Eor in Tight Oil Plays

EOR IN TIGHT OIL PLAYSSHONN ARNDT, CNRL EXPLOITATION ENGINEER MARCH 26, 2014 CALGARY, AB, CANADA

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TIGHT OIL DEVELOPMENT IN WCSBCANADA

3/15/2014 NEB - Energy Reports- Tight Oil Developments in the Western Canada Sedimentary Basin - Energy Briefing Note

http://www.neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/l/tghtdvlpmntwcsb2011/tghtdvlpmntwcsb2011-eng.html 5/37

Source: Modified from University of Regina map

According to an assessment by Macquarie Capital Markets Canada Ltd., the shale source rocks infour major tight oil resource plays in Alberta are estimated to contain over 40 billion barrels of

original oil-in-place (OOIP).[8] This assessment states that even a small recovery factor, such asone per cent of the total OOIP, would go a long way in extending the productive life of theWCSB.

[8] Macquarie Capital Markets Canada Ltd. Going Straight to the Source, Oct 2010

History of WCSB Light Oil Production

Although there were earlier light oil discoveries in western Canada, such as Turner Valleyin 1914, Norman Wells in 1920, and heavy oil at Wainwright in 1923, the giant Leduc discoveryin 1947 really marked the beginning of the oil age in western Canada. Output of conventional oilquickly grew, and peaked in 1973 at about 240 thousand m/d (1.5 million bbl/d). Over theperiod 1973 to 2007, conventional light oil production in the WCSB has declined aboutthree per cent annually. Since 2002, rapidly growing oil sands production has surpassedconventional light oil production in the WCSB (Figure 2).

Figure 2 - History of Oil and Bitumen Production from Western Canada



25 400 m/d (160 000 bbl/d).

Figure 5 - Canadian tight oil production by play

Data source: Divestco

Figure 6 shows the well production profiles for selected wells from four major tight oil plays.Initial rates are quite high, but they decline quickly and stabilize at low decline rates afterabout 9 to 12 months. The economics of tight oil development benefit from these higher initial

production rates and low upfront royalties.[10] Penn West Exploration, one of the most activedevelopers of tight oil plays, estimates that at an oil price of $US85 (WTI), the internal rate of

return for these plays can range from 30 to 70 per cent.[11] Payout times are relatively short,varying from nine months to two years.

[10] In Saskatchewan, the first 38,000 barrels are royalty-free. In Alberta a five per cent royalty applies to the first 50,000,60,000, or 70,000 barrels, depending on well specifics.[11] Penn West Exploration. Unlocking energy (Barclays Capital CEO Energy-Power Conference), September 2011.

Figure 6 - Tight Oil Well Production Profiles



Conventional reservoirs also tend to be isolated pods of oil-bearing and gas-bearing rock, wherethe buoyant oil and/or gas collect in updip areas above water-bearing rock. Tight oilaccumulations, in a similar fashion to tight gas, shale gas and coalbed methane, are sometimescalled continuous resources because they tend to be spread over wide areas and there is nodowndip water. While there can be a significant amount of oil and gas in these continuous

resources, often millions of barrels of oil per section[14], the difficulty until recently has been toextract even a small amount of it.

[14] A section is based on the Dominion Land Survey (township-range grid system) for dispensing land in western Canadaduring settlement. One section is equal to one square mile.

There are two main types of tight oil (Figure 7):

1. Oil found in the original shale source-rock, similar to shale gas[15] and typically called

shale oil.[16] Shales typically have the lowest reservoir quality of oil- and gas-bearingrocks, with microscopic pore spaces that are very poorly connected to one another; and,

2. Oil that has migrated out of the original shale source rock into nearby or distant tightsandstones, siltstones, limestones, or dolostones. This is similar to tight gas plays, whichhave been exploited in western Canada over the past few decades. These tight rock typestypically have better reservoir quality than shales, with more porosity and larger pores, butare still lower quality than conventional reservoirs.

[15] For further information: National Energy Board (NEB). A Primer for Understanding Canadian Shale Gas, 2009. [16] Shale oil is different from an oil shale. The term oil shale is a misnomer because there is very little oil in it. An oilshale is rich in organic matter from which oil can be generated and, if artificially heated, can generate oil. The Green RiverShale of the western United States is an example of an oil shale.

Figure 7 - Conventional, tight, and shale gas and oil

Key Themes: Upfront EOR Dev Planning Cash is king but perm rules Geology selects technology

Reference 16

PRIMARY PRODUCTION

Implications for EOR !

Artificial fracs are potential channels for injection fluid Lowering reservoir pressure lowers perm & oil viscosity



Data source: Divestco

Geology

Oil and Gas Generation

When source rocks (such as coals, which are simply fossilized peats, and organic-rich shales)are deeply buried and subject to high temperatures, hydrocarbons (oil and gas) can be formedfrom the organic matter. Oil is generated at cooler temperatures than natural gas, in atemperature range termed the oil window, at about 100 C. Importantly, the temperature andhow much oil and gas are generated vary as conditions change, and no two source rocks are thesame in this regard. For example, source rocks rich in leafy and woody material, like coals,typically do not produce any oil but may contain considerable amounts of natural gas.Meanwhile, source rocks rich in algae can produce significant amounts of oil. Since it is possibleto measure the temperatures that organic-rich rocks have been exposed to and determine thecomposition of the organic matter, companies looking for oil can prospect for oil-prone sourcerocks that have been heated into the oil window.

Tight Oil Reservoirs

Oil and gas in conventional sandstone, limestone, and dolostone[12] reservoirs typically flow

through pore spaces and sometimes through natural fractures in the rock. In tight[13] versions ofthese rocks, however, the amount of pore space, the size of the pores, and/or the extent towhich the pores interconnect are significantly less than in conventional reservoirs and productionof oil and gas is more difficult.

