N Sea

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ENHANCED CWH RESPONSE

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FLUID DENSITY RADIOACTIVE Am-241, 150mCi, 5.5 GBq, source T ½ 432 years • • •

measures electron density cps logarithmic function of density chlorine introduces non-linearity

No corrections required • • •

deviation statistical variations high energy r/a scale

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FLUID DENSITY RADIOACTIVE Operating Principle Overview Am241 has a high count rate and low energy level good resolution & safe.

Emitted gamma rays cross the void in the tool through which the well fluid passes. On the other side of the void is a sodium iodide detector crystal. The crystal has been specially designed to detect gamma rays from the source and not the formation / radioactive scale. 122 7/5/2019

FLUID DENSITY RADIOACTIVE Operating Theory The Fluid Density Radioactive tool measures Electron Density (ρ elec) and by inference the mass density of the fluid type. Oil, Gas and Water each have different densities, thus this tool may be used as a fluid identification tool for all phases.

Compton Scattering of gamma rays is done by the electrons surrounding each nucleus. In most elements the number of electrons is close to half the number of neutrons and protons. In hydrogen the ratio is 1:1 which is important in well fluids because hydrogen is the principal component of water and hydrocarbon.

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FLUID DENSITY RADIOACTIVE Operating Theory Below is a table of comparisons of electron density (measured by the tool) and actual mass density. Note that the density of gases depends also on the pressure. Approximations of ratios of measured density to actual density are tabulated below for several fluids.

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FDR The Americium source that Sondex uses has a high count rate (to give a high resolution) and low energy level(to make it safer to use). However the low energy of the gamma rays means that there is a photoelectric effect where the response is influenced by chemical make-up of the fluids as well as the density. Chlorine atoms have a marked effect.

125 GE Title or job number 7/5/2019

FDR Therefore, a simple. single semi-logarithm line 2point calibration will give acceptable results when there are only two phases and also in 3-phase flow when the downhole water is fresh. Because of changes in oil properties downhole, the surface calibration fluids should be air and water. Where there are all three phases present in a well (e.g.: oil, water and gas) and the water is strongly saline, it is best to use a multi-point calibration file to minimise errors. 126 GE Title or job number 7/5/2019

FLUID DENSITY RADIOACTIVE

Sondex Radioactive Fluid Density tool response.

Log(base 10) Normalised Countrate (Normalised = Countrate / water countrate)

1

0.8

General Multipoint Calibration line end-points

0.6

Density 0 0.846 1.0 1.2

0.4

Frequency 6.815 * w ater frequency 1.432 * w ater freq w ater freq 0.447 * w ater freq

Air-Diesel-Water Line Water-Salt Water Line Air pts

0.2 Petrol pts Kerosene pts 0

Diesel pts Fresh Water pts

-0.2

NaCl Salt Water pts Crude Oils

-0.4

Other log data

-0.6 0

0.2

0.4

0.6

0.8

1

1.2

1.4

Fluid Density (g/cc)

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FLUID DENSITY RADIOACTIVE Operating Principle A gamma ray passing through the sodium iodide crystal may excite an atom sufficiently to cause a number of photons of light to be emitted. These are collected by mirrors inside the crystal and exit through an optical window at the end; this is attached to the photomultiplier (PMT). Photons striking the photocathode of a PMT cause electrons to be emitted. The electrons are accelerated, as there is a potential difference of about 130 volts between dynodes in the PMT chain.

Each collision causes many more electrons to be emitted. These are accelerated onto the third dynode and multiplied again.

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FLUID DENSITY RADIOACTIVE Operating Principle- Electronics The HV PSU generates the -1.6kV Cathode potential and the voltage taps for the PMT Dynodes. The PMT anode output is at ground potential.

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FLUID DENSITY RADIOACTIVE Operating Principle- Electronics The output charge pulse is wired through the HV PSU to the detector electronics where it is amplified and detected by a comparator. Gamma detections are stored in FPGA logic and read out over the Ultrawire toolbus in response to requests from the Telemetry Controller e.g. MPL, XTU or other Crossover. Various commands are supported in the protocol.

