Low Tension Flood in Tight Oil Formations

7/27/2019 Low Tension Flood in Tight Oil Formations

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Low Tension Gas (LTG) Floodin Tight Oil Formations

Nhut M. Nguyen

ParticipantsStefan Szlendak, Sujeewa Palayangoda, Vu Nguyen

CMG Foundation Summit

October 7-8 2013


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Low-Tension Gas (LTG) Process:

Principle and Applications

Low Permeabil ity

Heterogeneity

Improvement of

Mobility ControlSynergy of IFT Reduction

and Miscibility

High temperature

High Salinity


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Proof of Concept Study


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Opportunity

Stranded Resource:

Thermal: Best for Darcy type sands

ASP/Polymer: Restricted to >>50mD formations

Miscible gas: Limited by depth, PVT, available gas type

Favorable Development:

LTG can be introduced at secondary recovery

Light crudes require reduced mobility control


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Low gas quality, low rate LTG process

can demonstrate favorable oil mobilization

and displacement for tertiary andsecondary recovery in tight formations

Hypothesis


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Demonstrate high LTG tertiary recovery in tight formations

Identify important process properties that affect project

upscaling (E.g. apparent viscosity)

Contrast with reference WAG & Surfactant floods to establishrespective contributions.

Attempt LTG process for secondary recovery

Research Objectives


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Coreflood Set-up and Procedure

12-in long, 1.5-in diameter

core is first saturated with

brine for measurements of

permeability and porosity

Brine is then displaced by

crude oil to achieve fluid

saturations Soi and Swr= 1-Soi

Water-flood is followed to

obtain Sor

LTG flooding is then

conducted through co-

injection of surfactant andgas

Schematic of coreflood experiment


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Tertiary recovery of 90%,

TOR of 95%

Large oil bank with high oil

cut

Consistent with good

mobility control

Favorable for project

economics

Reduced dispersion in

tight rock resulted inreduced microemulsion

production

Further opportunity to

reduce injected gas quality

1) Achieving High Tertiary Recovery


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2) Critical PropertiesPressure

Propagation of shock front as

oil is displaced

Steady-stateP 5x brine

floodP

krw~ 1 ap~ 5 cP

FurtherP reduction through

decreased rate.

(2ft/day used;


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2) Critical PropertiesMobility

Mobility is inverse of effectiveviscosity orP

d

Mobility ratio can be used todetermine process stability

(next slide)

D

Used to quantify ap =5cP

Steady-state R=0.2

corresponds @krw=1


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2) Critical PropertiesMobility Ratio

Normalized to Mwater @ residual oil

Moilflood endpoint ~ Mwater @ residual oil

Favorable R=1.3

Rapid mobility response

Normalized to Mwater@2PVwaterflood

Reflects actual in-situ conditions

Differs from Mconnate due to

sweep efficiency effects

Indicates initial conditions havereduced impact

Potential conformance benefits

high oil concentration can

decrease in-situ drive strength

Decreasing krw @ 2PV Waterflood


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2) Critical Properties Gas Saturation

High LTG gas saturation observed Indicates stable dispersed

gas phase

Gas saturation determined from effluent salinity and material

balance:

LTG [email protected] ~ 19%

Gas Only [email protected] ~ 4%

Sg = (1-Sw) So

Sw from salinity (right)

So = ROIP NPDTertiary

From material balance


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3) Contrast w/ WAG & Surfactant Recovery

LTG shown to have improved

recovery over combined affects of

Gas + Surfactant flooding

LTG curve delayed versus

surfactant flood due to improved

mobility control and fg=50%

Opportunity to reduce fg=50%

and shift curve left

Delayed LTG gas breakthroughvs. gas flood observed

Gas breakthrough effects

Oil bank effects


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4) Attempt Secondary LTG Flood

Improved recovery

Delayed water

breakthrough

Delayed gas breakthrough

(Not apparent in fig.)

Substantial tail

production

Potential to shift left by

reducing fg

Minimal microemulsion

production


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4) Attempt Secondary LTG Flood

Process shown to reduce

P during secondaryrecovery

Moilflood* ~ 1.1x Mchem SS

>>1, unstable


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Key Findings

Demonstrated high LTG tertiary recovery of ~90% ROIP for

2.6mD, 10mD formation

Observed drive apparent viscosity of ~5cP, correlating with a

mobility ratio (R) of ~1.2-1.3 for tertiary recovery

Observed favorable sweep efficiency during tertiary recovery

Observed high LTG gas saturation, indicating stability of a

dispersed gas phase

LTG secondary recovery results consistent with tertiary

recovery.

Significant secondary recovery upside opportunity:

Higher OIP

LowerP

More favorable mobility of the displaced phase.


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LTG Potential for Broaden Reservoir Candidates

Carbonate Sandstone

Heavy Oil Gas Type


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Effect of Salinity Gradient on LTG

Performance in Sandstone


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To evaluate the effect of new salinity gradient on drive

capacity in LTG process

Research Objective

Conventional Salinity Gradient (ASP)

Formation salinity: Windsor type II

Waterflood salinity: Windsor type II

Slug salinity: Windsor optimum

Drive salinity: Windsor type I

New Salinity Gradient

Formation salinity: Windsor type II

Waterflood salinity: Windsor type II

Slug salinity: boundary ofWindsortype I III ortype I

Drive salinity: Windsor type I


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7 corefloods were conducted; 3 corefloods below fordemonstration

LTG #1: optimum (slug) to type-I (drive)

LTG #2: type I-III (slug) to type-I (drive)

LTG #3: type I (slug) to type-I (drive)

Physical Properties

Experimental Scheme and

Physical Properties

Crude viscosity: 3 cp

Temperature: 60

0

C Pressure: 300 psi

Formation Salinity: 2.2 wt%

NaCl

Slug size: 0.3 PV

Slug surfactant: 0.5 wt%

Drive surfactant: 0.1 wt% Foam quality: 50%

Gas type: N2

Slug salinity: varied


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Results: Oil Recovery

Higher oil recovery

Faster oil production

response

Lower slug salinity results in:


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Results: Pressure Drop

LTG floods at high permeability exhibit a pressure increase at the

end of drive injection, indicating the generation of foam


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Correlation between Salinity Gradient and

Produced Oil Type

Oil viscosity: 3 11 cp Temperature: 50 60 C0

Pressure: 300 psi

Salinity ranges: varied


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Using new salinity gradient yields:

Recovery as high as 95% of waterflood residual oil

Less Type III microemulsion production, meaning

lower cost of microemulsion breaking

Faster response in oil recovery

Stronger drive capacity for mobility control during

chemical injection

Main Conclusions


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Project Sponsors


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Questions

Documents

Low Tension Flood in Tight Oil Formations