© 2017 Chevron Company Confidential. All rights reserved.

Baker Hughes ©

NAPE May 2017 Technical Meeting

Presenter: A.D. Oyegwa

Logging-While-Drilling (LWD) Pressure Data Acquisition, Interpretation & Challenges:

Okan Field Example

Presentation Outline

• Field Introduction

• Background Information

• Acquisition Challenges

• Experiment

• Results

• Lessons Learned

• Recommendations

Dat

aIn

form

atio

nK

no

wle

dge

“Known knowns”

“Known unknowns”

“Unknown unknowns”

……Donald Rumsfeld

Okan Field Location and Geology

Elongate NW-SE trending anticline,

bound on the NE & SW by major

structure-building faults

Structurally complex with crestal

collapse faults, variably synthetic and

antithetic in throw.

Three major fault blocks: Okan Main,

North & Block E

Key reservoir management

uncertainties affecting recovery are

compartmentalization and variations

in fluid contacts

• 1st NNPC/Chevron JV Offshore Asset

• OML 90, Western area of the Niger Delta

• 25’ water depth

• 18 km offshore Escravos, Nigeria

• Over 50 years of production

• Over 130 wells drilled to date

• Multiple stacked reservoirs

A

A’

A A’

Background Information

Reservoir Map

WL-4

WL-3

WL-2 WL-1

• Pressure data acquired in 3 wells

• ObjectivesFluid ContactsReservoir communicationFluid Typing

• Acquisition success rate: ~86%

• A number of reservoirs with interesting information

LWD Tool & Acquisition Operations

Baker Hughes ©

• Data acquired in 6” and 8-1/2” hole sizes

• Data monitored and qc’ed at office location

Acquisition Challenges

• Telemetry issues related to mud pumps and Bi-

directional Communication and Power Module (BCPM)

• Plugged probes/tight tests

• High Rate of Penetration (ROP) over reservoir sections

• Depleted reservoirs

• Time constraints for elaborate real time interpretation

Acquisition Duration and Success Rates

• Variable experience in the acquisition process

• For the 3 wells, the acquisition time ranges from 0.58 days to ~ 9 days

• Well-1 duration was due to tool failures and number of pre-test stations

• Success rates:• Well 1: 87%• Well 3: 81%• Well 4: 90%

0

1

2

3

4

5

6

7

8

9

Well-1 Well-3 Well-4

9

0.58 0.75

Acquisition Days

69

20 20

60

16 18

WELL-1 WELL-3 WELL-4

Pre-tests vs. Good Tests

Good Tests

Pre-tests

Experiment

Fluid Typing vis-à-vis Number of Pressure

Points

0.06 psi/ft

0.35 psi/ft

1

2

3

4

5

1

23

4

GR

CALI RESD

NPHI_SS

RHOB

GR

CALI RESD

NPHI_SS

RHOB

FPRESS

FPRESS

Reservoir Top

RSVR

Points Psi/ft Fluid

All 0.35 Oil

1&2 0.38 Oil

2&3 0.32 Oil

3&4 0.32 Oil

1&4 0.35 Oil

2&4 0.32 Oil

Example 2

Points Psi/ft Fluid

All 0.06 Gas

1&2 0.06 Gas

2&3 0.06 Gas

3&4 0.06 Gas

4&5 0.05 Gas

1&5 0.06 Gas

Example 1

Reservoir BaseWel

l-1

Reservoir Top

Reservoir Base

Well-1

• Accuracy of fluid gradients are influenced by the number of points

• Two (2) good points are sufficient to differentiate between gas and liquid

Results

Results

• Gas effects

• Compartmentalization

• Pressure regimes and variable fluid contacts

• Fluid typing

• Facies identification 0.06psi/ft

0.30psi/ft

0.43psi/ft

Residual Gas

GR

CALI RESD

NPHI_SS

RHOB FPRESS

0.46 psi/ft

GR

CALI RESD

NPHI_SS

RHOB FPRESS

0.34 psi/ft

OGOC=-5622’ss

OOWC=-5672’ss

Reservoir Top

Contact?