[12] Dolostone is created when the calcium in a limestone is replaced by magnesium, often generating additional porosity.[13] Tight refers to a rocks natural inability to flow oil and/or gas because of poor reservoir quality.



reservoirs, it can be stimulated with the intention to increase flow rates to economic levels. Forexample, hydraulic fracturing (commonly called fraccing or fracking in industry jargon) has beenused to increase production from the conventional oil reservoirs of the Pembina field sincethe 1950s. The practice has also been used in tight gas reservoirs in Canada for the past fewdecades and has been applied to shale gas reservoirs over the past six years.

Figure 9 - Multi-stage hydraulic fracturing in horizontal and vertical wells

In hydraulic fracturing, a fluid (commonlywater, but could be carbon dioxide,nitrogen, or even propane) is pumpeddown a well and into the targetedformation until the fluid pressure surpassesthe rocks strength and the rock cracks inthe vicinity of the well, creating a newfracture system through which oil and gascan flow into the well. For tight oil, as forshale gas and some emerging tight gasplays, operators are combining multi-stagehydraulic fracturing with horizontal drilling(Figure 9), which allows a horizontal wellto be exposed to just as much reservoir aswould a series of singly fractured verticalwells. Some companies are now reportingthe ability to complete up to 60 frackstages in a well, which greatly exceeds themaximum of 20 reported just two or three years ago.

Development Schemes

Because of the continuoas operations. However, to date it appears that for tight oil three orfewer wells are being dus nature of the resource when compared to conventional reservoirs,companies tend to develop their tight oil properties with significant amounts of planning withrespect to well spacing, well lengths, and frack sizes so the resource can be recovered asefficiently as possible. For example, in the Bakken, the most mature of the tight oil plays inCanada, some companies are using well spacing of three wells per section while others are usingup to eight wells per section, with most using four wells per section. Frack sizes will likelydepend on the well spacing, with larger fracks (using more pressure, fluid and proppant toextend the cracks further) required where fewer wells are used and smaller fracks where morewells are used. Or, at a later stage, additional wells may be drilled between existing wells in apractice called downspacing. Some companies are already proposing enhanced oil recoveryschemes in some areas, potentially using water floods, or even natural gas floods, to sweepmore oil out of the reservoir.

Operators are increasingly making use of multi-well drilling pads, where they can drill two ormore wells from the same wellsite, with up to 16 wells drilled from the same well pad in someCanadian shale grilled per multi-well pad.

Reference 16

Permeability Fundamentals

Radial&Flow&Equa-on&for&Tight&Oil:&&Flow,&Q&&Perm Drive&Pressure&@&Resistance)&&&&&&&&&&&&&&&&&&&&&Visc&&&&&&&&&&&&&&&&&&&&&&&&&&&&

Reference 1

0"

1"

2"

3"

4"

5"

6"

7"

0%" 10%" 20%" 30%" 40%" 50%" 60%" 70%"

Perm

(mD)

Movable Fluid

Perm

(mD)

Pore Throat Size (um)

Reservoir Pressure Sensitivity Fundamentals

As reservoir pressure lowers, mud/cement deforms plastically & fine pores/microcracks close.

Deformation cant be recovered!

A" B" C"

Stress"(Overburden)"

Strain"

D"

Lowering"Reservoir"Pressure"

Plas

Seepage / Percolation Flow Fundamentals

SPE 145024 13

Fig. 4 The relation curve of starting pressure gradient vs. permeability

Fig. 5 The log relation curve of starting pressure gradient vs. permeability

Fig. 6 The curve of the permeability damage ration vs permeability at 25MPa

Restricted)Pore)Throat)

Grain) Boundary)Layer)Forms)(Adsorp:on)of)Fluids))

Grain)

Displacing Pressure > TPG for flow

As flow increases, boundary layer thins i.e. perm increases

Each pore has unique TPG creating non linear flow

!

Question: Are saline waters more sensitive than N2?

Reference 1, 6

Permeability

EOR Choices for LTO

Enhanced(Water(Flood( Cyclic( Advanced(Gas(Injec8on( N2(or(CO2(misc( HC((WAG)( Air(Injec8on(Biochemical( MEOR( Enzyme(Flooding(Thermal( Steam(Injec8on(

Low((

Tight( Low( Moderate( High(0.1( 1( 10( 100(

Water(Flood(Chemical(Gas(Injec8on(Biochemical(Perm(Modifiers(((((((((

Primary(/w(fracs(Other?(((((((((((

Advanced Water Flooding

Concept

Drill water injection wells & install injection systems 6 months prior to drilling production wells.

Maintain reservoir over-pressure for life of field.

Reservoir(Pressure((

Fine(throats(&(micro(fine(cracks(

Overburden

Overpressure > Threshold Pressure Cracks open up & increase perm!

Reference 2

0.0%"0.0%" 10.0%" 20.0%" 30.0%" 40.0%" 50.0%" 60.0%" 70.0%"

Over;pressure%(%),%ns%=%130.4%x%Perm;0.1258%"Example:))1)mD,)ns)=)130%)

Water Specifications Water Floods

(1)Inlet polymer compound water oil content: less than or equal 2000mg/L; (2)Inlet treated water floating content: less than or equal 200mg/L; (3)Compound in the treated water content: less than or equal 450mg/L (4)Viscosity of the polluted water: 0.75 to 2.0mPa.s (testing conditions: rate of

shear is 7.53S-1 , temperature 45 degree) (5) Water density: 1000Kg/cbm (6) Oil density: 840 ~860 Kg/cbm (7) Water temperature: 40~42 deg C.