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FLUID DENSITY RADIOACTIVE

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FLUID DENSITY RADIOACTIVE

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3.5 2.0 5.5

4.0

R/A levels in μSv/hr

0.5 0.7 133 GE Title or job number 7/5/2019

48cm

70cm

20μSv/hr line

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FLUID DENSITY RADIOACTIVE Exposure rate  (1/distance)

2

Need a reference point

• from the source patterns • 20µSv/hr @ 70cm (in front of source) Example: @ 100cm for 15 minutes in front of source

• • • •

Exp rate  (1/100)2 20 µSv/hr  (1/70)2 Exposure rate = 20 x (70/100)2 Exposure rate = 20 x 0.49 = 9.8µSv/hr

Total exposure = 9.8 x 0.25 = 2.45µSv

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FLUID DENSITY RADIOACTIVE Hold up & Water Cut

Ywater = (log - oil) / (water - oil) where Ywater

water hold up

log

the log reading

water & oil

water and oil densities respectively

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FLUID DENSITY DIFFERENTIAL No hazardous materials

Fragile sensor Correction factors • •

deviation temperature

Vacuum filling Friction effects

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FLUID DENSITY Gauge cal may be distorted if Δp between ports > DIFFERENTIAL 15psi.

Gauge sensor will burst if Δp > 100psi Pressure up/down lubricator slowly to avoid large shock waves. Keep TV in ‘safe’ position except whilst logging or calibrating IMPORTANT RULE TRANSPORT VALVE (TV) must always be in SAFE position before operating the Port valves (PA & PB) TV incorporates 2 relief valves, one each way, to prevent continuous overpressure > 5psi

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Bellows to damp short duration pulses, when Δp >

FLUID DENSITY DIFFERENTIAL Δp = (ρsilicon oil – ρwell fluid) * g * h ρsilicon oil = 0.97g/cc @ STP for 200cs viscosity Temperature probe in FDD is for gauge correction.

Pressure & temperature effect on Silicon Oil (Bo, volume factor) is computed in software.

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FLUID DENSITY Field calibration: DIFFERENTIAL After 10 minutes warm up, record the frequencies for Δp, gaugeT, & accelerometer in the following positions: Horizontal in air

Vertical in air

Vertical in water

(within a few counts of last use; small variations in pressure counts dependent on temp) Create three cal files in memlog: sn.FDDP sn.FDDT

sn.FDDA

Laboratory coefficients required to calculate fluid density from the tool outputs. Coefficients are supplied in the FDD Data Checker file (warrior.FDD) Create a cal file ‘tool serial number’.FDD 140 7/5/2019

FLUID DENSITY TV must be in ‘safe’ position. DIFFERENTIAL DRAIN THE TOOL: Stand tool vertical in bucket. Screw out Port Valves, PA & PB. Remove upper & lower half shells. Remove water trap drain plugs D1 & D2. Remove gauge block drain plugs D3 & D4. If silicon oil is contaminated, gauge block & lines must be removed, stripped & cleaned before re-filling). STRIP, CLEAN & RE-ASSEMBLE THE TOOL: See MN-FDD003, sections 5.2.1 to 5.2.4 Torque wrench is required to assemble gauge, sealing to the gauge holder. Check all O-rings are good, particularly internal Oring 013 (item 20, 15761) 141 GE Title or job number 7/5/2019

FLUID DENSITY EMPTY THE TOOL (if not previously done): DIFFERENTIAL

Remove Big Hydraulic Coupler from Upper port. Set tool above chamber assy. Start vacuum pump. Slowly open valve V1, stop when no more oil in hose from drain D4.

VACUUM THE TOOL: Connect Big Hydraulic Coupler to Upper port. Set tool above chamber assy. Start vacuum pump. Very slowly open valve V1; control V1 so only air is sucked to the pump. Continue vacuuming (1/2hr or more) until no more air bubbles enter chamber #1, Vacuumeter reads 29 to 30” Hg.

