conocophillips test results and data analysis

ConocoPhillips test results and data analysis

Brian J. Anderson Associate Professor, Chemical Engineering, West Virginia University

Methane Hydrate Advisory Committee Meeting, Thursday, June 06, 2013

• North Slope reservoir‐scale field trial to evaluate CO2/CH4 exchange

• Short‐term test to demonstrate concepts at larger‐than‐lab scale

• Validate exchange mechanism results from laboratory work – Confirm injectivity into naturally occurring methane

hydrates

– Confirm methane release without production of water or sand

– Obtain reaction rate data to facilitate reservoir‐scale modeling

• Demonstrate stable production of natural gas hydrates by depressurization

Overall Iġnik Sikumi Project Goals

• 2008 – 2010 – Select site and gain access – Characterize reservoir

• 2011 – Drill, log, complete and suspend Iġnik Sikumi #1 – Design field test

• 2012 – Re-enter well and perforate – Perform exchange test – Perform depressurization test – P & A well and remediate site – Prepare datasets – Begin data analysis

• 2013 – Data analysis and history matching

Project History

• Data Correction/Reconsolidation in Progress – Outliers/spikes removed – Time stamps for each source corrected – GC data reprocessed – Three DTS data sets obtained

• Un‐normalized and 2 types of normalization

– Created 1 and 5 min time average datasets – Adding corrections for dead volumes/wellbore storage

• Path Forward – Perform material balance of test – Injectivity analysis, using simulation

• Infer hydrate saturation changes

– Production analysis using cell‐to‐cell model • Gas phase composition history match

– Issue final database and report – DOE workshop

July 2012 Status

Capillary-bound water

Clay-bound water

Movable water

39% Φavg

“C” Sand

25% SWavg

41% movable

Tem

per

atu

re

Tem

per

atu

re c

han

ge si

nce

6F

eb2

01

2

Initial Period before any well work Temperature linear with geothermal gradient (~1.79oF/100ft), Temperature change ~0

Injection

Tem

per

atu

re c

han

gesi

nce

6F

eb2

01

2

Days since 6 Feb 2012

100

75

50

25

Rat

e (m

scf/

d)

PerforationInjection started

Injection endedWell shut in

1700

1300

1500

1600

1400

BH

Pre

ssu

re p

sia)

Overall Production – Gas rates, Pressure, and Temperature

Ignik Sikumi #1 Production

Flowback - Production Period #1


Tem

per

atu

re c

han

gesi

nce

6F

eb2

01

2

100

50

Rat

e (m

scf/

d)

700

900

1000

800

BH

Pre

ssu

re p

sia)

600

1100150

Well openedUnassisted flow

Well shut-inJet pump installed

Well shut-inReplace sep. valve

Well shut-inFlare line freeze

Well shut-inReplace jet pump

Well shut-inReplace sep. valve

Tem

per

atu

re c

han

gesi

nce

6F

eb2

01

2T

emp

erat

ure

ch

ange

sin

ce 6

Feb

20

12


50

25

Rat

e (m

scf/

d)

Well openedJet pump #2

Shut-inGlycol injected below jet pump End of production procedure started

800

300

400

600

700

500

BH

Pre

ssu

re p

sia)


Successful injection of CO2 mixture into hydrate reservoir

Methane produced both above / below CH4-stability

pressure CO2 was retained in the reservoir compared with N2

Indicates the possibility of CO2 exchange

Depressurization sustained below CH4-stability pressure Steady increase in production rate Over 850 mscf (24,000 scm) of CH4 produced in total Low BHP achieved (~250 psi)

Solids production significant

Evidence for heterogeneous injection / production

Summary Observations

12

• Diagrams of the operations included – PI&D’s + dead volumes of surface equipment and well

• Master Variable List – Where to go for complete info on any recorded variable

• e.g., what instrument recorded the data, calibration, etc

• Supporting Data Document – Where to go for notes on calculations and data corrections

• Operation Event Log – Where to go to see what was happening at every step of the

test

• All raw data in MySQL and CSV format

• All final data available in MS SQL database format, CSV, Matlab – Clean, 1 min averaged, and 5 min averaged data

Database Summary

13

Data Streams

• Composition

– On-line GC (~15 min sampling int.)

• Continuous downhole conditions

– 3 downhole pressure gauges (P&T)

– Distributed Temperature Sensing (T per ft)

• Continuous surface conditions

– Pump rates

– Flow rates (gas, jet pump fluid)

– Line pressures and temperatures

– Separator P&T

• Produced fluid measurements

– Collected on regular intervals

– Water prod rate

• Tank straps (~30min int.)

– Water (~1hr int.)

