Schlumberger - Wireline Formation Testing

WIRELINE FORMATION TESTING Sammy Haddad, Ph.D. Reservoir Engineering Advisor

WIRELINE FORMATION TESTING OUTLINE • •

Introduction Formation Fluid Pressure Measurement – – – – – –

•

XPT Tool XLD-PA VIT Minifrac CHDT & OH-CHDT

DFA & Sampling – – – –

Downhole Fluid Analysis (DFA) Sampling, CFA & LFA QuickSilver XLD & PA for sampling

Why Wireline Formation Testing? Wireline Formation testing allows determination of pressure of mobile fluid in the reservoir and its identification through fluid analysis/sampling

Potential Hydrocarbon Zones

Potential Water Zones

Why Wireline Formation Testing? Comparison Wireline Formation Testing vs DST (Drill Stem Test): •Environmentally Friendly – No Hydrocarbon Flaring •Faster-day vs. weeks •Better reservoir characterization (detailed analysis for each zone tested) •Performed in Open Hole, possibility to change completion program due to contingency

Evolution of Formation Testers 50s FT Formation Tester

70s RFT 90s MDT Modular Repeat Formation Dynamics Formation Tester Tester Electrical Power Hydraulic Power

Year 2001 - CHDT Cased Hole Dynamics Tester

Probe Dual-probe Flow control

Dual Packer

Optical Fluid Analyzer Multisample Sample Sample Pumpout

1955 - 1975

1975 - Present

1991/1993 - Present New Generation

Year 2004 - XPT Pressure Express Tool

CQG

Pretest with MDT Single Probe Module

Isolation Valve

Equalising Valve

Strain Gauge

F l o w l i n e

Single Probe (MRPS)

Pretest

Front Shoe Packer

B u s Resistivity/ Temperature Cell Articulated Flowline

Filter

Filter Valve

Probe Pistons

MRPS BLOCK

Back-up Telescoping Pistons

Determining Formation Fluid Pressure

K/µ µ = C q / ∆P C=2395 for LD C=5660 for SP

When the probe is set in the wellbore, a short test, which is called a pretest, is conducted to measure the formation pressure. Usually up to 20 cm3 of fluid is withdrawn from the formation during the pretest. At the end of the drawdown period, the pretest chamber is full and the build up period starts.

Examples of flow geometries experienced in the vicinity of a wireline formation tester (Goode et al., 1991)

6-3

Theoretical log-log plot of pressure derivative for a sink probe buildup

6-4

Log-log plot of pressure derivative for a sink probe buildup

6-5

MDT Modular Design Basic tool modules • Electrical power • Hydraulic power • Single probe • Sample chambers

Optional tool modules • • • • • •

Dual-probe Flow-control Dual-packer Multisample • MPSR 450 cc PVT • SPMC 250 cc Single Phase Pumpout Optical Fluid Analyzer

XPT- Pressure Express Tool Formation Fluid Pressure Measurement

XPT PressureXpress • Combines with almost all Schlumberger tools (i.e PEX, DSI,FMI,ECS)

•Minimizes Risk of tool sticking • • •

Small diameter 3 7/8” ½” eccentered tool Shorter test measurement time

•Smart pretesting • •

Measures rapidly reservoir pressure Increased test success in tight formations

Tool Specifications •Rating: •Diameter: •Length: •Weight: •Hole sizes: •Pretest volume: •Pretest rate:

20,000 psi and 150°C 3.375 in. (3.875 in. at probe) 6.4 m. 125 Kg 4.75 to 15.4 in. 0.1 to 37 cc 0.02 to 2.6 cc/s

Two Sapphire Gauges • ± 5 psi accuracy, 0.04 psi resolution, 20 kpsi, 175°C • Simultaneous Formation and Hydrostatic pressure CQGCQG-L • ±2.5 psi accuracy, 0.005 psi resolution, 15 kpsi, 175°C

Identifying fluid types, densities and contacts

Gradients gives insitu fluid densities (psi/m) Fluid Density (g/cm3) = Pressure Gradient (psi/m) 1.422 Typical fluid densities (g/cm3) Gas Oil Water