Reservoir Base

• Resistivity log suggests hydrocarbon water contact within sand

• Porosity logs suggests very light hydrocarbon beyond that suggested by resistivity

• Pressure profile confirms current fluid type and fluid contact depths

• Logs show imprints of reservoir production history

Vertical Compartmentalization

11psi

0.07 psi/ft

0.07 psi/ft

GR

CALI RESD

NPHI_SS

RHOB FPRESS

RSVRReservoir Base

Reservoir Top

Reservoir Base

• Based on scanty pressure data and well logs correlation, reservoirs A and B were considered connected

• Recent pressure data now shows that the sands are separate.

A

B

Variable Fluid Contact

8040

8045

8050

8055

8060

8065

8070

8075

8080

2802 2804 2806 2808 2810 2812

TVD

SS(f

t)

Pressure(psi)

Okan -139H

Okan -141H

Linear (Okan -139H)

Linear (Okan -141H)6 psi

Well-3

Well-149H

Well-151H

Well-149H

Well-151H

• Pressure difference likely responsible for observed fluid contact difference across faults

Well-1

Well-3

Well-1

C Reservoir Top Structure Map

New Fluid Type Interpretation

0.29 psi/ft

GR

CALI RESD

NPHI_SS

RHOB FPRESS

~13ft

Reservoir Base

Reservoir

Reservoir Top

B

C

• Both lobes previously considered gas filled

• Two-point pressure gradient suggests oil!

• Fluid sampling would have helped confirm gradient

• Cased hole log validated the oil interpretation.

Puzzling Gradient

0.43 psi/ft

GR

CALIRESD

NPHI_SS

RHOB FPRESS

• Inconsistency between logs and pressure data

• About 40% pressure depletion from initial

• Cased hole log and production data supports hydrocarbon presence.

Reservoir

Reservoir Top

We

ll-3

Complementary Logs Signatures and Pressure Profiles

0.37 psi/ft

0.39 psi/ft

0.22 psi/ft

0.09 psi/ft

GR

CALI RESD

NPHI_SS

RHOB FPRESS

INCLINATION

• Different pressure compartments in D interval

• Distinct gamma and porosity logs signatures

Reservoir

Reservoir Top

D

GRVSHCALI

Sand Facies Discovery A’A

Well-3

Well-3

Well-9

AA’

GRVSHCALI RESD

NPHI_SSRHOB FPRESS RESD

NPHI_SSRHOB FPRESS

1

23

~5ft

Well-9

Well Facies Avg. VSH Avg. PHIT Avg. SWT Avg. PERM

142H 1 32.8 26.4 26.3 451

142H 2 16 27.8 15.4 783

142H 3 46.4 24.7 29.5 126

Well-3

Well-3

Well-3

Well Facies Avg. VSH Avg. PHIT Avg. SWT Avg. PERM

98 1 20.4 30.4 19.9 1425

98 2

98 3 38.8 28.4 32.4 840

Well-9

Well- 9

Well- 9

• Correlation with offset well confirms facies in well 3 is not laterally extensive.

Lessons Learned

1. Basic log data are not always conclusive on reservoir fluid types, especially in mature fields

2. Pressure data provides very useful information that may challenge current assumptions and thus help to improve our understanding of reservoirs

3. Optimum mud flow rate is very critical to LWD tool acquisition success, especially in slim holes

4. Multifunctional collaboration is essential to the success of any pressure acquisition program.

Recommendations

1. Downhole Fluid Analysis/sampling should be considered, especially for fluid typing in thin reservoirs or in horizontal hole sections

2. Mud pumps should be in good working condition (and calibrated) to ensure optimum flow rate for LWD operation

3. Tool flushing and face re-orienting should be done often, especially after every “tight” test

4. There should be controlled drilling over reservoir sections of interest.

Acknowledgements

Nigeria National Petroleum Corporation for approving the presentation

Chevron Nigeria for permission to present these findings.