Tracer Technology for Improved Reservoir

Description

Dr. Christos Chatzichristos

NCSR Demokritos

What is Tracer Technology?Tracers are chemicals added to injection gas and water to describe the flow in the reservoir. Samples of water and gas are collected from the producers and analyzed for tracer concentration.

Tracers can yield information on:• Flow directions• Transit times• Mass balance• Layers• Faults• Oil saturation• Miscibility of injection gas

•The ultimate use : To optimize/improve/verify the reservoir model

Water tracers Fluorobenzoic acids (e.g.

2-FBA)

Naphthalenesulfonic acids (e.g. 2,6-NDS)

Gas tracers Perfluorocarbons (e.g.

PMCH)

Chemical tracers

Tracerdata

Reservoirmodel

Biostratigraphy

Sedimentology

Reservoirsimulation

Production data

Geochemistry

Geology

Seismic

Reservoir characterisation

Field Flow Mapping

Injection wellsProduction wells

Interwell Communication

• Verify communication • Identify channels and

preferred flow paths• Calculate sweep

volume

Efficiency of Water Injection

P112 % P2

5 %

P335 %

P440 %

P58 %

P3 P2

P1

P2

P3

P4

P5

P-18A

P-40

P-12P-8

P-7P-17

P-11

P-28 P-29

P-13

P-34

P-25A

P-38

WFBCFB

TLP

Statfjord Formation

Lunde Formation

Injector Main producerP-25 P-29 and P-13P-28 P-40P-34 P-29

Flow direction of water tracers

Evaluation of Gas Miscible Injection

0

0.02

0.04

0.06

0.08

0.1

0.7 0.8 0.9 1 1.1 1.2 1.3

NO

RM

ALIZ

ED F

RAC

T. C

ON

C.

ELUTED GAS

0

0.02

0

0.02

0.04 0.04

0.06 0.06

0.08

0.1

0.7 0.8 0.9 1 1.1 1.2 1.3

NO

RM

ALIZ

ED F

RAC

T. C

ON

C.

ELUTED GAS

Tracers in Dual Porosity Systems

0E+00

5E-05

1E-04

2E-04

2E-04

3E-04

11/03/1997 24/07/1998 06/12/1999 19/04/2001 01/09/2002 14/01/2004

Date

Trac

er C

once

ntra

tion

0.0E+00

2.0E-06

4.0E-06

6.0E-06

8.0E-06

1.0E-05

1.2E-05

1.4E-05

1.6E-05

1.8E-05

2.0E-05

24/07/1998 06/12/1999 19/04/2001 01/09/2002 14/01/2004Date

Trac

er C

once

ntra

tion

Barrier DetectionWatercut B-3H

0.0

0.2

0.4

0.6

0.8

1.0

1.2

Nov-98 Nov-99 Nov-00 Nov-01 Nov-02 Nov-03 Nov-04

Date

Wat

ercu

t

SimulationField Data

TFBA Well B-3H

0

1000

2000

3000

4000

5000

6000

7000

8000

Nov-98 Nov-99 Nov-00 Nov-01 Nov-02 Nov-03 Nov-04Date

Conc

entra

tion

(ng/

lt)SimulationData

Determining Flowpaths

GullfaksSegment H-1

0

20

40

60

80

100

0 1000 2000 3000 4000 5000

Time (days)

Wat

ercu

t (%

)

Simulation

Field data

0.0

0.1

0.2

0.3

0.4

0 1000 2000 3000 4000Time (days)

Trac

er C

once

ntra

tion

(gr/

m3)

Field data

Simulation

Determining FlowpathsMain flow-path in the original model, the water comes from I-A5H

Main flow-path in the improved modelcorresponds to the path of water injected in I-A38

Tracer injectedin well I-A38

0

20

40

60

80

100

0 1000 2000 3000 4000 5000

Time (days)

Wat

ercu

t (%

)

Simulation

Field data

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0 1000 2000 3000 4000 5000Time (days)

Trac

er C

once

ntra

tion

(gr/

m3)