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FLUID DENSITY FILL DIFFERENTIAL THE TOOL:

Close V1. Stop the pump. Slowly open Quick disconnect. Slowly open V1; air at atmospheric will push oil from chamber 1 through the tool toward chamber 2; before 1 minute oil will be seen at the upper port, wait until no bubbles appear; close valves V3, V5 & V1.

CLOSING THE TOOL: Lay tool horizontal below the chamber assy. Open V5. Disconnect Big Hydraulic Coupler, add oil to port & screw in fully upper port valve; repeat at lower drain D4. The tool is now ready to transport.

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FDI – Fluid Density Inertial

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FDI – Fluid Density Inertial

FDI – Fluid Density Inertial

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FDI – Fluid Density Inertial

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FDI – Fluid Density Inertial

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FDI – Fluid Density Inertial

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FDI – Fluid Density Inertial

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FDI

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GAS HOLDUP TOOL Co57 source, 3 mCi, 111MBq. T ½ = 271 days The tool principally is a gas holdup tool; it responds to electron density.

• Water and oil have similar electron densities • Gas has a lower electron density.

Across wellbore holdup measurement:

• any flow regime • at any well angle.

Thus using GHT data will result in a more accurate interpretation where there is stratified flow in deviated and especially horizontal wells.

The tool is run centralised and is best run in combination with other fluid identification tools.

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GAS HOLDUP TOOL The low energy gamma rays interact with the surrounding medium in 2 ways:

• scattering (principally Compton scattering) • photoelectric absorption (attenuation) The source / detector spacing is chosen to maximise the detection of scattering rather than attenuation. Increasing electron density in the surrounding medium causes more back scattering but, at the same time, depending upon the chemical makeup, there is a change in photoelectric absorption. The source energy level is chosen so that the tool measures only the fluid in the wellbore and not the formation. Most of the gamma rays are absorbed by the casing and any that do get through and are back scattered by the formation do not have enough residual energy to return to the detector.

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GAS HOLDUP TOOL Gas has a low electron density and thus a low level of back scattering. It also has low attenuation. Fresh Water has a high electron density. Saline Water has a higher electron density so normally we would expect the count rate to increase, but chlorine is an excellent photoelectric absorber of gamma rays so the expected increase in count rate is effectively cancelled out. Consequently, the tool is virtually insensitive to salinity changes.

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GAS HOLDUP TOOL Oil, in general, has a slightly lower electron density than water so the backscatter & therefore countrate is slightly lower. The difference in count rate between oil and water (fresh or saline) is typically in the 5% range when compared to the difference between water and gas. The tool is strictly a ‘Gas Holdup Tool’.

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GAS HOLDUP TOOL

The difference between oil & water becomes more significant compared to gas & liquid as the pipe size decreases.

GAS HOLDUP TOOL

A7A-100, P1: Well f

Solid lines: Down passes, Dashed lines: Up passes, Pass 1, Pass 2, Pass 3, Pass 4

Response to ID If an irregular hole ID is anticipated then an XY caliper should be run in the tool string; this snap shot from a log clearly shows the effect of varying diameter, due to scale, on the raw GHT counts.

1:500 ft

GHT 19800

22600 4.2

CALA in

4.7 4.2

13900

13950

14000

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GAS HOLDUP TOOL

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GAS HOLDUP TOOL Effect of Pressure Gas properties change with increasing pressure and temperature. As the density of gas increases with pressure (and temperature) the level of back scattering changes – the greater the pressure the higher the level of backscattering. The Sondex acquisition/post processing software provides a PVT correction algorithm to adjust reasonably for changes in gas properties from surface to downhole. At high pressures, the difference in frequency between gas and oil and water reduces so that the tool cannot be considered to respond only to gas holdup. The water/oil ratio will also affect the count rate. The interpreter will have to determine the predominant liquid end point when calculating gas holdup.

