Ula Field Miscible WAG Flood Assessment

- Core & Log Experience from behind a Maturing WAG FrontSimon Thomas, Jon Duncan, Ula Subsurface Team, BP Norway

FORCE Mature Field Life Extension WorkshopRealising value from existing data, data acquisition planning and modelling

2nd October 2007

Ula Field Introduction

Discovered: 1976; First Oil: 1986

Water depth 67m

100m thick shallow marine reservoir

Moderately deep and hotDepth: 3350-3800mtvdss

Temperature: 150ºC

Volumes:In-place: ~1 billion barrels

Produced: ~ 420 million barrels

Late field-life initiatives:

Infill drilling Unit 1 horizontal wells

WAG Injection EOR

Living QDrilling

Production

ULA

Ula Field Reservoir

RetrogradationalShelf

ProgradationalShelf

ProgradationalShelf

Aggradational Shelf

ProgradationalShelf

Unit 1

Unit 2A1-2

Unit 2A3-6

Unit 2B

Unit 3A-B

DepositionalEnvironment

ReservoirLayering

UpperJurassicUla SstMember

(Farsund Fm)

Stratigraphy

Ula Sandstone Bioturbated fine-medium grained

sandstone withnodular calcite cement stringers

Depositional Setting:Storm dominated shallow marine

shelf

Ula Field Producing Wells

8 Crestal Oil Producers

3xUnit 2-3 WAG

5xUnit 1 horizontal

7 Flank Injectors

3xUnit2-3 water injectors

4xUnit 2-3 WAG injectors

Ula Field WAG Surveillence

Monthly well testing

Living QDrilling

Production

ULA

Wellhead P & T

Injection PLT’sGas & Water

Gas Injection TracersWater Injection Tracers

7/12-A-9A Logs & CorePilot well for planned horizontal injector

A15-A3A WAG Panel

87 88 89 90 91 92 93 94 95 96 97 98 99 00 01

0

4.00

8.00

12.0

16.0

20.0

24.0

28.0

32.0

36.0

(1)40.0

0

2.00

4.00

6.00

8.00

10.0

12.0

14.0

16.0

18.0

20.0(2)

0

5.00

10.0

15.0

20.0

25.0

30.0

35.0

40.0

45.0

(3)50.0

0

5000

10000

15000

20000

25000

30000

35000

40000

45000

50000(4)

(1)Oil Rate,MB/d (2)Gas Rate,MMCF/d (3)Water Rate,MB/d (4)OilCum_MB,MB VS Time

Name: 7/12-A-15 ID: A15:7/12-A-15 Type: OIL Format: ula_prod_group

A-3A WAG Inector

A-9A Observation Well

A-15 Oil Producer

2000A-15 WAG Oil ArrivalIncreased Oil rates & GOR (1-4kb/d)

500m

1500m

1994A-15 Water

Breakthrough

8kb/d

1998A-3A WAG

Start-up

1kb/d

1989/1990A15 & A3A

Start-up

20kb/d

28kb/d

Ula WAG Observation Well Objectives

Is current Ula Field WAG working?

Halted production decline & increasing GOR support pilot success

Where and how big is the ultimate WAG prize?

Recent SCAL data indicates high potential prize: Sorm 5% (Sorw 30%) & Sgt 35%

How efficient is the WAG process?

Which intervals of the reservoir are being contacted by the WAG injection?

Fundamentally: Sorw, Sorm, Sg, kh & kv

What do we do next?

How do we optimally design the future WAG injector/producer drilling program to access to remaining oil in Ula?

Data Acquisition Challenges

Core Data

3-phase fluid mobility system

Miscible gas injection process

Wireline Data

complicated logging environment

Sample InvasionCoring & Plugging

Sample LossesGas-expansion drive

Oil Propertiesdensity, formation factor

Water Propertiesdensity (salinity)

Deep Invasion3-phase mobility

Gas Presencegas injection

Mixed Watersformation & seawater

Reservoir Coolingwater injection

COST!!– Justified by the large size (>100mmbbl) but large uncertainty of the potential WAG prize

Ula A9A Wireline Logging Program

Baker Atlas Wireline Logging Contract

Gamma-ray, density, neutron, sonic & laterolog resistivity

57 Pressures & 7 fluid samples

Nuclear Magentic Resonance – Gas & Non-RT based saturation profiles

Openhole Pulsed Neutron – Gas saturation profiles

Carbon/Oxygen – Non RT based saturation profiles

Electrical resistivity images – Small-scale heterogeneities

Directional induction resistivity – fluid related anisotropy

Ula A9A Coring Program

Low invasion, high ROP coring system

Low invasion water-based (NaCOOH) mud with Deuterium tracer

Assumed that the dominant mobile fluid phase would be water

Slow, staged tripping to avoid gas driveAssumed that both free gas and high GOR oil would be present

Ula A9A Core Analysis & Program

Core plugged offshore under oil & brine and onshore under nitrogen

Multiple measurements including:Porosity, vertical, horizontal permeability & probe permeametry