0.18 0.64 1.03

0.1psi/ft 0.3psi/ft 0.465psi/ft

Gradient example 1

Gradient example 2

MDT - Modular Dynamics Tester Formation fluid pressure measurement and characterization

Evolution of Formation Testers 50s FT Formation Tester

70s RFT 90s MDT Modular Repeat Formation Dynamics Formation Tester Tester Electrical Power Hydraulic Power

Year 2001 - CHDT Cased Hole Dynamics Tester

Probe Dual-probe Flow control

Dual Packer

Optical Fluid Analyzer Multisample Sample Sample Pumpout

1955 - 1975

1975 - Present

1991/1993 - Present New Generation

Year 2004 - XPT Pressure Express Tool

CQG

Single Probe Module

Isolation Valve

Equalising Valve

Strain Gauge

F l o w l i n e

Single Probe (MRPS)

Pretest

Front Shoe Packer

B u s Resistivity/ Temperature Cell Articulated Flowline

Filter

Filter Valve

Probe Pistons

MRPS BLOCK

Back-up Telescoping Pistons

MDT Log Example

Mud Pressure

Formation Pressure

Mud Pressure

Factors Affecting Sample Capture •Single phase sample •Difference between reservoir pressure & HC bubble point or dew point pressure •Draw Down pressure •Flow rate sufficient to clean up •Area available to flow Liquid

Initial Pr & Tr

K = C q µ / ∆P

Pressure

APO

2Φ

∆P ∝ q µ / k A

Gas

Temperature SingleSingle- phase Bottomhole Sampler

Extra Large Diameter Module, XLD


XLD

-

~100% Increase in flow area. area. (2.01in^2 (2.01in^2 vs 0.85in^2) Reduces drawdown (100 psi vs 700 psi). psi). Replaces MDT packer saving rig time. Increases number of effective prepre-tests. Increases mobility range.

Quicksilver – the Concept Current generation sampling tools
One pump


One flowline
Kv / Kh, invasion and fluid viscosity contrast causes contamination
Even long clean up time will not prevent contamination

Focused Sampling with QuickSilver probe
Step change in sampling technology


Sampling using two synchronized pumps
Independent flow lines for both pumps
Optimize flowrate ratio between guard and sampling lines
Proven reduction in clean-up times
Very low contamination levels expected pump1 EDTC

MRPC

MRSC/M S

LFA1

MRHY

Focusedprobe

pump2 LFA2

IPTT Interval Pressure Transient VIT Vertical Interference Test

vertical probe 2 3160

3000

3140 Probe 2

vertical probe 1

2000

3120 14.4ft zo2

1000

sink probe

3100

Probe 1

horizontal probe

0

6.4ft zo1

3080

Dual probe Packer

3120 3160 time, s

3080 3200

MDT Mini-Frac Test Wireline Pumpout module Pressure gage Inflate seal valve

P

Packer Interval seal valve

P

1m

Packer P

Sliding coupling Flow control Module Sample chamber

Hydraulic Fracture

CHDT – Testing Formations Behind Casing Telemetry

9.6 ft 262 lbm

Optional GR or CCL

7.9 ft 189 lbm

9.8 ft 232 lbm

Power supply

Drilling controller

Probe module

13.5 ft 370 lbm

1-gal, 4¼-in. sample chambers

•Length (without sampling) •Optional sample chamber •Tool OD •Casing size •Casing thickness •Temperature •Pressure •H2S service •Max underbalance •Max holes drilled/plugged •Drilled hole diameter •Max penetration •Plug pressure rating •Pretest volume •Pressure sensors •Standard CQG pressure •Sampling •Fluid identification MDT combinability

31.2 ft 9.7 ft 41/4 in. 51/2 to 13 3/8 in. Up to 0.625” thick 350°F 20,000 psi Yes 4000 psi †6 per run 0.28 in. 6 in. 10,000 psi, bidirectional 100 cm3, can be recycled CQG and strain gauges 15,000 psi PVT and conventional Resistivity and LFA, CFA Yes‡

