Know Before You GoHow GeoPrediction helps with Production Optimization

and Assessing the Size of the Prize

Steve O’ConnorGlobal Technical Lead, Geopressure

Bryony YoungsReservoir Portfolio Development Manager

2

AIM: an integrated modeling solution to reconcile virgin and production

pressures and account for stress changes during depletion

• Phase 1 – Understand pre-production overpressures within reservoir.

Study the effects of lateral and vertical fluid drainage.

• Phase 2 – Understand the effects of production effects on the

reservoir. Understand the static reservoir pressure modelling to model

effects of field production on the pressure depletion. Production history

matching

• Phase 3 – Dynamic GeoFlow modelling.

Agenda

14/18a-7

21/3a-7

ALDER MACCALLAN

20/6-120/7-1

20/4-1

15/22-3

21/2-4

21/4-1

16/28-8

13/22a-1, 2,

6 and 7

13/30-313/30-3

14/29a-314/29a-3

14/18a-7

21/3a-7

ALDER MACCALLAN

20/6-120/7-1

20/4-1

15/22-3

21/2-4

21/4-1

16/28-8

13/22a-1, 2,

6 and 7

13/30-313/30-3

14/29a-314/29a-3

Modeling Geological vs. Production Pressure

O’Connor and Swarbrick, 2008

1. Collate all relevant virgin fluid or pore pressure data (RFT, DST,

Kick), with particular focus on the Cetaceous data (Upper and

Lower) and Jurassic,

2. Identify fluid gradients (gas, oil and water) and Free-Water

Levels (FWL’s),

3. Compare FWL’s with Hydrocarbon-water contacts from logs,

4. Understand the regional picture, including the geological

evolution of the region using supplied and public seismic,

stratigraphy, lithology and regional data,

5. Use structural data to understand fault patterns and their

likelihood for reservoir compartmentalisation

6. Explaining fluid distributions

e.g. Spill point maps for Fields X, Y, Z etc

7. Construct theoretical pressure model for Kopervik Fairway

4

Geological Time Virgin Pressure State

1. Construct summary of production history in

the area including all satellite fields

2. Does Field X and Field Y production explain

Field Z pressures?

3. Has there had to have been some other

depletion e.g. Jurassic communication?

4. Update spill point maps for Fields X, Y, Z etc

5

1D Production Time Static Modeling

1. Using a Geomechanical flow simulator to capture and

model fluid flow in a reservoir affected by stress

changes during depletion

2. How fast is regional and local pressure waves?

3. Effect of future Field X production on Field Y reservoir

pressure depletion

4. What is the predicted pressure with time at Field Y

(with and without Field X production, before and after

Field Z production)?

6

3D/4D Production Time Dynamic Modeling

Geological Time Virgin Pressure State

7

Any Questions?Thank you

Challenge of variable hydrocarbon-water contacts

STRUCTURAL?

SEDIMENTOLOGICAL?

HYDRAULIC?

RECENT TILTING?PRODUCTION?

