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The Science and a Case The Science and a Case History of COHistory of CO22
Conformance Conformance Through the UseThrough the Use
of of
Complex Nano FluidsComplex Nano Fluids
Glenn Penny, Ph.D., Director of TechnologyGlenn Penny, Ph.D., Director of TechnologyTom Pursley, IOR Technical ManagerTom Pursley, IOR Technical Manager
2
••
Conformance Challenge:Conformance Challenge:––
Divert CO2 from High Perm Streaks or swept areas of reservoir Divert CO2 from High Perm Streaks or swept areas of reservoir into Unswept Reservoir;into Unswept Reservoir;
––
Idea is to Increase CO2 Sweep Efficiency or Utilization;Idea is to Increase CO2 Sweep Efficiency or Utilization;––
Increase Oil Production;Increase Oil Production;
Candidate patterns are generally selected according to the following criteria.1. Unusually high gas rate and high gas/oil ratio (GOR),2. Low wellhead pressure in the contributing injection well.3. Rapid interwell transit.4. Identifiable, high-permeability “thief”
zone.
Previous polymer methods to achieve CO2 conformance and mobility control•
Preformed Polymer gel (PPG)–
Good for very high perm thief zones (>3 Darcies)
•
Crosslinked
Gel Injection–
10 to 15kgal 3-5000 ppm
PAM + Cr–
Incremental oil costs 5 to $7/bbl depending on field (about 150 jobs performed in W TX 15 to 20% with CO2
•
Gelled foam injection (Freidman SPE 38837)–
CO2 replaces 60% of the volume–
Cost of gel conformance decreased 50% to around $3/bbl but only lasted 4 months in a limited field trial
3
Previous CO2 Conformance with Surfactants
•
Surfactant injection with the CO2 (Sanders, Linroth
SPE 160016 –
Observed that more CO2 was injected into additional deeper zones but only while surfactant was being pumped
•
SAG Surfactant Alternating gas (Hoefner
SPE 27787)–
some profiles improved while many were not,–
the injection profile modification was highly transient
•
CO2 foam to increase CO2 viscosity to match reservoir oil to achieve favorable mobility ratio (Stephenson SPERE Aug 93)–
An extended field test showed the foam bank propagated only a few meters from the wellbore
4
New Technique
••
Strategy:Strategy:––
Develop a low adsorbing high salt and oil tolerant Develop a low adsorbing high salt and oil tolerant foamerfoamer
that that works with CO2 works with CO2
Complex Complex nanofluidnanofluid
((CnFCnF®®
+ + FoamerFoamer))––
Inject Inject CnFCnF
+ + FoamerFoamer
in water phase and follow with CO2 to divertin water phase and follow with CO2 to divert––
Investigate in a CO2 core flood using a Dual Core Flood ApparatuInvestigate in a CO2 core flood using a Dual Core Flood Apparatus s with 50 with 50 mDmD
and 250 and 250 mDmD
Core Plugs.Core Plugs.
••
Action:Action:––
Inject a Complex Inject a Complex NanoNano
Fluid (Fluid (CnFCnF®®) Product Containing a Low ) Product Containing a Low Adsorbing salt tolerant Adsorbing salt tolerant FoamerFoamer
into candidate injection well into candidate injection well followed by CO2 to Create Conformance. followed by CO2 to Create Conformance.
––
Follow production of CO2 and oil before and after.Follow production of CO2 and oil before and after.
5
One Method to Mitigate Adsorption is to Formulate in a One Method to Mitigate Adsorption is to Formulate in a Complex Complex NanoFluidNanoFluid
((CnFCnF): Oil/Solvent + Surfactant + Water ): Oil/Solvent + Surfactant + Water
= Clear Additive = Clear Additive
•Ternary diagram shows areas of microemulsion
system stability. •Area of 1 phase indicates oil water and surfactant appear as a single phase.•Oil is dispersed as Droplets that are nano
to
micrometers is size•
Surfactant
WaterOil/
Solvent
1 phase
3 phases
2 phases
Surfactant
WaterOil/
Solvent
1 phase
3 phases
2 phases
Water oil and surfactant form Water oil and surfactant form VeronoiVeronoiType structures on the order of 10Type structures on the order of 10--20 nm20 nm
These structures maintain their integrityThese structures maintain their integrityand clarity even at very dilute concentrationsand clarity even at very dilute concentrations
Ternary DiagramTernary Diagram
1E-3 0.01 0.1 1 10 1000.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
5.0
5.5
6.0
6.5
7.0
PSD
volume-based (P
CS), %
by volume
Dynamic light scattering (PCS)
Emulsion Complex Nanofluid (CnF), neat CnF diluted (20 gpt, 2% KCl)
PSD
wei
ght-b
ased
(aco
ustic
s), %
by
wei
ght
Droplet diameter (m)
Acoustic spectroscopy
0
2
4
6
8
10
12
14
16
18
20
22
24
26
28
30
CnF diluted (2gpt, 2% KCl)
CnFCnF
NanodropletNanodroplet
Size DistributionSize DistributionMaximize Propagation into Reservoir MatricesMaximize Propagation into Reservoir Matrices
10‐20 nm NanodropletWith Foamer
MicellarMicellar
Solutions Vs. Complex Solutions Vs. Complex NanoFluidNanoFluid
σσSLSL
σσLGLG
σσLLLL
σσLGLG
σσSLSL
Injected fluid in contact with the formationInjected fluid in contact with the formation
MicellarMicellar
SolutionSolution CnFCnF
SystemSystem
•• Presence of liquidPresence of liquid--liquid interface prevents surfactant adsorptionliquid interface prevents surfactant adsorption•• Surfactant adsorption minimizes free energy of the systemSurfactant adsorption minimizes free energy of the system
nanodropletsnanodroplets
Adsorption Test: Fluid flowed through a 12Adsorption Test: Fluid flowed through a 12””
X 1X 1””
diameter column diameter column filled with cuttings. Surface tension measured after eachfilled with cuttings. Surface tension measured after each
pore volume.pore volume.