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GAS HOLDUP TOOL

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GAS HOLDUP TOOL CALIBRATION In air and water, centralised in a 5 ½” calibration jig; average count rates in air and water over 1 minute time and record. Note calibration date because of the rapid decay of the source (9 month half life). The air and water end points are used in the software calibration process and can also be used to check on the correct tool response. The wellsite verifier is a steel sleeve which is used at the wellsite to ensure that that the tool is working correctly and that the countrates have not changed between jobs. It is not used to adjust the software calibration values.

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Individual Tools in detail: 1. 2. 3. 4. 5.

Flowmeters (Spinners) Fluid Identification tools Pressure & Temperature Depth control Auxiliary tools

Quartz Pressure The Sondex Quartz Pressure Sensor uses an industry standard Quartzdyne® precision quartz crystal pressure transducer. The quartz pressure gauge is used to measure very accurately bottom hole pressure, and how it changes with depth and flow rate. This data may be used for: • • • •

measuring depletion analysis of the formation and reservoir properties the well efficiency determining pressure gradient (hence density)

Pressure build ups (PBU) and fall offs (PFOT) can be recorded during a PL job as there will be a pressure gauge in every PL string

Quartz Pressure Operating Principle Pressure enters through the well port in the Lower Housing sub and acts on the inconel gauge bellows, which is filled with silicone oil during manufacture. The bellows isolate the quartz pressure crystal from the aggressive well fluids while transmitting the pressure. Note the bellows, because of their construction, may introduce an error at atmospheric pressure.

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QUARTZ PRESSURE Operating Principle A second "flushing" port, blocked off during logging, allows the well port to be flushed clean during maintenance and keeps silicone oil inside the pressure chamber during logging. The crystal’s resonant frequency depends on pressure and temperature, hence the gauge incorporates a second "temperature" crystal, thermally coupled to the first which is not subjected to well pressure. A 7.2MHz clock, used to down shift the pressure and temperature crystal frequencies is output as a time reference for frequency measurement. Drift of this clock is included in the calibration algorithm, resulting in accurate calculation of Temperature and Pressure.

Gauge output pressure and temperature frequencies lie in the range 1560kHz 166 7/5/2019

Quartz Pressure Operating Principle BHP & BHT act directly on the crystal, changing its resonant frequency: Increasing well pressure increases the output frequency Increasing well temperature decreases the output frequency

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Quartz Pressure Transducer performance Pressure transducers outperform the Quartzdyne stated specification of 0.02% full scale. The stated drift is < 3 psi/year - we have seen that the drift is less than this. Calibration The tool is supplied with coefficients generated by Quartzdyne. A calibration facility to match the gauge’s performance would cost about $150,000 or more. It is obvious if the tool is not giving the correct pressure. If the output frequency is changing this is most likely a coefficient error. If the gauge requires re-calibration it must be sent back to the manufacturer.

There is no specified re-calibration frequency; oil companies set their own standards. 168 7/5/2019

Quartz Pressure How is pressure data used? Monitoring well stability

• Effect on spinner cross-plot • Slugging Input for PVT

• Converting downhole rates to surface rates Derived density

• Across wellbore measurement, deviated holes • Cross check direct density measurements Selective Inflow Performance (SIP)

• Layer performance, Productivity Index Pressure Transient Analysis 169 7/5/2019

SKIN PL DATA CAN BE USED TO CALCULATE THE AMOUNT OF SKIN DAMAGE. THE SKIN FACTOR, S, IS A DIMENSIONLESS INDICATOR

Undamaged well S = Zero Damaged well S = Positive Stimulated well S = Negative

Flowing Shut In

Flowing

Shut In

Flowrate 1000 bpd

2000 bpd

Skin damage results in a higher drawdown for the same flowrate. 170 GE Title or job number 7/5/2019

SKIN

In this example, if our lift system can only draw the well down by 1000 psi we will get 1800 BPD from the damaged well and 2800 BPD from the undamaged well.