• Flat fluid

contacts

• HC outlines

are parallel to

structure and

are within

structure

• Same GOC &

OWC for all

wells

Static vs. Dynamic Systems

• Tilted fluid contacts

• HC outlines are not parallel to structure and may be outside structure

• Different GOC & OWC for each well

Dennis et al, 1998

“Conventional” : Groundwater Flow

LakeTorrens

LakeFrome

LakeEyre

300 km

Alice Springs

Surat

Basin

Cooper

Basin

Eromanga Basin

Brisbane

Direction of groundwater flow

Recharge area

Spring

Concentration of springs

Legend

LakeTorrens

LakeFrome

LakeEyre

300 km

Alice Springs

Surat

Basin

Cooper

Basin

Eromanga Basin

Brisbane

Direction of groundwater flow

Recharge area

Spring

Concentration of springs

Legend

Webster et al., 2007

11

Artesian Water Drive/Support11

• Pressure remains high• GOR remains steady• EOR up to 60% of OIP

“Unconventional” Hydrodynamics

14/18a-7

21/3a-7

ALDER MACCALLAN

20/6-120/7-1

20/4-1

15/22-3

21/2-4

21/4-1

16/28-8

13/22a-1, 2,

6 and 7

13/30-313/30-3

14/29a-314/29a-3

14/18a-7

21/3a-7

ALDER MACCALLAN

20/6-120/7-1

20/4-1

15/22-3

21/2-4

21/4-1

16/28-8

13/22a-1, 2,

6 and 7

13/30-313/30-3

14/29a-314/29a-3

Modeling Geological vs. Production Pressure

100

100

200200

400400

300300

500

500

1000

1000

1500

1500

200200

100100

200200

100100

16

4

25

4

2

2

5Z

5

6

7

12

4Y

2Z

3

4Z

6

21Z

24

3

107 96

4Z

5

6

7 8

113

15/27 15/28 15/29 15/30 16/2716/26 16/29

21/2 21/3 21/4 21/5

16/28

22/1 22/2 22/3 22/4

Control well Britannia Field outline 1000 Overpressure (psi)Britannia Sandstone Limit

Renee Ridge

7km

0o36’E 1o00’E

Kopervik Fairway

100

100

200200

400400

300300

500

500

1000

1000

1500

1500

200200

100100

200200

100100

16

4

25

4

2

2

5Z

5

6

7

12

4Y

2Z

3

4Z

6

21Z

24

3

107 96

4Z

5

6

7 8

113

15/27 15/28 15/29 15/30 16/2716/26 16/29

21/2 21/3 21/4 21/5

16/28

22/1 22/2 22/3 22/4

Control wellControl well Britannia Field outline 1000 Overpressure (psi)1000 Overpressure (psi)Britannia Sandstone Limit

Renee Ridge

7km

0o36’E 1o00’E

Kopervik Fairway

Britannia Field, North Sea

Common Gas

Gradient

West

15/30

East

16/27

16/26

Britannia Field, North Sea

Shale pressures and shoulder effects16

Shale pressures above and below are

higher than the reservoir pressure and

the shales are slowly draining

overpressure into the reservoir resulting

in shoulder effects.

Shale pressures calculated

using data from O’Connor et

al. (2008).

Virgin Pressure Model for Britannia

Sands

17

Tertiary

Laterally-drained sands

Theoretical shale pore pressure

Pressure transition zone in

chalk matched by kicks

Overpressured sands

Variable

amounts of

drainage in

reservoir

Cretaceous

Jurassic/Triassic

(after Ikon Science/IHS/PGS, 2010)

Central Graben

Pressure Study

Distribution Map of

Overpressures

Andrew Formation

Contours of

overpressure in psi

O/P < 50 psi

Hydrodynamic

flow directions

Andrew

Sandstone

limit

O/P > 2000 psi

Close to shale

pressures?

O/P < 50 psi

Ramp - OWC tilt

• Distance: 10km

• Difference in o/p: 200 psi

• dp/dx: 20 psi/km

• Tilt (oil): 180 ft/km (55m)

Case Study#2

Structural Spill Point

Hydrodynamic Spill Point

8220 8210 8200 8190 81708150

8130

8200 8190 8170 8150 8130

8210

8220

N

25 ft / km

Oil

Dry Holes

Shows

Oil & Gas

To close the spill point there

must be a minor readjustment

of the 8210 ft contour in the

saddle point.

500 m

8650 8630

8610 85908800 8770 8740 8710

8800

8770

8740

8680

8650

8830

8610

?

?

?

Field X – Hydrodynamic Oil Pool Outlines

8710

OWC structure ft

structural closure

hydrodynamic closure

seismic amplitude

anomaly

A

A’

A A’

8550

8600

8650

8700

8750

8800

8850

Structural Closure

Hydrodynamic Closure

NW E

Trap structural

spill to the north

Forties Surface

25 ft per km

1km

Seismic Impedance Response

60% increase in

reserve by applying

this approach

Seismic Attributes

Arbroath and Montrose fields. LHS is the structural relief map (red =high). RHS is seismic impedance

(brine-filled = blue, red colour = oil-filled channels. Arrow is the regional flow

defined by overpressure gradient.