• pH, salinity, SG

– Gas (~1hr int.)

• Gas gravity

Database Folder

15

• Adiabatic CTC Model (ConocoPhillips)

– Cell Volume (3.5 ft), SH = 65%, Pi = 1000 psi, Ti = 40.5 F

• Solids production

• Heterogeneous production

• History-match simulations of the Iġnik Sikumi field test with newly-developed Mix3HRS software

• Complex pressure, temperature, and composition history

– CO2+N2 injected into a CH4 reservoir with all 3 gases produced

– Competing thermodynamics for hydrate formation and dissociation in the reservoir

Modeling and Simulation Efforts

Hydrate

Saturation

Hall Plot – Varying Permeability

17

Hall Plot

0

1000

2000

3000

4000

5000

0 25 50 75 100 125 150 175 200 225

Cumulative injection (MSCF)

Su

m(d

P*d

t)

Hydrate pilot Gas injection model with k variation

Hall Plot

0

1000

2000

3000

4000

0 25 50 75 100 125 150 175 200


Su

m(d

P*d

t)

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

In-s

itu

pe

rm (

mD

)

Gas Injectivity Estimated in-situ perm

Hall Plot

0

1000

2000

3000

4000

0 25 50 75 100 125 150 175 200


Su

m(d

P*d

t)

0.650

0.700

0.750

0.800

0.850

Hy

dra

te s

atu

rati

on

Gas Injectivity Estimated average Sh

A.

B.

Permeability adjusted over time

One possibility is Δ hydrate sat.

Good match obtained

• The Injection flow rate and cumulative injection of CO2 and N2 into the

reservoir are matched with the field data.

Injection matching

Post-Injection Period

Tem

per

atu

re c

han

ge si

nce

6F

eb2

01

2


BH

Pre

ssu

re p

sia)

1340

1220

1300

1260

Post-Injection Period

Production

0

200

400

600

800

1000

1200

1400

0

200

400

600

800

1000

1200

1400

4-Mar 8-Mar 12-Mar 16-Mar 20-Mar 24-Mar 28-Mar 1-Apr 5-Apr 9-Apr

Cu

mu

lati

ve P

rod

uce

d G

as (m

scf)

an

d W

ate

r (b

bl)

Do

wn

ho

le P

ress

ure

(p

sia)

Unassisted Flowback

4-Mar 14:00 – 6-Mar 00:00

Jet-Pump Flowback #1

7-Mar 04:00 – 13-Mar 23:30


15-Mar 18:52 – 18-Mar 10:40


23-Mar 06:20 – 11-Apr 00:00

CH4 Hydrate Stability P

(based on downhole T)

0

200

400

600

800

1000

1200

1400

0

200

400

600

800

1000

1200

1400

4-Mar 8-Mar 12-Mar 16-Mar 20-Mar 24-Mar 28-Mar 1-Apr 5-Apr 9-Apr

Cu

mu

lati

ve P

rod

uce

d G

as (m

scf)

an

d W

ate

r (b

bl)

Do

wn

ho

le P

ress

ure

(p

sia)

Unassisted Flowback

4-Mar 14:00 – 6-Mar 00:00


7-Mar 04:00 – 13-Mar 23:30


15-Mar 18:52 – 18-Mar 10:40


23-Mar 06:20 – 11-Apr 00:00

CH4 Hydrate Stability P

(based on downhole T)

First 200 mscf produced above CH4 Hydrate stability conditions

Cumulative Gas

Cumulative

Water

More CH4 produced than Equilibrium Model predicts.

CH4 composition in produced gas

0

20

40

60

80

100

0 100 200 300 400 500 600 700 800 900

Cumulative produced gas (MSCF)

CH

4 c

om

po

sit

ion

Pilot 3.5 ft tank

Model predicts exchange significantly depletes CH4 from the near well region.

Pi = 1000 psia Shi = 65 % Ti = 40.5 F

% Recovered based on Injected Amounts

23

0

10

20

30

40

50

60

70

80

90

100

4-Mar 9-Mar 14-Mar 19-Mar 24-Mar 29-Mar 3-Apr 8-Apr 13-Apr

% R

eco

vere

d

N2

CO2

Observations: Field versus Model

• Not enough CH4 from model • Not enough water from

model • Temperature increase too

high in model • Recovery of N2 to CO2

reversed in model • Examining potential

mechanisms of gas production

1. Dissociation in place w/o permeability enhancement

2. Dissociation in place w/sand migration + permeability enhancement

3. Production of solid hydrate (< 200 μm) and subsequent dissociation in wellbore above the jetpump when contacted with warm power fluid