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DENSITY FROM PRESSURE

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TEMPERATURE Operating Principle The PRT measures downhole temperatures from the change in resistance of a fast-responding platinum resistance element.

The probe is contained in a thin, pressure tight Inconel® needle, protruding into an open slot through which borehole fluid can flow. The probe resistance is included as a component in a frequency oscillator circuit.

The circuit elements are chosen so that at 0°C the sensor frequency is close to 100Hz and increases linearly at approximately 4.5Hz/°C. This frequency is multiplied by 64 to achieve the desired sensor resolution.

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TEMPERATURE Operating Principle The output frequency depends only on the sensor temperature. Changes in circuit board temperature have negligible effect on the measurement. An exact calibration of each tool against a secondary platinum resistance standard accurate to 0.5°C or better is provided with each tool. Although essentially linear, a multipoint calibration is supplied and recommended. The resistance of the platinum wire, used in the probe, varies roughly 38% for 100°C of temperature change. 174 7/5/2019

TEMPERATURE How is temperature data used?

Qualitative

• Geothermal gradient – –

ideally, well would be logged before production practically, use data from bottom of well

• Fluid influx causes deviation from geothermal gradient – –

liquid causes increase – friction heating, 4°F/1000 psi drawdown gas causes cooling, due to expansion

• Responds to activity outside pipe Quantitative

• Input for PVT, converting downhole rates to surface rates • Compute flowrate 175 7/5/2019

TEMPERATURE OIL/WATER WELL

Flowing Shut In (Temperature cools off)

Fluid Entry at Geothermal Temperature

(Shape is dependent on total flow and amount of inflow).

Geothermal Temperature Gradient 176 GE Title or job number 7/5/2019

TEMPERATURE GAS WELL (below approx 7500 psi) Shut In (Temperature warms up)

Flowing (Shape depends on total flow and amount of inflow).

Fluid entry below Geothermal Temperature due to gas expansion

Geothermal Temperature Gradient

177 GE Title or job number 7/5/2019

TEMPERATURE

INJECTION WELL 178 GE Title or job number 7/5/2019

TEMPERATURE

Producing well 179 GE Title or job number 7/5/2019

TEMPERATURE Up flow behind pipe

SI cross-flow down

180 GE Title or job number 7/5/2019

TEMPERATURE Calculating Flow Mixed Stream @ T0

Energy balance w1Cp1T1+w2Cp2T2 = T0(w1Cp1+w2Cp2) assume fluids have same heat capacity, so

Stream 1 @ T1

Reservoir A

w1/w2 = -(T0-T1)/(T0-T2) because w1+w2=w0 (full flow) Stream 2 @ T2

w1/w0 = (T0-T2)/(T1-T2)  Stream 1 percentage contribution.

Individual Tools in detail: 1. 2. 3. 4. 5.

Flowmeters (Spinners) Fluid Identification tools Pressure & Temperature Depth control Auxiliary tools

DEPTH CORRELATION Open Hole – GR

Cased Hole – GR/CCL Tubing Tally – CCL

Always ask for “The Depth Reference Log” (Preferably obtain an ascii file of the GR)

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CASING COLLAR LOCATOR The Casing Collar Locator (CCL) detects changes in metal volume as it moves through tubing or casing. The field around the magnets in the tool is disturbed inducing a low frequency voltage or EMF in a coil mounted between the magnets.

The signal is amplified and the frequency is output at surface (SRO) or recorded downhole (Memory).

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CASING COLLAR LOCATOR Operating Principle The CCL consists of opposing annular magnets separated by an annular bobbin carrying several thousand turns of wire in a coil. Changes in metal volume change the lines of magnetic flux passing through the coil – this generates a voltage. The magnets are compound, consisting of two or more magnets 3/8″ thick and separated by pole pieces to make a 2″ long magnet. Collars generate a low frequency signal in the coil as the tool them.