2. Outlet water parameter requirement (1) Oil removal stage outlet water oil content & floating particle content: less than or equal 50mg/L. (2) Filtering stage(final outlet water ) oil content: less than or equal 20mg/L; Floating particle content: less than or equal 20mg/L; Floating particle diameter average mean: less than or equal 2 micron. 3. Required production treatment cost. The total cost to the station roughly 3.0RMB/ton, equals USD0.44/ton.

III. Oil field inject water quality standard

1. Water driven oil field injected water quality standard Currently DaQing oil field regular injecting water carries the industrial standard issued by National Petroleum & Gas General Corporation (Table 1) ((SY/T 5329-94) and DaQing Oil Co. Ltd issued enterprise standard > (Q/SY DQ0605-2000) (Table 2).

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Water Treatment Technologies

1. Skim Tanks - Various Internals 1. IGF / WLS 1. Warm Lime Softening 1. UV / H2O / O3 Treatment2. Cross Flow / Corrugated Separators 2. Coagulation Tanks /w Filters or Separators (corrugated) 2. Membranes - Ultra / Nano / RO 2. UV / Chlorine Generator

3. Settling Tanks /w Deep Bed Filtrations (various media) 3. SAC's / WAC's4. Dynamic Hydrocyclone /w Deep Bed Filtration 4. Electrodialysis5. Electric Coagulation 5. Electrodialysis /w Membrane6. Chemicals (oxydizers / flocculants)7. Dissolved Air Floatation (DAF) / Dissolved Gas Floatation (DGF)8. Micro Bubblers9. Shear Pumps10. Mycelx Filtration11. Multimedia Filtration (MMF)

1. Bulk Separation 2. Oil, TSS Removal 3. Softening 4. Final Treatment

Case Study: Advanced WFJingan Oilfield, Ordos Basin

Permeability 0.5 - 2 mD

Porosity 8 - 13%

Depth 1690

Reservoir Pressure 10.51 MPa

Oil Visc 1.48 - 4.3 cP

Temp 40-80 C

Primary Recovery 8-10%

Wuliwan

Dalugou

Reference 1

Concept: Nanospheres Overcoming Heterogineities

Nanospheres move by Brownian motion & attracted to boundary layers.

9 This document is a translated by ZL (abstract is original) for reference only- It cannot be reproduced or transferred without written permission. ZL does not guarantee the accuracy of the data being used nor the accuracy of the translation. The original paper can be found in Oil Drilling and Production Technology VOL 35.N4. Article number: 1000 7393(2013)04 0088 06.

with oil marked as red. (Figure 6 a-c). So the water flooding efficiency is low with 13% recovery. When injecting 0.2PV polymeric Nanospheres expanded for 10days at 1000mg/L, the blue water redirect to red channel with apparent increase of sweeping volume, the red residual oil decreased(Figure 6 d-i)and the recovery factor went up to 49%. The result showed that polymeric Nanospheres can reducethe plane heterogeneity of low permeability reservoir to enhance oil recovery.

Figure 6 Distribution changes of water and oil in core micro model with water flooding time

2.2.2Oil displacement experiment of double parallel tube

According to the low permeability and significantvertical heterogeneity characteristics of Block Wuliwan Changqing oilfield, use double parallel sand tube model to study oil displacement performance of polymeric Nanospheres in reservoir with extra-low permeability and significant vertical heterogeneity.

Figure 7 pressure curves of polymeric Nanospheres flooding shows that: after injecting 0.5PV polymeric Nanospheresexpandedfor 10 days, the pressure of the double tubes rise rapidly, then continue water flooding, pressure of the double tubes decrease constantly with some slight fluctuation. It is because that as the enormous permeability difference between the double tubes, most Nanospheres come flow intothe high


The injection property of unexpanded Nanospheres has been evaluated by one tube sand model with 1.3mD permeability on average. Figure 1 shows the pressure variationsof all the measuring points before and after injecting of polymeric Nanospheres. From the figure 1 it can be seen that it has a sudden decline because of switch of the valve, while there is no apparent rise of each measuring point. It shows that unexpanded Nanospheres have good injection property in extra-low permeability core.

2.1.2 Expansion property of polymeric Nanospheres

UseTransmission Electron Microscope and particle size analyzer to test the morphology and particle size distribution of polymeric Nanospheresafter expansion for 10 days in synthetic formation water. Figure 2 and figure 3 show the result.From the TEM photos it can be seen that unexpanded Nanospheres is in regular spherical shape with clear outline.

After expansion for 10 days, there is meshy hydrated layer around Nanospheres, while the core is blurry. It shows that the polymeric Nanospheres have the hydration expansion property.The Nanospheres haveshrunk with smaller particle size as observed when it is dry withunder transmission electron microscope. So the Nanospheres particle size is smaller than that of observing from particle size analyzer.From the particle size distribution it can be seen, polymeric Nanospheres particle size is 100nm on average, while the particle size can growup to several microns after expansion for 10 days, apparently bigger than that of before. It proves that polymeric Nanospheres can expand and becomebigger particle size from hydration in Block Wuliwan Changqing oilfield.

Figure 2 Nanospheres photos of transmission electron microscope

Boundary)Layer)Forms)(Adsorp2on)of)Fluids))

Grain)

Nanospheres

Nano-sphereForce

Force Removed

Review of Nano-sphere mechanisms

The size distribution o the polymer Nano-

spheres after dilated for 20 days at 25.

Reference 21

DUAL CORE FLOOD NANOSPHERESZL PETROCHEMICALS


permeability tube which formed a certain pressureresistance in the high perm tube andresults in pressure rise, which redirects water to flow to low permeability tube causing pressure rise of low permeability tube. At the same time, with the continuously displacement of oil from the double tubes, permeability increases and pressure decreased gradually.