RealFinal-FLS

HC Reservoir Engineering AS

Sweep eficiencySimulated and measured HTO in ALK013

0

1000

2000

3000

4000

5000

6000

7000

Jul-98 Jul-99 Jul-00 Jul-01 Jul-02 Jul-03 Jul-04 Jul-05

Date

Con

cent

ratio

nBq/

litre

0

5

10

15

20

25

30

35HTO Field DataHTO Model '300' High Perm. PathHTO Model '300' Rel. Perm. HTO Model '300' Base

The base case (original model) predicts matrix flow. The likely solution is that injection water moves through a high-perm. layer on its way to the producer. The injection water is thus not sweeping as intended. Although the original model has a reasonable matched water cut, the tracer history matching reveals that the water is coming from the wrong source.

The colors indicate tracer concentration in the model.

Simulated and measured WaterCut in ALK013

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

Mar-97 Mar-98 Mar-99 Mar-00 Mar-01 Mar-02 Mar-03 Mar-04 Mar-05 Mar-06Date

Wat

ercu

t

WCut HistoryWCut Rel.PermWCut High Perm PathWCut Base

Detection of Gas Attic StorageSnorre FieldCentral Fault Block

Gas tracers in P29

0

100

200

300

400

500

600

700

800

900

1000

jan.93 jul.93 feb.94 aug.94 mar.95 sep.95 apr.96 nov.96 mai.97 des.97

Date

GO

R

0

2E-13

4E-13

6E-13

8E-13

1E-12

1.2E-12

Con

cent

ratio

n / i

njec

ted

amou

nt (1

/l)

GORPMCH injected P25 28.03.94PDMCB injected P28 28.09.941,3-PDMCH injected P28 05.07.95SF6 injectd P28 22.03.97

Detection of Gas Attic Storage

0.000

0.050

0.100

0.150

0.200

0.250

0.300

0.350

0.400

0 365 730 1095 1460 1825 2190

Time, day

Conc

., m

g/Sm

3

Measured 1,3-PDMCH Conc.Non-storageStorage

Gas storage

0.000

0.005

0.010

0.015

0.020

0.025

0.030

0.035

0.040

0 365 730 1095 1460 1825 2190Time, day

Conc

. mg/

Sm3

Measured PDMCB Conc.Non-storageStorage

0.0

0.3

0.6

0.9

1.2

1.5

1.8

2.1

2.4

2.7

3.0

0 365 730 1095 1460 1825 2190

Time, day

Con

c., m

g/Sm

3

Measured SF6 Conc.Non-storageStorage

Natural Tracers

Formation water = Information water

Early detection of injection water breakthrough

Accurate quantification of injection water

Minimize water production, pollution and reinjection cost

Identify fluid compartments, flow paths and barriers

Production allocation

Prognosis for scale and formation damage

Methods• Residual salt analysis• Isotop ratios• Water analysis

-30.0

-25.0

-20.0

-15.0

-10.0

-5.0

0.0

5.0

15.03.00 23.06.00 01.10.00 09.01.01 19.04.01 28.07.01 05.11.01

δD ‰ SMOW

Fault

PA-13

IA-9

It follows the indicated path, around the fault.

Sea water is injected in the injection well IA-9 and produced in theproducer PA-13

Will extend this fault to try to match SO4 and water-cut

Natural tracer in the Veslefrikk Field

SO4

Measureddata

Simulation

Effect of modifying fault lengthWater cut

measured

Original faultFault extended 1 blockFault extended 2 blocksFault extended 4 blocks

measured

SO4

Original faultFault extended 1 blockFault extended 2 blocksFault extended 4 blocks

Extending the original fault by 1 cell gives early arrival

Extending the original fault by 4 cells gives late arrival

The original fault gave early arrival

The best results are obtained when the fault is extended by 2 cells i.e. about 200 m

An Integrated Approach

The tracer data indicate two distinctive paths connecting the W103 and W109. This is not reflected at the model. Consistent with this is the Breakthrough Timeof the injected water, which also is not captured by the model.