• † Formation dependent • ‡ Combinable with MDT modules in 6-5/8 in. and larger casing (pumpout, LFA, CFA, and PVT sample chambers)

CHDT – Testing Formations Behind Casing Telemetry

9.6 ft 262 lbm

Optional GR or CCL

7.9 ft 189 lbm

9.8 ft 232 lbm

Power supply

Drilling controller

Probe module

13.5 ft 370 lbm

1-gal, 4¼-in. sample chambers

•Length (without sampling) •Optional sample chamber •Tool OD •Casing size •Casing thickness •Temperature •Pressure •H2S service •Max underbalance •Max holes drilled/plugged •Drilled hole diameter •Max penetration •Plug pressure rating •Pretest volume •Pressure sensors •Standard CQG pressure •Sampling •Fluid identification MDT combinability

31.2 ft 9.7 ft 41/4 in. 51/2 to 13 3/8 in. Up to 0.625” thick 350°F 20,000 psi Yes 4000 psi †6 per run 0.28 in. 6 in. 10,000 psi, bidirectional 100 cm3, can be recycled CQG and strain gauges 15,000 psi PVT and conventional Resistivity and LFA, CFA Yes‡

• † Formation dependent • ‡ Combinable with MDT modules in 6-5/8 in. and larger casing (pumpout, LFA, CFA, and PVT sample chambers)

Mobility Changes Near Wellbore…. CHDT example in CH • Bit Penetration 3.1”

Bit Penetration 4.6”

Bit Penetration 5.5”

Mobility 1.6 mD/cp

Mobility 8.3 mD/cp

Mobility 11 mD/cp

Open Hole DT •

High overbalance, LCM, low gravity solids plugging pores…???

•

Why not testing formation past the damaged zone? – Combinable with MDT – Set, Drill, Test, Retract… – Pressure rating: 20 kpsi Differential pressure rating: 6kpsi* Temperature rating: 260 degF* H2S service* – Bit size: 5 7/8” – 10 ¼”* – 30” of formation drilled per descent*

Pumpout Module Can pump formation fluids from formation into the borehole (Max. ∆p = 3500 psi, Max. rate 45 cc/s) Typical rate is 1 liter/minute Clean the mud filtrate from the formation before collecting fluid samples.

Electrical power module Pumpout module Hydraulic power module Probe module Dual-packer module Sample module

Downhole Fluid Analysis with MDT -LFA Live Fluid Analyzer -CFA Condensate Fluid Analyzer

Holding Oil up to a Light • Different oils are different colors – – – – –

black brown reddish yellowish clear

• Just as you would hold a test tube of oil up to a light to look at its color, that is what the Fluid Analysis with MDT does downhole

LFA - Optical Fluid Analyzer Module •Ten optical detectors look at the light source through the fluid •A reflection system can tell if any gas is in the flowline

Pumpout module Multisample module Sample chamber LFA

Single probe module

Packer module

LFA – Liquid Analysis Metal flowline within the MDT

Intensity of light measured at different wavelengths

Visible and near infrared light source

Fluid flowing from the formation and along the flowline

Optical density

I T= I I

I

l Optical Density (D) is linear with path length

D = log T 100% 10% 1% 0.1% 0.01%

1 T

{} D 0 1 2 3 4

Optical Absorption Spectrum of fluids

CFA Spectrometer Optical Density Channels

Hydrocarbon Peak

Crude Oil vs OBM Filtrate Since methane is present in all naturally occurring hydrocarbons and is absent in drilling fluids, any methane detected is due to reservoir hydrocarbon and not filtrate. GOR determination

0

8

MDT pH sensor : Principle of measurement Lamp Dye Injector water pumped Flow line Detector

MDT Ph sensor

LFA Log - Oil Sampling Pumpout stopped Oil

Oil Peak Channel 8

Decreasing contamination

Pumpout started

Mud

LFA Log - Formation Water Sampling Pumpout stopped Water

Water Peak Channels 6 and 9

Decreasing contamination

Pumpout started

Mud

Growth of OD with Time

t2

Oil

Filtrate

Oil cone

Filtrate

Filtrate

t1

t3

OD

Data

t1 t2 t3 Probe

Time

LFA gas detector Wellbore fluids’ minimum θ c Gases Total reflection if gas

Liquids Sapphire Fluid Mostly refraction if liquid

….