N2 and CO2 recovery

0

20

40

60

80

100

0 100 200 300 400 500 600 700 800 900


N2

an

d C

O2

re

co

ve

ry f

ac

tor

N2_recovery CO2_recovery

Sand Production

25

0

10

20

30

40

50

60

70

5-Mar 10-Mar 15-Mar 20-Mar 25-Mar 30-Mar 4-Apr 9-Apr

Esti

mat

ed

San

d P

rod

uct

ion

(bb

l)


7-Mar 04:00 – 13-Mar 23:30


15-Mar 18:52 – 18-Mar 10:40


23-Mar 06:20 – 11-Apr 00:00

From: Kurihara, et al., Proceedings of the 7th International Conference on Gas Hydrates (ICGH 2011), Edinburgh, Scotland,

United Kingdom, July 17-21, 2011

Figure 17 Schemata of reservoir performances through 2007 and 2008 tests inferred from history matching simulation

Mechanism 2 – Experience at Mallik

Mechanism 2

From: Kurihara, et al., Proceedings of the 7th International Conference on Gas Hydrates (ICGH 2011),

Edinburgh, Scotland, United Kingdom, July 17-21, 2011

Figure 11 Concept expressing overall grid block permeability as a function of MH saturation with

growth of high permeability conduits

Mechanism 3: Solid CH4 – Hydrate produced?

CH4 Hydrate - CO2(l)

contact

Local

disassociation of

CH4 Hydrate

Reformation of

mixed CO2-CH4

Hydrate


contact

Local

disassociation of

CH4 Hydrate

Reformation of

mixed CO2-CH4

Hydrate CH4 Hydrate - CO2(l)

contact

Local

disassociation of

CH4 Hydrate

Reformation of

mixed CO2-CH4

Hydrate


contact

Local

disassociation of

CH4 Hydrate

Reformation of

mixed CO2-CH4

Hydrate

CH4 Hydrate - CO

2(l) contactLocal disassociation of CH

4 Hydrate

Reformation of mixed CO2-CH

4Hydrate

CH4 Hydrate - CO


4 Hydrate


4Hydrate

CH4 Hydrate - CO


4 Hydrate


4Hydrate

CH4 Hydrate - CO


4 Hydrate


4Hydrate

Native State Exchange Depressurization

Well Screen

Largest source of CH4 & water = CH4 Hydrate

Solids (sand) were produced

Mechanism 3: CTC Model Solids Recombination – CH4 Match

CH4 composition in produced gas

0

20

40

60

80

100

0 100 200 300 400 500 600 700 800 900


CH

4 c

om

po

sit

ion

Field data Hypothesis

Mechanism 3: CTC Model Solids Recombination – Recovery

CO2 and N2 recovery factor

0

20

40

60

80

100

0 100 200 300 400 500 600 700 800 900


CO

2 a

nd

N2

re

co

ve

ry f

ac

tor

N2 CO2

Mechanism 3 • Method

– Use EXPRO water rate and %Sed measurements

– Scale sediment rates to match observed cumulative sand production

• Worst-case Assumptions

– All sand produced had associated CH4 hydrate that was produced

– SH values from CMR log

• Gives upper limit to CH4 from solids

0

50

100

150

200

250

300

350

400

450

500

550

0 100 200 300 400 500 600

Cu

m. C

H4

gas

pro

du

ced

(m

scf)

Time (Hours since 3/4/2012 14:00)

Measured Cumulative CH₄ Production (mcf)

Max Cumulative CH₄ Prod by solids

0

4

8

% S

edim

ent

0

500

1000

1500

2000

Wat

er R

ate

(bb

l/d

ay)

• Mechanism 2

– Dissociation in place w/sand migration + permeability enhancement

• Mechanism 3

– Production of solid hydrate (< 200 μm) and subsequent dissociation in wellbore above the jetpump when contacted with warm power fluid

• Reservoir heterogeneity

Field trial likely a combination of mechanisms

CH4 Hydrate - CO


4 Hydrate


4Hydrate

CH4 Hydrate - CO


4 Hydrate


4Hydrate

CH4 Hydrate - CO


4 Hydrate


4Hydrate

CH4 Hydrate - CO


4 Hydrate


4Hydrate

Well

Tracer … Argument for Heterogeneity?