Figure 7 Double tube pressure changes with injecting volume of Nanospheres

From the enhancement of recovery performance of Nanospheres(Figure 8), during water flooding, the recovery factor of high permeability tube is up to 76%, while the low permeability tube is 0, after injection of Nanospheres, recovery factor of low permeability tube increases continuously up to 27% and recovery factor of high permeability tube has also been increased. This is because the Nanospheres injected with the injection water went into the high permeability tube created resistance for water injected afterwards,redirected the water, which displaced residual oil from the low permeability tube and from the low permeability area in the high permeability tube. This experiment shows that Nanospheres can improve the vertical heterogeneity of low permeability reservoir to further enhance oil recovery.

Figure 8 Double tube recovery changes with injecting volume of Nanospheres

Dual Sand-tube Tests Set ups

60 cm

950 mD

93 mD

2.21 mD

0.56 mD

High PermLow PermCombine



Sand PackConcentration Permeability Water Flood Total Recovery Incremental PV*mg/L %RF

Reference 21

Case Study: NanospheresChangqing Oil Field, Plant 3

WF, 3 Well Injection Pilot

Permeability 1.8 mD

Porosity 12.69%

Net Pay 14.2 m

Salinity 53 219 mg/L

Slug Design

A. 3000 ppm micro

B. 3000 ppm nano

C. 1500 ppm nano

D. 3000 ppm micro

Results 2% Incremental in one year

A B C D

Fluid

Oil

Water

A B C DFluidOil

Water

All Oil Wells (Effective, Stable, No Response)

Effective Oil Wells OnlyTo

nnes

/day

Tonn

es/d

ay

1 t ~ 1.2 m3 for light oil

Reference 4

Concept: Steam Flooding Improve Injectivity, Lower Residual Oil Saturation

Increase reservoir pressure i.e. increase permeability, lower TPG.

Vapourize ~31% oil 200 C ~31% (lower visc) reduced residual oil sat to 10%.

Thermal expansion of oil & conduction carrying heat to by passed oil.

Wettability & IFT alterations /w temperature.

7

G-grade cement with sand and cement to the surface. Thermal stress compensator should be located at 10~30m top of oil formation and choke ring should be 15-20m under the bottom of oil formation (see Fig.15).

For producers, casing pipe is steel grade N80 with the diameter of 139.7mm. The cement should cement to the surface (see Fig.15). Choke ring should be 15-20m under the bottom of oil formation

During steam flooding, injection for each vertial injctor should be 50~80t/d and injection for horizontal injector should be 80~100t/d. The steam flooding will last about 7 years and oil recovery will increase 14% than waterflooding.

Fig. 14 Map of Extensive Steam Flooding Project Fig.15 Wellbore Structure of Injector (left) and Producer (right)

Mechanisms of Steam Flooding in Low Permeable Light-oil Reservoir Since the first light-oil steam flood field trials was initiated at the Brea Field near Los Angles in the 1960s, significant detail has been paid to steamflooding recovery mechanisms. Wu7 presented a critical review and identified the following, thorough, but not exhaustive, list: (1) viscosity reduction; (2) distillation (vaporization); (3) distillate (in-situ solvent) drive; (4) Steam (gas) drive; (5) Thermal expansion; (6) Relative permeability and capillary pressure variation; and (7) Gravity segregation.

Figure 16 displays schematically how the most significant mechanisms vary with oil reservoirs containing viscous oil. For the heavy oil, the main objective of steamflooding is to increase oil production by reducing oil viscosity; thus, allowing oil drainage at significantly increased rates. However, for the light oil, the main objective is to reduce remaining oil saturation below that obtained by waterflooding. For the low permeability light oil reservoir, there are other objectives such as quick pressure build-up between injector and producers and high pressure steam drive. The following displays the main mechanisms of steam flooding in the low permeability light-oil reservoir.

Fig. 16 Mechanisms of Steamflonding in LO and HO Fig. 17 Oil Distillation vs. Vw/voi Curves

0

10

20

30

40

50

60

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5

Vw/Voi= / cm3/cm3)

120200250270

Vw/Voi (cm3/cm3)

Oil

Dis

tilla

tion,

%

0

10

20

30

40

50

60

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5

Vw/Voi= / cm3/cm3)

120200250270

Vw/Voi (cm3/cm3)

Oil

Dis

tilla

tion,

%

Thermal Expension

Wetibilty

Viscosity Decline

Vapouration

LO HO

Thermal Expension

Wetibilty

Viscosity Decline

Vapouration

LO HO

- 80 0

- 75

0

- 750

00

00

00 00

00 00

- 80 0

- 75

0

- 750

00

00

00 00

00 00

- 80 0

- 75

0

- 750

00

00

00 00

00 00

273.1mm 100m

Cement to surface

Choke ring: 1520m under BOF

350mm 101m

139.7mm 877m

215.9mm 880m

339.7mm 100m

Cement to surface

Choke ring:1520m under BOF

450.0mm 101m

177.8mm 877m

241.3mm 880m

273.1mm 100m

Cement to surface

Choke ring: 1520m under BOF

350mm 101m

139.7mm 877m

215.9mm 880m

339.7mm 100m

Cement to surface

Choke ring:1520m under BOF

450.0mm 101m

177.8mm 877m

241.3mm 880m

SPE 145005

Light Oil Heavy Oil

Reference 8

CORE FLOOD STEAM INJECTION - LONG TUBEDAQING OIL FIELD

9

Threshold Pressure Gradient Alteration

Long tube displacement experiments show that high temperature can see good results to improve the injectivity (Fig. 20),

which is a challenge faced by water flooding in the low permeable reservoir. Two series of experiments were carried out in a

core tube flood at the temperature of 25 and 200 . At the same flow velocity, the pressure differential under temperature

of 200 is only one fourth of that of 25 , which shows that the high temperature improves the injectivity of the low

permeable reservoir.