Dean & Stark Water & oil saturations

Spun Water Resistivities - for calibrating Archie water saturation model

Gas Chromatography Analysis – for determining degree of WAG contact

Plug Sampling Program

30cm

Wrapped & waxed in laboratory

CT Scanned10 Samples selectedPlugged whilst frozen

1vertical & 1 horizontal

20cm

Dean-Stark SwD2O; Ø & k

Centifuged WaterD2O; Rw

Plugged under oilat well site

20cm

Dean & Stark SoØ & k

Centrifuged OilGas Chromatography

Plugged under brineat well site

15cm 15cm

Dean & Stark SwØ & k

Gas Chromatography

Plugged with N2gas in lab

Plugged with N2 gas in lab

Dean & Stark SwØ & k

Gas Chromatography

100m of core; 800plugs & >2000 petrophysical measurements

Reservoir Quality & Layering

Unit 1

Unit 2A

Unit 2B

Unit 3A

1

2

3

4

Reservoir Pressure

3 layer pressure system

2 key pressure barrier/bafflesUnit 1A shale barrier (1200psi)

Unit 2A6 baffle (40psi)

Producing from 1A & 2A with injection into Units 1A+2A+2B

Unit 1A Barrier

Unit 2A6 Baffle

Pressure

Depletion

1200psi

Calcite

Calcite

Calcite

Calcite

Calcite

Unit 1A Barrier

Oil & Water Saturation Profiles

Offshore & onshore samples

Oil, water & nitrogen cutting

Sw range between 40-60%

0-50% sample contamination

So range between 10-70%

1.36 FVF used to covert from stock-tank to reservoir conditions

Core So more robust than Sw

Mobile water may have been lost

Sw from from logs used to check

In-situ So

Gas or fluid loss?

No gas or fluid loss

Preserved Core SCAL Sample So after Bump-

flood

Minor Gas or fluid loss?

Log-based Water Saturation

Archie Model:

Rw profiles determined from: 100 spun-water samples from core

2 downhole fluid samples

wellhead produced water samples

historical water resistivity data

n-exponent determined from:20 oriented electrical plugs

We trust:Spun data with <15% contaminationMDT data with ~15% contaminationHigh permeability intervals have become contaminatedand comprise dominantly of mud filtrateResistivity values fall well below levels for A3A injected & A15 produced waterMDT and clean-up data are consistent and in agreement with production and injection values

3820.00

3840.00

3860.00

3880.00

3900.00

3920.00

0.000 0.050 0.100 0.150 0.200

Resistivity (@25C Ohmm)

Mea

sure

d D

epth

(m

)

Centrifuged Data (<15% Invasion)

Centrifuged Data (15-30% Invasion)

Centrifuged Data (>30% Invasion)

MDT Samples (~15% Invasion)

MDT Sample (>15% Invasion)

MDT Sample (60%+ Formate)

Rmf Core #1

Rmf Core #2

Rmf Core #3

Injection Water

A15 Produced Water

A9A

Clean-up W

ater

Rmf (Flowline)

ZeroInvasionBaseline

Adjust?

Adjust?

nm RtØ

RwaSw

.

.

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0

1-Sw (%)

n e

xp

on

en

t

Native Horizontal

Native Vertical

Post Bump Horizontal

Post Bump Vertical

Gas Desaturation Horizontal

Gas Desaturation Vertical

At So >30% n exponents are typically ~2.3-2.6AT So<30% n expoents rise rapidly tow ards values ~4

Trend is similar for both vertical & horizontal plugs but exponenets are slightly higher w ithin vertical samples (see above)

Fluid Saturation Uncertainty Reduction

Gas

Gas

Gas

Log Sw reconciles well with core based CSo & CSw

Core-log comparison highlights:

Intervals of remaining gas

Intervals of lost core water

Core-log comparison does not illustrate WAG contact

An independent method was required to assess gas contact

Original Oil

Oil Composition Analysis

Compositional oil analysis key to understanding WAG performance

Toluene extracted oil samples

Gas chromatography analysis

C50/Cn ratio analysis

Identified compositional profiles

Reduction in lighter end components unambiguously identifies WAG contact

’Stripped’ Oil

Oil Composition Analysis Results

Raw GC Dataset prior to normalisation.Note the correspondence between the low remaining oil saturations combined with gas indications and the reduced low carbon components.

Normalised GC DatasetThe upper <1A3 & lower >3B intervals are compositionally unchangedThe 2A3-2A6 & 3A intervals appear to have minor compositional strippingThe 1B-2A2 & 2B1-2B3 intervals have undergone extreme stripping

CSw

CSo

1A1B

2A

2B

3A

3B

A-15OP

A-3AINJ

A-9AOBS

Reservoir LayeringPermeability Layering1987: Initial Oil Saturation1989: Water-flood1990: Water-flood1991: Water-flood1993: Water-flood1994: Water-flood1995: Water-flood1996: Water-flood1997: Water-flood1998: WAG Injection1999: WAG Injection2000: WAG Injection2001: WAG Injection2002: WAG Injection2003: WAG Injection2004: WAG Injection2005: WAG Injection2006: A-9A Observation Well

Sector Modelling

1A1B

2A

2B

3A

3B

A-15OP

A-3AINJ

A-9AOBS

Summary

Innovative integration of core & log data has been key to reducing saturation profile uncertainty

fluid property profiles (resistivity & composition) are key descriptors

Gas-flood has contacted only 40% of the reservoir within 2 layers

Sorm’s reach down to 10-20%, consistent with SCAL Sorm’s

Gas-flood by-passed intervals make up 60% of the reservoirWater-flood sweep has been variably effective

Target intervals for future WAG confirmed with Sorw’s of 30-75%

Acknowledgements

BP Exploration & Production Technical Group (Sunbury, UK)

ICCS (UK) & Reslab (Norway) Core Analysis Laboratories

Baker Hughes (Wireline & Coring Operations)

Andrew Spence (Independent Core Analysis Consultant)

Questions or Comments?