0

10

20

30

40

50

60

70

80

90


% T

race

r R

eco

very

R114

SF6


7-Mar 04:00 – 13-Mar 23:30


15-Mar 18:52 – 18-Mar 10:40


23-Mar 06:20 – 11-Apr 00:00

Unassisted Flowback

4-Mar 14:00 – 6-Mar 00:00

0

10

20

30

40

50

60

70

80

90


% T

race

r R

eco

very

R114

SF6


7-Mar 04:00 – 13-Mar 23:30


15-Mar 18:52 – 18-Mar 10:40


23-Mar 06:20 – 11-Apr 00:00

Unassisted Flowback

4-Mar 14:00 – 6-Mar 00:00

Heterogeneous Injection / Production

SH = High

SH = Low

SF6

SF6 R114 Inject SF6 / R114

SF6

SF6 R114

Produce

Tem

per

atu

re c

han

gesi

nce

6F

eb2

01

2


100

75

50

25

Rat

e (m

scf/

d)

PerforationInjection started

1700

1300

1500

1600

1400

BH

Pre

ssu

re p

sia)

0.0 0.2 0.4 0.6 0.8 1.0

Saturation (v/v)

CMR Free FluidBound FluidNPORHydrate Saturation

Heterogeneous Injection

Tem

per

atu

re c

han

gesi

nce

6F

eb2

01

2


Tem

per

atu

re c

han

gesi

nce

6F

eb2

01

2

150

100

50Rat

e (m

scf/

d)

1100

700

900

1000

800

BH

Pre

ssu

re p

sia)

600


0.0 0.5 1.0Hydrate Saturation


Tem

per

atu

re c

han

ge si

nce

6F

eb2

01

2

2,240

2,245

2,250

2,255

2,260

2,265

2,270

2,275

0 2 4 6 8

de

pth

(ft

)

Temperature (°C)

T(°C) 6.1hrs

T(°C) 18.7hrs

T(°C) 33.6hrs pre-shutin

T(°C) 61.7hrs end-shutin

T(°C) 100hrs end_of_sim

Production Period #1

Production Simulations Production

− Production phase is modeled by maintaining fixed-state boundary as

aqueous phase at the bottom-hole pressure.

− Still attempting to match sand production and each gas rate (with recovery

factors)

• Demonstrated injection of CO2 mixture into water filled hydrate reservoir – Possibly some injection out-of-zone

• Confirmed mixture / CH4-Hydrate Exchange – CH4 produced above CH4-hydrate stability pressure

– Produced CO2 : N2 ratios altered from injectant value

– Injectivity decline consistent w hydrate exchange

• Low BHP are achievable during depressurization – Icing not observed @ 250 psi BHP

• Heterogeneous injection / production observed (DTS)

• Temperature record consistent w hydrate association / dissociation during injection / production cycles

Tentative Conclusions

39

• Datasets and ConocoPhillips project reports can be downloaded from the NETL website.

– http://www.netl.doe.gov/technologies/oil-gas/FutureSupply/MethaneHydrates/rd-program/ANSWell/co2_ch4exchange.html

– google “ignik sikumi” or see the announcement in the latest Fire in the Ice

• Organizing a problem for the Code Comparison Project on the Ignik Sikumi Results

• DOE has previously facilitated creation of Special Volumes in peer-reviewed journals to consolidate reporting

Going Forward

http://www.netl.doe.gov/technologies/oil-gas/FutureSupply/MethaneHydrates/rd-program/ANSWell/co2_ch4exchange.html





Questions?

Backup Slides – do not print

CPAI - Iġnik Sikumi #1 and PBU L-pad

“E sand:” 31ft hydrate

Sagavanirktok “F Sand:” Ice-filled

Target: Upper C Sand

base permafrost

“D sand:” 49ft hydrate

“C sand:” 67ft hydrate

Iġnik Sikumi #1

Wellbore Construction

Upper Completion

Lower Completion

Tem

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6F

eb2

01

2


Tem

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6F

eb2

01

2

150

100

50Rat

e (m

scf/

d)

1100

700

900

1000

800

BH

Pre

ssu

re p

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600


− Two data files are incorporated into

Teq = f(P,y1,y2) and Peq = f(T,y1,y2)

where T is temperature ( C), P is

pressure (MPa), y1 is CH4 composition

in gas phase and y2 is CO2 composition

in gas phase (yN2 is not independent)

• Two new primary variables for each phase

state and two governing equations are added

for the binary (CO2) and ternary (N2) gases

• Gas-Hydrate (GsH) system was added to

consider the possibility of converting all

available free water to form hydrate with

injected gas

• The phase equilibrium data for a three-component (CH4-CO2-N2) gas hydrate are incorporated

using tri-linear interpolation, where in the code can interpolate data from a table containing

stability pressure, temperature and composition of the hydrate phase

– Based on predictions using our statistical mechanics model that has been validated against

experimental data for 1-, 2-, and 3-component gas mixtures with low error

Prediction of stability pressure for the CH4-CO2 mixed hydrate

system

Ternary Hydrate Modeling

conocophillips test results and data analysis

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