Laboratory work shows the contribution to oil recovery increment of each mechanism, which is shown in figure 21. For

steamflooding in the low permeable, light oil reservoir, vaporization, thermal expansion, and viscosity reduction are three

important mechanisms, which contribute to over three quarters of incremental recovery in steam flooding.

Fig.20 Pressure Differential vs. Temperature and Velocity Fig. 21 Mechanisms Contribution of Steamflooding

Conclusions As a mature manner to develop the heavy oil reservoir, steamflooding has been carried out to develop light-oil, low-

permeability reservoir to improve the production performance. Its mechanisms and effectiveness of this process are much

less understood because of the complexities of flow in these sands and high pressure steam injection. This paper examines

thermal recovery in such reservoir using both physical and numerical simulation. In regard to recovery mechanisms,

wettability alteration, interfacial tension and threshold pressure gradient decline contribute to higher oil displacement and

swept efficiency. Vaporization, viscosity reduction, thermal expansion and relative permeability variation accounts for over

three quarters of incremental recovery in steam flooding. The paper also describes a successful steam flooding project in a

low permeable reservoir in Daqing oil field which began in 2005. The steam flooding project shows promising results. The

response to steam injection is prompt and significant. The injectivity is doubled and productivity is almost tripled. The oil-

steam-ratio is around 0.3. The oil recovery to be enhanced is predicted to be over 10%. And now, field operator is

considering expanding the pilot program to a much larger region.

Acknowledgments

The authors would like to thank PetroChina Company Limited for allowing the publication of this paper. Appreciation is also

extended to the following individuals: Shi Lianjie, Zhao Xin, Daqing Oil Field Company Limited.

References

1. Alfredo Perez-Perez, Marjorie Gamboa, Cesar Ovalles: Benchmarking of Steamflood Field Projects in Light/Medium Crude Oils. SPE 72137, 2001.

2. Jung, K.D.: Unconventional Pilot Steam Drive, Tar V Sand, Long Beach Unit, Wilmington Field, CA. SPE12775, 1984.

3. Volek, C., Pryor, J.: Steam Distillation Drive, Brea Field, California. Journal Petroleum Technnology, August, 899-906, 1973

4. Julio G. Estremadoyro: The Use of a Simulation Model to Optimize Reservoir Management in a Very Mature 24Z Reservoir, Elk Hills, California. SPE 68843, 2001.

5. Wu shushong: Steam Distilation in light oil reservoir, Specail Oil Reservoir, 2001. 6. Ruiqi, Y., Shengzhen, Y., Zhengying, Z., and et al Tests of Conversion into Steam Stimulation Following Water

Flooding in Karamay Conglomerate Oilfield, paper SPE 50894, 1998.

7. Wu, C.H: A Critial Review of Steamflood Mechanisms, SPE 6550, presented at SPE 47th Annual Califonia Regional Meeting, Bakersfield, CA (April 13-15, 1977).

8. Wooten, R. Case History of a Successful Steamflood Project-Loco Field, paper SPE 7548, 1978. 9. Chu, C., State-of-Art Review of Steamflood Field Projects, Journal of Petroleum Technology, October 1985, 1887-

1902.

0.5cm3/min

0.6cm3/min

0.8cm3/min

0.5cm3/min

0.6cm3/min

0.8cm3/min25 120

0.5cm3/min

0.6cm3/min

0.8cm3/min

0.5cm3/min

0.6cm3/min

0.8cm3/min25 120

6.2

3.2

1.51.3

7.6

0

2

4

6

8

10

Vaporization Viscosity Reduction Thermal Expansion Gravity Segregation Others

Oil

Rec

over

y In

crem

ent,

% 6.2

3.2

1.51.3

7.6

0

2

4

6

8

10


Oil

Rec

over

y In

crem

ent,

%

SPE 145005

9

Threshold Pressure Gradient Alteration

Long tube displacement experiments show that high temperature can see good results to improve the injectivity (Fig. 20),

which is a challenge faced by water flooding in the low permeable reservoir. Two series of experiments were carried out in a

core tube flood at the temperature of 25 and 200 . At the same flow velocity, the pressure differential under temperature

of 200 is only one fourth of that of 25 , which shows that the high temperature improves the injectivity of the low

permeable reservoir.

Laboratory work shows the contribution to oil recovery increment of each mechanism, which is shown in figure 21. For

steamflooding in the low permeable, light oil reservoir, vaporization, thermal expansion, and viscosity reduction are three

important mechanisms, which contribute to over three quarters of incremental recovery in steam flooding.

Fig.20 Pressure Differential vs. Temperature and Velocity Fig. 21 Mechanisms Contribution of Steamflooding

Conclusions As a mature manner to develop the heavy oil reservoir, steamflooding has been carried out to develop light-oil, low-

permeability reservoir to improve the production performance. Its mechanisms and effectiveness of this process are much

less understood because of the complexities of flow in these sands and high pressure steam injection. This paper examines

thermal recovery in such reservoir using both physical and numerical simulation. In regard to recovery mechanisms,

wettability alteration, interfacial tension and threshold pressure gradient decline contribute to higher oil displacement and

swept efficiency. Vaporization, viscosity reduction, thermal expansion and relative permeability variation accounts for over

three quarters of incremental recovery in steam flooding. The paper also describes a successful steam flooding project in a

low permeable reservoir in Daqing oil field which began in 2005. The steam flooding project shows promising results. The

response to steam injection is prompt and significant. The injectivity is doubled and productivity is almost tripled. The oil-

steam-ratio is around 0.3. The oil recovery to be enhanced is predicted to be over 10%. And now, field operator is

considering expanding the pilot program to a much larger region.