LFA Logs - “Fingerprints” of various Fluids

Answer Product • • • • • •

LFA independent CGA apparent fluid density (C1, C25, C6+ partial densities addition) Water volume Color channels GOR/CGR Fluorescence channels

CFA Compositional Fluid Analyzer

OD (pathlength = 2mm)

2.0 (normalized) methane ethane propane n-butane n-heptane CO2

1.5

1.0

0.5

0.0 1600

1700

1800

1900

Wavelength (nm)

2000

2100

Example 1 (Abu Dhabi) Gas Injection Monitoring Depth A: no gas Depth B: plenty gas Depth C: Some gas Depth D: Some gas

Example 2 (North Sea) Vertical composition gradient is observed in an exploration well Composition (wt%)

Pressure Gradients

C1 C2-C5 C6+ water

3660

xx68.2m 0.374 g/cc

xx75.1m

3680 Depth (m)

xx85.6m 0..599 g/cc

xy00.0m

3700

xy06.3m 0.982 g/cc 3720 377

378

379 Pressure (bar)

380

381

*

GOR Ch. 1 (scf/bbl) (OD)

7900 9000 2500 2100 2000

0.1 0.7 0.8

1800 1500

1.4 2.0

Crude oils from a Single Column. Compositional Grading from Charge History. (No Mixing! Nonequilibrium. Shell) Heavies and light ends separately out of equilibrium

Top

Bottom

Cap Rock

Burial Cap Rock

Ker oge o n 100 C Oil Window Cold

Burial Cap Rock

Ker oge n

Warm

Ker oge n

HOT

Downhole Fluid Analysis (DFA) Top

Bottom

DFA Fluid Scanning DFA GOC & OWC are NOT the Same That Picked From Pressure Gradients

•Transition zone •Gas Injection breakthrough •Water Injection breakthrough •Asphaltenes suspension

and Anyway, Why Should they Be?

GOC From Pressres

OWC from Pressures

Representative Sampling - Review Single-phase vs. Conventional (Oil Reservoir) Liquid Initial Pr & Tr Reservoir Fluid

Pressure

APO

Hydraulic Fluid 2Φ

Nitrogen Gas Gas PV ∝ T

Temperature SingleSingle-phase Bottomhole Sampler Conventional Bottomhole Sampler

Flow Assurance Asphaltenes: Alkane insoluble components of oil & precipitate D (P & T) Waxes: Normal paraffin from C15 to C75 and become solid D (T & P) Gas Injection Water Injection Sampling above onset Press. – Suspension & Precipitation

16000 14000

Pressure (psia)

• • •

12000

Wax Reservoir

10000

Hydrate

8000 6000 4000

Asphaltene Flow line

Bubble Point

2000

0 0

Organic Scale

50

100 150 200 Temperature (°F)

25 0

Definitions & Phase Boundaries Asphaltenes: Alkane insoluble components of oil & precipitate ∆ (P & T) Waxs: Normal paraffin from C15 to C75 and become solid ∆ (T & P) Hydrates: Gas hydrates are inclusion compounds & formed by water and small molecular gases (C1, C2, C3, CO2, H2S) at low temperature and high pressure conditions Reservoir P & T

Well Profile

Wax Hydrate Asphaltene Envelope Envelope

V-L Equilibrium

Power

Near-infra Red Technology for Onset of Asphaltene Precipitation

2,000 15,000 11,000 13,000 3,000 4,000 5,000 6,000 7,000 9,000

Pressure

Oil Chemistry affects… Flow Assurance

Asphaltene Gas Hydrate

Wax

Downhole Fluid Analysis benefits • Improve sampling • Fluid Identification Stations, to

complement gradient interpretation • Define Compositional hydrocarbon grading/ compartmentalization

Thank You