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CASING COLLAR LOCATOR Operating Principle As a casing collar is passed, the disruption in the magnetic field pattern results in a wavelet being generated at a frequency dependent on the cable speed. At usual logging speeds this is around 0.2Hz. The wavelet consists of a small down-swing, a large upswing, and then another small down-swing. The CCL coil output is frequency modulated onto a high frequency carrier prior to sending to the Ultrawire Telemetry board.

CCL Wavelet

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CASING COLLAR LOCATOR Operating Principle The low frequency CCL is amplified and filtered before modulating a VCO (Voltage Controller Oscillator) which has a typical centre frequency of 6 or 17kHz depending on revision level. This frequency is stored in the FPGA logic and is read out over the Ultrawire toolbus in response to requests from the Telemetry Controller e.g. MPL, XTU or other crossover. Various commands are supported in the protocol.

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GAMMA RAY Operating Principle Overview The detector is a Sodium Iodide crystal. When a gamma ray passes through the crystal it causes a photon of light to be emitted (it scintillates). The light signal is amplified using a photomultiplier tube to create a measurable charge pulse. The PMT has a 1600V high voltage PS.

The pulses are detected and filtered for noise, are stored and sent to the memory tool / surface system.

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GAMMA RAY Operating Principle- Electronics The HV PSU generates the -1.6kV Cathode potential and the voltage taps for the PMT Dynodes. The PMT anode output is at ground potential.

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GR – WATER INGRESS

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GR – WATER INGRESS Re-scale the PL GR in high and low zones to overlay the reference GR log. In this case re-scale using values at 2940m (low) and 2960m (high).

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Individual Tools in detail: 1. 2. 3. 4. 5.

Flowmeters (Spinners) Fluid Identification tools Pressure & Temperature Depth control Auxiliary tools

Add Noise tool !

LEAK DETECTION

Sand production associated with water production has eroded a hole in the blast joint in the tubing in front of the perforations. The leak can be seen quite clearly on the spinner response.

X-Y CALIPER X-Y caliper •

2” to 9” std (special 3.4” to 14”)

•

rollers or skids

•

not common in pipe

•

necessary in open hole

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X-Y CALIPER

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X-Y CALIPER Response is not linear, make multi-point calibration

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Deployment tools Weight/Sinker Bars The various forces lifting the tool string are: • During shut-in: – Well head shut-in pressure. This is simply a calculation of the WHP/(cross-sectional area of the wire) to find the weight to balance the well head pressure, add additional weight to allow the tool string to descend.

• During flowing: – Lift force on the bottom of the tool string. – Lift force on the arms of centralisers, and caged full bore arms. – Friction force acting on the surface area of the tool string. – Piston effect force acting as the tool passes through a restriction. – Friction force acting on the surface area of the wire line. 199 7/5/2019

Deployment tools WEIGHT TO BALANCE WHP for slick & braided lines

600 5/16in

WEIGHT (lb)

500 400

9/32in

300

7/32in

200

3/16in 0.125in

100

0.108in 0 0

1000

2000

3000

4000 WHP (psi)

5000

6000

7000

8000 200 7/5/2019

Deployment tools Weight/SinkerBars Lift(N) = F * ρ(kg/m3) * V2(m/s) * π* d(m) * length/2(m) THE LINE TENSION MUST NEVER BE ALLOWED TO DROP BY MORE THAN 30% OF THE SHUT-IN TENSION. For example: If shut-in tension = 1000lbs, minimum allowable flowing tension = 700lbs.

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Centralisers (PRC) • Roller 3-arm - standard; easy entry option; various spring forces e.g. 25 or 40lbs • Roller 4-arm - for critical centralisation; 110lbs force, option 60lbs • Bowspring (PSC)- required for barefoot completions; 50lbs force

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Deployment tools Knuckle joints • remove excess weight from centralisers • flexibility of string (buckled, twisted pipe) • 10 deg displacement • space out with PGR in larger pipe Swivel joints • perforating jobs • eliminate tool rotation due to wireline torque • MIT operations 203 7/5/2019

Deployment tools PIA - Production Inclinometer Accelerometer • deviation survey, horizontal wells • accelerometer to correct yo-yo effect on spinner

Head Tension Unit • avoid breaking the weakpoint • monitoring of tool sticking • CT operations in horizontal, highly deviated wells

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JOB PLANNING Obtain as much as possible of the following information before the job: 1. 2. 3. 4.