GIR109

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

1.1

1.2

Jun-01 Dec-01 Jun-02 Dec-02 Jun-03 Dec-03 Jun-04 Dec-04 Jun-05 Dec-05 Jun-06 Dec-06 Jun-07 Dec-07 Jun-08

Date

WCT

FW

0.E+00

1.E-06

2.E-06

3.E-06

4.E-06

5.E-06

6.E-06

7.E-06

Trac

er C

once

ntra

tionFW fraction

WCTFW simTR103 ConcTR103 sim

BT 1st flow path 1st flow path

BT 2nd flow path2nd flow path

What is a Partitioning Tracer?

EtAc + H2O EtOH + HAc

What is Hydrolysis of the Tracer?

Water tracer

Water-oil partitioning tracer

Oil

Water

Kd=Co/Cw = 5/5 = 1

The Kd value is found in a PVT or Petrophysics lab using live oil and reservoir water.

The hydrolysis rate is found using reservoir water at atmospheric pressure.

Partitioning Tracers – Oil SaturationInjector

At time of production of passive tracerAt time of injection

Producer

Partitioning tracer, e.g. pentanol

Passive tracer, e.g. FBA

KVVVV

Sor

0

0

+∆

∆

=

T=50 degr.CP=150 bar

1 1.6 2 2.2 2.4 2.60.8 1

14

12 10

8

6

4

2 0

1.81.41.2

NO

RM

ALI

ZED

RE

LATI

VE

CO

NC

EN

TRAT

ION

PMCP PMCH

b.

1.6 1.8 2 2.2 2.4 2.60.8 1 1.2 1.4

12 10

8

6 4

2 0

14

PMCP PMCH

a.

CH CH3 314

CH CH3 314

CH T3

CH T3

ELUTED GAS VOLUME (in units of PV)

T=50 degr.CP=250 bar

Gas tracer core-flooding experimentsTracer dispersion profiles, 30% residual oil saturation

Estimation of Remaining oil Saturation

Partitioning tracers – oil saturation

The oil saturation between the injector and the producer, where the injection fluid contacts the oil, can be calculated using two tracers with different partitioning coefficients.

The oil saturation isrelated to the differentarrival times of a non-partitioning and a partitioning tracer.

In two- and three-phaseflow systems the So inthe RM is tuned untilthe tracer curves match.

Non-partitioningtracer

Partitioning tracerwith K-value = 1

Measuring Residual Oil SaturationThe average SOR up to ~20’ from the producer can be measure using reacting tracers:

1. Push the reacting tracer into the formation.Typical tracer: Ethyl acetate

2. Let the tracer react with water.Ethyl acetate + H2O → ethanol + acetic acid

3. Back-produce and measure the different arrivaltimes/volumes of the ethyl acetate and the ethanol.

Ethyl acetate has a partition coefficient, K, to oil.Ethanol doesn’t partition to the oil phase.Ethanol will therefore be back-produced first.The SOR in a simplified system becomes:

A simulator is used to calculate the SOR in a field-test.

The partition coefficient, K, is measured in the lab.

Ktttt

Sor+∆

∆

=

0

0

SWTT Tracer Profiles

Evaluating EOR Efficiency

Measurement of Sor prior to EOR Measurement of ROS by injecting passive and

partitioning tracers ahead of the chemical front. Injection of passive tracer with the chemical front for

the evaluation of the chemicals’ flow. Measurement of Sor after EOR Measurement of ROS by injecting passive and

partitioning tracers behind of the chemical front.

Other Applications of the Tracer Technology

14000 -- 16000 12000 -- 14000 10000 -- 12000 8000 -- 10000 6000 -- 8000 4000 -- 6000 2000 -- 4000 0 -- 2000

Tracers in LaboratoryInjector

Producer

Radioactive tracer for measuring fluid saturation in flooding experiments.

Formation damage:Measurement of CaCO3 and BaSO4 scaling by aid of radioactive 47Ca or 131Ba

Tracers in process systems

Detector

Detector

Rich gas

Liquid hold-up

Measurement of liquid hold up in pipelines.(Huldra-Heimdsal, Åsgard-Midtgard)

Tracers to measure liquid carry-over in separator systems

Thank you for listening !