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Company Background
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Locations
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What is a polymer gel?
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99% Water + Polymer + Cross-linker = Immobile Gel
• used for profile modification and in-depth
conformance control at injection wells • used to shut-off excessive water at producing wells in
natural waterdrive reservoirs and waterfloods
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Factors that determine recovery efficiency
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Vertical Sweep Efficiency: the volume of rock that is contacted in the vertical plane Areal Sweep Efficiency: the volume of rock that is contacted in the horizontal plane Displacement Efficiency: the volume of mobile oil displaced from the contacted rock
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Injector Producer
Injected fluid
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By-passed oil (low K)
Injector Producer
Swept layer (high K)
By-passed oil (low K)
Injection “cycling”
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Areal Sweep Ideal Case (Radial Flow)
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Realty
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By-passed oil
By-passed oil
By-passed oil
By-passed oil
By-passed oil
By-passed oil
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Realty
Injector Producer
gel
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Injector Producer
gel
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Injector Producer
gel
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Injection water is diverted to other areas of the reservoir and sweeps by-passed oil to the producing wells
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Injection drive fluid is diverted to other areas of the reservoir and sweeps by-passed oil to the producing wells
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Data needed to assess pro-mod treatment
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Base map showing producer & injector well locations
Geological maps (isopach, structure, HCPV, etc.)
Reservoir rock & fluid properties
Geological description
Core reports
Historical tabular oil & water production data by well
Historical tabular injection rate & pressure data by well
Injection profile logs
Openhole logs
Wellbore diagrams
Well histories
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Sizing the job
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By-passed oil
By-passed oil
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WOR Method
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Fracture Breakthrough (smaller Swept PV)
1
10
100
1000
10000
1.00
10.00
100.00
1000.00
0
20
,00
0
40
,00
0
60
,00
0
80
,00
0
10
0,0
00
12
0,0
00
14
0,0
00
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0,0
00
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0,0
00
20
0,0
00
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0,0
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0,0
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00
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0,0
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0,0
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0,0
00
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0,0
00
BO
PD
& B
WP
D
WO
R
Cum. Oil Bbls.
Cumulative Oil vs. WOR
WOR Begin Water Injection BOPD BWPD
Swept MPV 140,000 Bbls
Oil Response Water Breakthrough
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Matrix Breakthrough (larger swept PV)
Swept MPV 140,000 bbls
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140,000 bbls
assign proportionate share to surrounding injectors
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Volumetric Method
Example Injector-centered Pattern
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Estimate “serviceable” area
Area = 10 acres
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Estimate thief height in “serviceable” area from injection profile log 10’
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High K Swept Layer
Low K By-passed Layer
Low K By-passed Layer
10’ 70’
100% of Flow Capacity into only 14.3% of Pay
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Height = 10’ Porosity = 20%
Calculate Moveable Pore Volume (“MPV”) of high K layer (thief) over the “serviceable” area
More difficult to estimate swept MPV of fractures using Volumetric Method (geometry unknown)
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How much of the MPV do we want to fill with polymer? More if
Kvh is high, and less if Kvh is low.
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General treatment procedure 1) No well modification required to accommodate job 2) Rig up polymer blending and injection unit to water source and
wellhead 3) Inject treatment (“bullhead”-style) with entire producing
interval exposed to polymer 4) Polymer injected as a liquid with delayed gelation allows for
deep placement of large volumes 5) Polymer will follow the path of least resistance (i.e. high
permeability swept rock) 6) Over-displace polymer solution from wellbore 7) SI well for several days to allow gel time to form 8) Reactivate well
36’
Polymer Technology for Water Shut-off • Profile Modification • Mobility Control
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6.2’
Mobile Polymer Unit
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0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
0
50
0,00
0
1,0
00,
000
1,5
00,
000
2,0
00,
000
2,5
00,
000
3,0
00,
000
3,5
00,
000
4,0
00,
000
4,5
00,
000
5,0
00,
000
5,5
00,
000
6,0
00,
000
6,5
00,
000
7,0
00,
000
Cu
mu
lati
ve p
si-d
ays
Cumulative Injection Bbls.