Artesian Water Drive/Support23

• Pressure remains high

• GOR remains steady

• EOR up to 60% of OIP

Conclusions

• Different fluid contacts in fields?

• Eliminate other competing explanations (faults, production,

recent tilting, capillarity etc.)

• Affect migration and can increase reserves estimates

• Can enhance water support and recovery

• Provide new exploration models as well as the ability to re-

assess existing acreage without drilling anymore wells

• Best approach is undertake regional studies to map pressure

and reservoir connectivity. Hard to do using only local

acreage.

1D Production Time Static Modeling

25

Viking Graben, North Sea Palaeocene26

NOR 25/1-3

• Map of the Frigg Field area

showing Palaeocene wells

affected by production related

pressure depletion surrounding

the Frigg Field.

• The yellow dashed line shows the

area affected by the Frigg Effect.

• The black dashed line shows the

extent of the Palaeocene basinal

sands.

• The colour shading indicates the

relative magnitude of

overpressure-

• Red is positive overpressure;

• Blue is under-pressure (bars

below hydrostatic).

0.12 bar/m

0.14 bar/m

0.16 bar/m

0.18 bar/m

0.2 bar/m

Hydrostatic

Lithostatic

2600

2500

2400

2300

2200

2100

2000

1900

1800

140 160 180 200 220 240 260 280 300 320

Frigg Main Field, Little Frigg and East Frigg Pressure-Depth PlotPressureView 4 GeoPressure Technology Ltd

De

pth

(m

) T

VD

SS

Pressure (bar) abs.

25/1-1 25/1-2 ST 25/1-3 25/1-5 25/1-7 25/1-8 S 25/2-1

25/2-10 S 25/2-11 25/2-2 25/2-8 25/2-9 30/10-1

Frigg Sandstone Member

Lista Formation

Sele Formation

Ty Formation

Balder and Sele Formations

Overpressure date vs. production

date

28

Ove

rpre

ssu

re

Year

A B C D E F

Field X came

online

Simplistic approach but

doesn’t take into account

distance

Multivariate linear modelling

• Amount of pressure depletion depends on both time since production began

and distance from producing field.

• Not possible to create a model only using one or the other. Combining the

two variants as a ratio and plotting them against pressure depletion will give

a model to allow prediction of blind tests.

• A ratio of distance/time will be used.

• Distance in km from producing field / time in days since production of field

began.

• Typical flow simulators do not allow for stress changes in the reservoir and

overburden

29

Results of using a ratio of Time/Distance

30

100 psi

1 psi

De

ple

tio

np

si

1100.1

Distance (km)/Time (days)

Field X wells

Blind Test Wells

Real Tested Values

A resulting trend line will generate

an equation which can be used to

predict the blind test well depletion

values. A lower ratio will result in a

larger depletion value. The ratio

value will decrease with time but

increase with distance from the

producing field.

As the time since the beginning of production

increases and more is produced from the field, the

pressure depletion is expected to increase.

As the distance from the producing field increases,

the amount of pressure depletion decreases

rapidly close to the field but slowly much

further from the field.

Production Effects

Assumptions in this modelling are:

• 1D model, necessitating homogenous

pressure front in the 1D model. No radial

flow near the pressure sink

• Homogenous properties (porosity,

permeability, viscosity and compressibility)

• Fixed pressure in the pressure sink at the

centre of the model that is turned on at

time=0

Validity of pressure depletion models

• To test the validity of the theory behind the schematic time/depth plots we

create a theoretical 1-D fluid flow model. 1-D fluid flow in porous media can

be modelled using the following partial differential equation (Smalley and

Muggeridge, 2010):

• Typical flow simulators do not allow for stress changes in the reservoir and

overburden. These changes affect fluid flow, compaction, permeability,

drive etc

Dynamic Geomechanics

Understand multiple reservoir systems

Reservoirs can be connected geomechanically even though they are isolated from a fluid standpoint

Geomechanics and Production Optimization

Is there a risk of seal breach during injection?