Acknowledgments

The authors would like to thank PetroChina Company Limited for allowing the publication of this paper. Appreciation is also

extended to the following individuals: Shi Lianjie, Zhao Xin, Daqing Oil Field Company Limited.

References

1. Alfredo Perez-Perez, Marjorie Gamboa, Cesar Ovalles: Benchmarking of Steamflood Field Projects in Light/Medium Crude Oils. SPE 72137, 2001.

2. Jung, K.D.: Unconventional Pilot Steam Drive, Tar V Sand, Long Beach Unit, Wilmington Field, CA. SPE12775, 1984.

3. Volek, C., Pryor, J.: Steam Distillation Drive, Brea Field, California. Journal Petroleum Technnology, August, 899-906, 1973

4. Julio G. Estremadoyro: The Use of a Simulation Model to Optimize Reservoir Management in a Very Mature 24Z Reservoir, Elk Hills, California. SPE 68843, 2001.

5. Wu shushong: Steam Distilation in light oil reservoir, Specail Oil Reservoir, 2001. 6. Ruiqi, Y., Shengzhen, Y., Zhengying, Z., and et al Tests of Conversion into Steam Stimulation Following Water

Flooding in Karamay Conglomerate Oilfield, paper SPE 50894, 1998.

7. Wu, C.H: A Critial Review of Steamflood Mechanisms, SPE 6550, presented at SPE 47th Annual Califonia Regional Meeting, Bakersfield, CA (April 13-15, 1977).

8. Wooten, R. Case History of a Successful Steamflood Project-Loco Field, paper SPE 7548, 1978. 9. Chu, C., State-of-Art Review of Steamflood Field Projects, Journal of Petroleum Technology, October 1985, 1887-

1902.

0.5cm3/min

0.6cm3/min

0.8cm3/min

0.5cm3/min

0.6cm3/min

0.8cm3/min25 120

0.5cm3/min

0.6cm3/min

0.8cm3/min

0.5cm3/min

0.6cm3/min

0.8cm3/min25 120

6.2

3.2

1.51.3

7.6

0

2

4

6

8

10


Oil

Rec

over

y In

crem

ent,

% 6.2

3.2

1.51.3

7.6

0

2

4

6

8

10


Oil

Rec

over

y In

crem

ent,

%

SPE 145005

Improved Injectivity

Reference 8

Case Study: Steam FloodingCy Reservoir, Daqing Oil Field

Sandstone, siltstone, shale, multiple sand layers

WF (10% RF in 10 yrs) 55 Inj, 155 Prod.

Low water injectivity, poor communication, poor sweep

High wax content (16-26%, precipitation 49 - 52 C)

Permeability 1-20 mD

Porosity 12-18%

Net Pay 2-4 m

Oil Visc 16 - 95 cp

Temp 55 C

Pressure 8.4 MPa

Depth 1000 m

Steam Flooding Pilot 3 Injectors, 14 Producers

Spacing WE 300-350, NS 150-250 m

Injection Pressure 18.2 MPa,

Steam Quality 50-70%, SOR 0.3

!Results 10% Incremental

Other successful LTO stream flood pilots Wilmington Oil Field (1981), Brea Field (1973), Elk Hill (1987), Ruhlermoor (1987), Minas (1997)

5

Fig. 7 Map of Steam Flooding Project Fig. 8 3 Well Groups of STeam Flooding project

Fig. 9 Injetion Profiles of Well Group of 119-52

Fig. 10 Liquid Production Testing Profiles of Well 121-53 (Blue for Waterflooding and Purple for Steamflooding)

In 2007, 2 well groups near the well pattern 119-52 were added to the steam flooding project and 3 wells were used to inject the steam with the injection rate of 160~180t/d in total. Three months later the oil production was nearly twice of that before 2 injectors went to steam injection. Unfortunately, in the end of 2007 the generator worked poorly and went to repair again. There was no steam injection for more than 5 months. As a result, the oil production declined by 40% in half a year. Once the steam was re-injected into the reservoir, the oil production went up again, see Fig.12. Figure 12 gives the production profile

0 10 20 30 40 50

F331

F23

F21

F171

KH, md.m

NN

0.0 0.5 1.0 1.5 2.0 2.5 3.0

F331

F23

F21

F171

t/d

SFWF

Injectivity,

0.0 0.5 1.0 1.5 2.0 2.5 3.0

F331

F23

F21

F171

t/d

SFWF

Injectivity,

18.6 19 19 19.1 19.2 19.219.1

18.818.2 18.5 18.4 19.3 19.419.4 18.9 18.7

10

15

20

25

MPa

119-5265 84 85 83 82 88 88 88 87 84 85 85 85 87 88 55 5456 56 56 56 55 55 54 54 54

0

60

120

Steam Generator Repairing


Injection Profile of Well 119-52Daily Injection, t/d

Injection pressure, Mpa

Inje

ctio

n pr

essu

re, M

paD

aily

Inje

ctio

n, t/

d

18.6 19 19 19.1 19.2 19.219.1

18.818.2 18.5 18.4 19.3 19.419.4 18.9 18.7

10

15

20

25

MPa

119-5265 84 85 83 82 88 88 88 87 84 85 85 85 87 88 55 5456 56 56 56 55 55 54 54 54

0

60

120





Inje

ctio

n pr

essu

re, M

paD

aily

Inje

ctio

n, t/

d

0 00 0

18.6 19 19 19.1 19.2 19.219.1

18.818.2 18.5 18.4 19.3 19.419.4 18.9 18.7

10

15

20

25

MPa

119-5265 84 85 83 82 88 88 88 87 84 85 85 85 87 88 55 5456 56 56 56 55 55 54 54 54