9
KrussKruss
100 , Surface Tension 100 , Surface Tension
Higher surface tensions Vs. Pore Higher surface tensions Vs. Pore volvol
shows shows adsorptionadsorption
Adsorption mitigated by Adsorption mitigated by CnFCnF/ME formulation/ME formulation
0
10
20
30
40
50
60
70
80
0 2 4 6 8
Pore Volumes
Surfa
ce T
ensi
on (d
ynes
/cm
)
2% FS
NP
AE
ME
ME+2%FS
Foam viscosity in core Foam viscosity in core vsvs
Surfactant Type, Concentration Surfactant Type, Concentration Salinity and PressureSalinity and Pressure
•• Surfactant Surfactant ConcentrationConcentration
•• Salinity Salinity
•• Pressure Pressure
FoamerFoamer
SelectionSelection
Surfactants Foam SalinityRetention
on Sandstone
Temp Oil
Betaine √ √ X √ √
AOS √ X √√ X
#2Micro-emulsion+Betaine
+AOS good improved decreased good improved
Formulation 1: Betaine : AOS = 2: 8
Dual Core Flooding Tests with OilDual Core Flooding Tests with Oil
Label Formu-lation
Concn(gpt)
Preflush (PV)
Back Pressure
(psi)
Core permeability
(mD)
Test 1 Betaine 2 0 1200 67 and 9Test 2 #1AOS-BET8-2 5 1 1200 225 and 81Test 3 #2AOS-BET-
CnF17
5 0.5 1200 335 and 70
Test 4 #2AOS-BET-
CnF17
5 0.1 2400 167 and 85
Inject 0.5 PV of 5 Inject 0.5 PV of 5 gptgpt
Formula 2Formula 2150 F 15% Salinity, 1200 150 F 15% Salinity, 1200 psipsi
335 and 70 335 and 70 mdmd
Flow ratio changes from5 to 1 to 2.5 to 2 And is stable with time
Oil Recovery in Dual Core TestsOil Recovery in Dual Core Tests
Test 1BetaineTest 2AOS-BET8-2Test 3AOS-BET-METest 4AOS-BET-ME
Reservoir ConditionsReservoir Conditions•Sandstone
Permeability range of 50 mD
and 200 mD•T=150 oF•Formation Brine (FB)
Salinity is 15% TDS with divalent ions•West Texas Crude Oil
API 37.7 at 60oF, MMP = 2200 psi
Field treatment
•
Select injector that has low injection pressure relative to the others.
•
Inject ½
pore volume of CnF
based foam based on suspected flow profile
•
This was 3000 gal of 0.3% CnF
Foamer
injected at the end of the water injection cycle
•
Convert to CO2•
CO2 contacts the foamer
placed in the high perm area
and the CO2 is diverted to lower perm unswept
zones•
Observe CO2 emission rate and oil production rate
Facts:Facts:
••Improved Production to Date:Improved Production to Date:
14,110 14,110 BblsBbls..••Cost per Incremental Bbl. to date:Cost per Incremental Bbl. to date:
$0.58$0.58
••Improved COP Percentage:Improved COP Percentage:
75%75%••Improved NPV Percentage:Improved NPV Percentage:
75%75%
27
CnFCnF
Foam ConformanceFoam Conformance
Conclusions1.
Foamer
created with a combination of CnF+AOS+
Betaine
surfactant mixture is –
more resistant to crude oil ;–
more resistant to high salinity–
Has decreased betaine
adsorption on sandstone;
2.
Dual core flow tests show O.5 PV injection changes flow ratio from 8 to 1 to 2.5 to 2 and recovers 80% of the oil in the low perm core
3.
Field results show that the flared CO2 was reduced from 1.5 MMCFD to 0.5 MMCFC after the CnF
Foam
treatment4.
The production has steadily increased after the CO2 diversion resulting in 14,000 Bbl of oil in 4 months.
28
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