Typical Hall Plot
Hall Plot Polymer Gel Treatment
First indicator of change is decreased injectivity at treated well (higher injection pressure is required to inject water into lower permeability rock)
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51,000 bbls
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Phosphoria Injection Pattern
30 acres
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Portwood (EOGA), Lackey (Citation), & Abel (Citation)
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Data needed to assess WSO treatment
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Reservoir rock & fluid properties
Geological description (how water gets to the wellbore)
Core reports
Historical tabular oil & water production data
Static SI and producing fluid level
Openhole logs
Wellbore diagram
Well history
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Gel polymer for WSO at producing wells
1
10
100
1,000
10,000
1 3 5 7 9
11
13
15
17
19
21
23
25
27
29
31
33
35
37
39
41
43
45
BO
PD
& B
WP
D
Time
BOPD BWPD
flat water and declining oil
indicate max pump capacity,
and increasing fluid level
Typical High Water-cut Well
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Sizing the job
Distance Matters! deeper placement = more oil
(but how deep?)
Productivity Index (PI) estimates maximum flow capacity at zero pressure gradient
→ High PI = large flow features = large PV = large gel volume → Low PI = small flow features = small PV = small gel volume
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General treatment procedure
1) Pull production equipment 2) Install tubing & packer above top perforation or openhole section 3) Aggressively acidize well 4) Rig up polymer blending and injection unit to water source and
wellhead 5) Inject treatment (“bullhead”-style) with entire producing interval
exposed to polymer 6) Polymer will follow the path of least resistance (i.e. offending
water flow conduits) 7) Over-displace polymer solution from wellbore 8) SI well for several days to allow gel time to form 9) Reactivate well
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Whisonant (Marathon) & Hall (Marathon)
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Old Well #1
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Old Well #2
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57
New Well
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Phosphoria Formation –
Candidate Selection, CRM, Gel
Polymer Treatment Model
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Components of the Methodology
Step I – Production Diagnostics, Data Analysis, Data
Preparation, Sector Selection Production Diagnostics, WOR vs Cumulative Production, CRM, Core
Analysis, Upscale Simulation Layers
Step II – Estimation of Depth and Volume of
Treatment Apparent Viscosity using Viscoelastic Model, Couple with Fluid Flow
Model, Generate Depth and Volume of Gel Polymer Injected
Step III – Apply Gel Polymer Footprint in the
Numerical Sector Model and Compare Effects of
Continued Waterflood OR Fracture Modeling Calibrate Numerical Model to Current Watercut conditions, Upload
Gel polymer Footprint, Run two Cases to Compare (a) Continued
Waterflood and (b) Waterflood after Treatment
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Phosphoria Formation – Gel
Polymer Treatment (Fractured
Producer)
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Maximum Oil Rate
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Zero Time Cumulative Oil
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Zero Time Cumulative Water
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Production Diagnostics – 5713
coning
channeling
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Aquifer
Oil Zone
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History Match – 5713 fracture distribution – run 1
Ratio = 1
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History Match – 5713 watercut – run 1
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History Match – 5713 watercut – run 2
Ratio = 1.5
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History Match – 5713 watercut – run final
Ratio = 6
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Water (Aquifer) www.getmoreoil.com
Post Treatment Fractures Shutoff
Ratio = 6 Fractures shut off
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Treatment Volume 5713
3,000 bbls
10,000 bbls
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Effective Fracture Shutoff – 5713
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Phosphoria WSO – Actual Treatment
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Phosphoria WSO – Model Comparison
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Phosphoria WSO – Model Fracture Shutoff
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Phosphoria – Gel Polymer
Treatment (Injector)
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CRM Results – Gains Matrix - Phosphoria
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CRM Results – Gains Matrix - Phosphoria
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Fraction of Water Injected
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Total Liquid Produced
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(Produced – Injected)
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Step I – Data Preparation -- Layered Reservoir Properties
Oil viscosity ~ 200 cp
Mobility Ratio ~ 133
Kv/kh ~ 0.1
Effects of viscous fingering
and permeability contrast
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Step II – Estimate Depth and Volume of Invasion
Delshad, M.. et. al 2008; Stavland, A et . al 2010
1
2max
21
20 2
1
exp11
n
effr
n
effwpwapp
p
e
w
t
w
p
p
t
r
r
h
q
r
r
h
qp ln
007081.0ln
007081.0
Apparent viscosity calculation for different flow regimes (shear thinning, shear thickening, Newtonian)
Pressure Drop calculation in a layered system
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Step II -- Depth and Volume of Invasion
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Step III – Comparison of Performance
Case I – continued waterflood
Case II – waterflood post treatment
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Step III -- Comparison of Oil Rates
IBO ~ 50 M STB in 10 years
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Step III -- Comparison of Watercut
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