0

60

120





Inje

ctio

n pr

essu

re, M

paD

aily

Inje

ctio

n, t/

d

18.6 19 19 19.1 19.2 19.219.1

18.818.2 18.5 18.4 19.3 19.419.4 18.9 18.7

10

15

20

25

MPa

119-5265 84 85 83 82 88 88 88 87 84 85 85 85 87 88 55 5456 56 56 56 55 55 54 54 54

0

60

120





Inje

ctio

n pr

essu

re, M

paD

aily

Inje

ctio

n, t/

d

0 00 0

SPE 145005

5

Fig. 7 Map of Steam Flooding Project Fig. 8 3 Well Groups of STeam Flooding project

Fig. 9 Injetion Profiles of Well Group of 119-52

Fig. 10 Liquid Production Testing Profiles of Well 121-53 (Blue for Waterflooding and Purple for Steamflooding)

In 2007, 2 well groups near the well pattern 119-52 were added to the steam flooding project and 3 wells were used to inject the steam with the injection rate of 160~180t/d in total. Three months later the oil production was nearly twice of that before 2 injectors went to steam injection. Unfortunately, in the end of 2007 the generator worked poorly and went to repair again. There was no steam injection for more than 5 months. As a result, the oil production declined by 40% in half a year. Once the steam was re-injected into the reservoir, the oil production went up again, see Fig.12. Figure 12 gives the production profile

0 10 20 30 40 50

F331

F23

F21

F171

KH, md.m

NN

0.0 0.5 1.0 1.5 2.0 2.5 3.0

F331

F23

F21

F171

t/d

SFWF

Injectivity,

0.0 0.5 1.0 1.5 2.0 2.5 3.0

F331

F23

F21

F171

t/d

SFWF

Injectivity,

18.6 19 19 19.1 19.2 19.219.1

18.818.2 18.5 18.4 19.3 19.419.4 18.9 18.7

10

15

20

25

MPa

119-5265 84 85 83 82 88 88 88 87 84 85 85 85 87 88 55 5456 56 56 56 55 55 54 54 54

0

60

120





Inje

ctio

n pr

essu

re, M

paD

aily

Inje

ctio

n, t/

d

18.6 19 19 19.1 19.2 19.219.1

18.818.2 18.5 18.4 19.3 19.419.4 18.9 18.7

10

15

20

25

MPa

119-5265 84 85 83 82 88 88 88 87 84 85 85 85 87 88 55 5456 56 56 56 55 55 54 54 54

0

60

120





Inje

ctio

n pr

essu

re, M

paD

aily

Inje

ctio

n, t/

d

0 00 0

18.6 19 19 19.1 19.2 19.219.1

18.818.2 18.5 18.4 19.3 19.419.4 18.9 18.7

10

15

20

25

MPa

119-5265 84 85 83 82 88 88 88 87 84 85 85 85 87 88 55 5456 56 56 56 55 55 54 54 54

0

60

120





Inje

ctio

n pr

essu

re, M

paD

aily

Inje

ctio

n, t/

d

18.6 19 19 19.1 19.2 19.219.1

18.818.2 18.5 18.4 19.3 19.419.4 18.9 18.7

10

15

20

25

MPa

119-5265 84 85 83 82 88 88 88 87 84 85 85 85 87 88 55 5456 56 56 56 55 55 54 54 54

0

60

120





Inje

ctio

n pr

essu

re, M

paD

aily

Inje

ctio

n, t/

d

0 00 0

SPE 145005

6

of 7 wells in the steamfloong well groups, whereas Figure 13 gives the production profile of 7 wells of waterlfooding. During waterflooidng, the liquid production was only 12t/d for 7 wells. However, it was about 30~40t/d for 7 wells in steamflooding and productivity is almost tripled.

Up to now, the pilot test has shown promising results. The response to steam injection is prompt and significant. The oil-steam-ratio is around 0.3. The incremental oil recovery is predicted to be over 10%.

Fig. 11 Production Profiles of Well Group of 119-52

Fig. 12 Production Profiles of Pilot Test (7 producers)

Fig. 13 Production Profiles of Waterflooding (7 producers)

Extensive Steam Flooding Project

Field operator is considering expanding the steam flooding program to a much larger region. The extensive steam flooding project will include 6 vertical well groups and 2 horizontal well groups. Totally 39 wells will be in the project with 8 injectors and 31 producers, in which 7 injectors and 11 producers are new wells (see Fig. 14).

For injectors, casing pipe is steel grade TP100H with the diameter of 177.8mm. Lifting and drawing preceding stress is applied in well completion in order to resist the thermal stress during high temperature steam injection. The cement should be

32.7 30.7

44.8 45.3 47.248.4

43.4

32.4 30.8 33.741.5

46.9

29.637.4

43.6 46.5 46.5 41

28.1 28.536.5

42.1

46.4

41.728.3

28.915

35

55

2007 3 4 5 6 7 8 9 10 11 12 2008 2 3 4 5 6 7 8 9 10 11 12 2009

18.618.8 19 19 19.2 19 19 19.1 19 19 19 19 19 18.919.119.119.119.119.119.2

10152025

MPa


170 169 168 170 165 171 168 165 168 168 168 180 185 190 185 185 185 185 187 190

100150200250

m3

t

MPa

/

t

Pro

duct

ion,

t/d

Inje

ctio

n pr

essu

re, M

paDai

ly In

ject

ion,

t/d

Ql Qo

Production Profile of Pilot Test (7 producers)