Will reservoir compaction have an effect on production?

What is the maximum drawdown before sanding occurs?

Is a time-lapse seismic study feasible?

If so, what is the optimal interval?

Geomechanical flow simulation

Geomechanics simulationSolve for stress state and rock deformation.

Flow simulationSolve for fluid saturations and pressure distribution

Benefits• Understand how the stress state (and potential for failure) evolves with production• Understand how geomechanical behaviour effects fluid flow

Governing equations

Mechanics:

Flow:

Darcy flowPorosity change

Stress tensor

𝛻∅ ∙𝜕𝒖

𝜕𝑡+ 𝐀 ∶ 𝒆

𝜕𝒖

𝜕𝑡+ 𝛽

𝜕𝑝

𝜕𝑡+ ∅𝑝 − 𝛻 ∙ 𝜆 𝛻𝑝 −𝑯 = 𝑞

𝛻 ∙ 𝐂 ∶ 𝒆 𝒖 − 𝜀𝑝 −𝐀𝑝 = 0

Multi-scale simulation

Well scale Reservoir scale Basin scale

Benefits• Appropriate resolution at each scale• Understand connections and interactions between processes at different scales

Workflow

Build input model

Stress determination

Model calibration

Geomechanicalapplications

Every step in the workflow needs to be good to ensure a

successful study

Build input model

Stress determination

Model calibration

Geomechanicalapplications

Rock & fluid

properties

Initial pressure

Initial stress field

Run

simulator

Output

Build input model

Stress determination

Model calibration

Geomechanicalapplications

Fluid pressure

Fluid saturations

Solid displacements

Mechanical stress tensor

Well production data

Fluid velocities

Effective stress

Change in porosity

Build input model

Stress determination

Model calibration

Geomechanicalapplications

History matching

(well production data)

4D seismic

Surface displacement data

Observed data used to constrain uncertain input parameters

Calibrate

1D well scale

models

3D well, reservoir

and basin scale

models

Geomechanical

Flow Simulation

Wellbore centric

analytic models

Build input model

Stress determination

Model calibration

Geomechanicalapplications

Calibrate

Existing well

information

Image logs,

drilling reports

Build input model

Stress determination

Model calibration

Geomechanicalapplications

Caprock integrity studies

Optimize hydraulic fractures Maintaining wellbore stability

Avoiding surface subsidence

Reservoir compaction effects on production

Does reservoir compaction increase production via compaction drive?

Or does it decrease production as a result of reduced permeability?

0

5

10

15

20

25

30

35

40

45

0 1 2 3 4 5 6

We

ll p

ress

ure

(M

Pa

)

Time (years)

With full mechanics

Without full mechanics

Predict fault reactivation

σ1

σ3

β

σn

t

σ1

β

𝜏𝑓𝑎𝑖𝑙 > 𝑆0 + 𝜇 𝜎𝑛

With:S0 Cohesionm friction coefficient

Shear failure criterion:Fault slip initiates if shear failure texceeds a critical stress

Faultplane

Normal to fault plane

Determine maximum injection pressures

Friction coefficient m=0.4 Friction coefficient m=0.5 Friction coefficient m=0.6

Additional pressure required above initial conditions for fault re-activation to occur

Reservoir

1000psi = 6.89MPa

Summary

• Naturally hydrodynamic aquifers enhance production rates, provide water support and aid pressure decline. Out of closure potential.

• Understanding the dynamic geomechanical behaviour of your reservoir is a key ingredient in production optimization

• Geomechanical flow simulation enables us to predict how both the stress field and fluid pressure evolve with production and determine the answers to questions such as:

• Will depleting reservoir X effect reservoir Y?

• What is the maximum injection pressure without compromising the cap rock?

• Will reservoir compaction have a positive or negative impact on production?

• What is the maximum drawdown before sanding occurs?