5. 6. 7. 8.

Objective(s) of the PL job Surface production rates Fluid properties (including H2S & CO2) & PVT data Well sketch • Minimum restriction • Open (and closed) perforated intervals • Max deviation • Deviation across the interval (or a deviation survey) Correlation GR/CCL log, preferably an ASCII file Estimation of time to flow the well until it is stable Well history, problems previously encountered WH & BH pressures & temperatures, flowing & shut-in

Make tool lift calculations for weight required – high rate wells 205 7/5/2019

Components of a PL Toolstring Deployment • weight bars, knuckles joints, centralisers Depth Correlation • CCL, GR Fluid Flowrate • Various spinner types Fluid Identification • Density and Holdup PVT • Temperature & Pressure 206 7/5/2019

Components of a PL Toolstring Pipe condition • XY caliper • MIT • MTT Complex Flow conditions • Diverter Basket Tool • Capacitance Array Tool • Spinner Array Tool • Resistivity Array Tool Specialty Tools • High Temperature / High Pressure • Tracer tools • Pulsed Neutron Tools • Noise tools 207 7/5/2019

Choice of Tools & deployment TYPES OF WELLS

• Production wells - fluid identification needed • Injection wells - fluid identification not needed CHOICE OF SENSORS

• the completion type and size of tubing - minimum restriction. • down hole flowrate - WEST. • ‘barefoot’ or cased. • BHP, BHT & PVT.

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Deploying PL Tools

Electric line • SRO tools, can see real time what is happening. • Used in high profile jobs and when rig time is expensive. • Max deviation  65 degrees depending on the well. • Greater amount of equipment needed. • Larger wire cross section problematic in very high pressured wells. • Better in very high temperature wells. • Grease injection is most frequent method of pressure control. • Cable head rope socket has a weak point if tools are stuck. • Braided armour, higher friction factor 209 7/5/2019

Deploying PL Tools

Slick line • Memory tools only • Economical, unit always on site. • No real time monitoring; more job planning, reliance on good maintenance. • May not be ideal for high temperature wells. • High profile wells, use tandem tool strings. • Smooth surface leads to lower friction factor. • Good for high flow rate wells. • Can log to about 82 degrees, wire has less drag than electric line. • Slickline ‘stuffing box’ with rubber inserts; no grease is required. • Rope sockets have no weak point; jars can be run. • Use of spring jars, or spang jars modified with shear studs. 210 7/5/2019

Deploying PL Tools

Coiled Tubing (or Continuous Sucker Rod) • SRO (CTU) requires CT reels with a conducting wireline  expensive. • CTUs with electrical conductors cannot be used for well stimulation operations. • Pressure control is through stripper rubbers. • Rig up difficult, especially on-shore where use of a deployment bar may be required. • Risk of CT collapse; pump fluid through the reel during logging operations. • Presence of coiled tubing in the well can change inflow pattern. • CT can ‘lock up’ from helical buckling. • Release sub, allows disconnection from stuck tools. • Ability to lift well with Nitrogen.

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DEPLOYING PL TOOLS

Tractor • Cost effective compared with coiled tubing. • Electrically driven – either directly or by powering a hydraulic pump. • Some tools (not Sondex) require very high power and so larger diameter line is required. • RIH normally to hold up, then tractor onward. • Logging is performed by spooling in the line at surface. • Rig up is as for a standard e-line job with additional lubricator. • WEST predictive s/ware to estimate loads & tension while logging. • Release sub option for emergency ‘get-away’. • Electrical noise prevents simultaneous motoring & logging. • A SAFE system is needed in order to perforate with a well tractor e.g. ADS.

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