Ula Field Miscible WAG Flood Assessment
- Core & Log Experience from behind a Maturing WAG Front
Simon Thomas, Jon Duncan, Ula Subsurface Team, BP Norway
FORCE Mature Field Life Extension Workshop
Realising 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
ULA
Moderately deep and hot
Depth: 3350-3800mtvdss
Temperature: 150ºC
Volumes:
In-place:
~1 billion barrels
Produced: ~ 420 million barrels
Late field-life initiatives:
Infill drilling Unit 1 horizontal wells
Drilling
Living Q
Production
Ula Field Reservoir
Ula Sandstone
Stratigraphy
Depositional
Environment
Reservoir
Layering
Bioturbated fine-medium grained
sandstone with
nodular calcite cement stringers
Depositional Setting:
Storm dominated shallow marine
shelf
Upper
Jurassic
Ula Sst
Member
(Farsund Fm)
Retrogradational
Shelf
Unit 1
Progradational
Shelf
Unit 2A1-2
Progradational
Shelf
Unit 2A3-6
Aggradational
Shelf
Unit 2B
Progradational
Shelf
Unit 3A-B
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
Wellhead P & T
Monthly well
Injection
testing PLT’s
Gas & Water
Gas Injection Tracers
Water Injection Tracers
ULA
7/12-A-9A Logs & Core
Pilot well for planned
horizontal injector
Drilling
Living Q
Production
A15-A3A WAG Panel
A-15 Oil Producer
me: 7/12-A-15 ID: A15:7/12-A-15 Type: OIL Format: ula_prod_group
(1)40.0
(3)50.0
20.0(2)
50000(4)
36.0
45.0
18.0
45000
32.0
40.0
16.0
40000
28kb/d
28.0
35.0
12.0
30000
10.0
25000
20kb/d
16.0
20.0
8.00
20000
12.0
15.0
6.00
15000
8kb/d
8.00
10.0
4.00
10000
1kb/d
4.00
5.00
0
0
87
88
89
90
(1)Oil Rate,MB/d
1989/1990
A15 & A3A
Start-up
91
A-9A Observation Well
14.0
35000
24.0
30.0
20.0
25.0
1500m
92
93
94
(2)Gas Rate,MMCF/d
VS Time
1994
A-15 Water
Breakthrough
95
96
97
98
2.00
5000
99
(3)Water Rate,MB/d
1998
A-3A WAG
Start-up
00
01
0
0
(4)OilCum_MB,MB
2000
A-15 WAG Oil Arrival
Increased Oil rates & GOR (1-4kb/d)
500m
A-3A WAG Inector
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
Wireline Data
Core Data
complicated logging environment
3-phase fluid mobility system
Deep Invasion
Sample Invasion
3-phase mobility
Coring & Plugging
Gas Presence
Sample Losses
gas injection
Gas-expansion drive
Miscible gas injection process
Mixed Waters
formation & seawater
Oil Properties
Reservoir Cooling
density, formation factor
water injection
Water Properties
density (salinity)
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 drive
Assumed 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
Plugged under oil
at well site
20cm
Dean-Stark Sw Centifuged Water
D2O; Ø & k D2O; Rw
Plugged with
N2 gas in lab
15cm
Dean & Stark Sw
Ø&k
Gas Chromatography
Wrapped & waxed in
laboratory
30cm
CT Scanned
10 Samples selected
Plugged whilst frozen
1vertical & 1 horizontal
Plugged with Plugged under brine
N2 gas in lab
at well site
15cm
Dean & Stark Sw
Ø&k
Gas Chromatography
20cm
Dean & Stark So Centrifuged Oil
Ø & k Gas Chromatography
100m of core; 800plugs & >2000 petrophysical measurements
Reservoir Quality & Layering
Unit 1
1
Unit 2A
2
Unit 2B
3
4
Unit 3A
Reservoir Pressure
3 layer pressure system
2 key pressure barrier/baffles
Pressure
Unit 1A shale barrier (1200psi)
Unit 2A6 baffle (40psi)
Unit 1A Barrier
1200psi
Calcite
Calcite
Depletion
Unit 2A6 Baffle
Calcite
Calcite
Calcite
Unit 1A Barrier
Producing from 1A & 2A with injection into
Units 1A+2A+2B
Oil & Water Saturation Profiles
Offshore & onshore samples
Oil, water & nitrogen cutting
No gas or
fluid loss
Sw range between 40-60%
0-50% sample contamination
Gas or fluid
loss?
So range between 10-70%
1.36 FVF used to covert from stocktank to reservoir conditions
Minor Gas
or fluid
loss?
Core So more robust than Sw
Mobile water may have been lost
In-situ So
Sw from from logs used to check
Preserved Core
SCAL Sample
So after Bumpflood
Log-based Water Saturation
Archie Model:
Resistivity (@25C Ohmm)
0.000
3820.00
0.050
0.100
 a.Rw 
Sw  n  m 
 Ø .Rt 
0.150
0.200
Rmf (Flowline)
Centrifuged Data (<15% Invasion)
Centrifuged Data (15-30% Invasion)
Centrifuged Data (>30% Invasion)
3840.00
MDT Samples (~15% Invasion)
MDT Sample (>15% Invasion)
MDT Sample (60%+ Formate)
Rw profiles determined from:
Rmf Core #2
Rmf Core #3
100 spun-water samples from core
wellhead produced water samples
historical water resistivity data
n-exponent determined from:
3860.00
Measured Depth (m)
2 downhole fluid samples
Rmf Core #1
Adjust?
3880.00
20 oriented electrical plugs
Adjust?
10.0
A9A Clean-up Water
Native Horizontal
9.0
Native Vertical
3900.00
Post Bump Horizontal
Zero
Invasion
Baseline
Post Bump Vertical
8.0
Gas Desaturation Horizontal
Gas Desaturation Vertical
n exponent
7.0
6.0
At So >30% n exponents
are typically ~2.3-2.6
AT So<30% n expoents rise
rapidly tow ards values ~4
5.0
4.0
3920.00
Injection Water
3.0
2.0
A15 Produced Water
Trend is similar for both vertical & horizontal
plugs but exponenets are slightly higher w ithin
vertical samples (see above)
1.0
0.0
0.0
10.0
20.0
30.0
40.0
1-Sw (% )
50.0
60.0
70.0
80.0
Fluid Saturation Uncertainty Reduction
Log Sw reconciles well with core
based CSo & CSw
Core-log comparison highlights:
Intervals of remaining gas
Intervals of lost core water
Gas
Core-log comparison does not
illustrate WAG contact
An independent method was
required to assess gas contact
Gas
Gas
Oil Composition Analysis
Compositional oil analysis key to
understanding WAG performance
Original Oil
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
CSw
CSo
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 Dataset
The upper <1A3 & lower >3B intervals are compositionally unchanged
The 2A3-2A6 & 3A intervals appear to have minor compositional stripping
The 1B-2A2 & 2B1-2B3 intervals have undergone extreme stripping
Sector Modelling
2006:
1987:
A-9A
Permeability
2000:
2001:
2004:
2005:
1998:
1999:
2002:
2003:
Initial
1997:
1989:
1990:
1991:
1993:
1994:
1995:
1996:
Observation
WAG
WAG
OilWater-flood
Water-flood
Saturation
Injection
Layering
Injection
Well
Reservoir
1A
1B
2A
2B
3A
3B
A-15
A-15
OP
OP
A-9A
OBS
A-3A
INJ
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 reservoir
Water-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?