32.7 30.7

44.8 45.3 47.248.4

43.4

32.4 30.8 33.741.5

46.9

29.637.4

43.6 46.5 46.5 41

28.1 28.536.5

42.1

46.4

41.728.3

28.915

35

55

2007 3 4 5 6 7 8 9 10 11 12 2008 2 3 4 5 6 7 8 9 10 11 12 2009

18.618.8 19 19 19.2 19 19 19.1 19 19 19 19 19 18.919.119.119.119.119.119.2

10152025

MPa


170 169 168 170 165 171 168 165 168 168 168 180 185 190 185 185 185 185 187 190

100150200250

m3

t

MPa

/

t

Pro

duct

ion,

t/d

Inje

ctio

n pr

essu

re, M

paDai

ly In

ject

ion,

t/d

Ql Qo

Production Profile of Pilot Test (7 producers)

13.417.2

33.2 32.225.2 27.8

29.1 25.9 23.317.9 19.4 20.7

23.9

12.3

31.1 30.824.3 26.9

28.5 25.4 22.919 19.5

23.2

26.719.3

16.512.512.6

24

24.3

11.8

19.1 17.416.412

16.5 23.4

0

10

20

30

40

t

0

10

20

30

pQl Qo Water cut

Wat

er c

ut, %

Pro

duct

ion,

t/d

13.417.2

33.2 32.225.2 27.8

29.1 25.9 23.317.9 19.4 20.7

23.9

12.3

31.1 30.824.3 26.9

28.5 25.4 22.919 19.5

23.2

26.719.3

16.512.512.6

24

24.3

11.8

19.1 17.416.412

16.5 23.4

0

10

20

30

40

t

0

10

20

30

pQl Qo Water cut

Wat

er c

ut, %

Pro

duct

ion,

t/d

Q, t

/d

Ql Qo

Q, t

/d

Ql Qo

SPE 145005

Reference 8

Concept: Misc Gas Flooding CO2, Hydrocarbon WAG

Inject 0.2-0.4 PV of solvent alternating /w water 0.01 - 0.04 PV to decrease solvent mobility.

Oil is recovered by direct misc displacement & oil swelling in bypassed oil.

Reference 17

SIMULATION IN TIGHT OIL FORMATIONSUNIVERSITY OF CALGARY / PENNWEST 2012

2 SPE 152084

However, in such systems, achieving injection levels adequate for carbon storage and incremental oil recovery is a challenge using conventional oilfield technologies. The adoption of multi-stage fractured horizontal wells in such a situation is an effective strategy to increase injectivity. To increase the sweep efficiency, and hence oil recovery, the configuration of hydraulic fractures and their orientation should satisfy two conditions: maximizing contact area with the reservoir matrix and maximizing distance between the producer fractures and injector fractures. One solution that can offer such an opportunity is to have staggered transverse fractures along the injectors and producers. Therefore, the focus of this study is the investigation of CO2 EOR, either through injection of pure CO2 or WAG injection, in such configurations. In this paper, compositional simulation of CO2 EOR in a tight oil reservoir, with properties similar to the low permeability portion of the Pembina Cardium field, is performed and the results are summarized. A commercial compositional simulator is used to examine the amount of incremental recovery that can be obtained in such a reservoir after the secondary recovery stage. The results of the CO2 storage capacity of these plays under different injection schemes will be provided. Base Case Data and Simulation Model a) Fluid properties and EOS model The reservoir oil is undersaturated light oil with stock tank gravity of 38 API and an initial solution gas-oil-ratio (GOR) of 730 scf/stb. The original reservoir pressure at the reference depth of 5279 ft is 2520 psi. The bubble point of the reservoir at reservoir temperature of 127 F is approximately 2450 psi. The CO2 minimum miscibility pressure (MMP) was determined experimentally to be 2320 psia. Table 1 summarizes the important properties of the reservoir fluid.

Table 1 Reservoir fluid properties Parameter ValuePb, psia 2450 Rs at Pb, scf/stb 730 Oil viscosity at Pb, cp 0.63 Bo at Pb, res. bbl/stb 1.37 Oil density at STP, lbm/ft3 52.1 Avg. gas viscosity, cp 0.01 Avg. gas density at STP, lbm/ft3 0.065 Water viscosity, cp 0.57

Table 2 Composition of the fluid (after regression) Component Mole Frac.CO2 0.001 N2-C1 0.414 C2 0.076 C3 0.059 C4-C5 0.061 C6 0.026 C7P* 0.363 * MW = 238 lb/lbmole ; S.G. = 0.86

(a)

(b)

Fig. 1 Comparison of the predicted (PR EOS and LBC correlation) and observed values for (a) liquid mixture swelling factor and (b) liquid viscosity with respect to CO2 mole percentage in the mixture.

A crucial part of a compositional reservoir simulation of miscible or even immiscible EOR scenarios is appropriate prediction of the phase equilibria between the in-situ reservoir fluid and the injected fluid. To achieve this, an equation of state (EOS) is usually tuned via experimental PVT data. The tuning of EOS in this work followed the methodology suggested by Khan et al. (1992) to characterize CO2-oil mixtures. The two-parameter Peng-Robinson EOS (Peng and Robinson, 1976) was selected to regenerate the fluid properties because it has proven to be suitable for low-temperature CO2-oil mixtures

Swel

ling

Fact

or, v

ol./

sat.

vol.

CO2 mole percent

Experimental

PR EOS

Liqu

id V

isco

sity

, cp

CO2 mole percent

Experimental

LBC correlation

4

wpc

dccp

wrc

0pp

rrhsw5

Fp

4

Table 3- ReseLength, ft Width, ft Thickness, ft Depth at the toInitial reservoiInitial water saInitial oil saturReservoir temAverage porosAverage horizHorizontal to vReservoir poreReference preRock compresNumber of griGrid size (Dx

where product in the conductivity is

Fig. 3-a shodisplays the subcenter (P2 withcover the wholplanes.

A combinatwater injector)recovery is concut at producer

The set of r0.25 (the same phases are equapressure, howev

Fig. 5 depicrecovery stage reduction in thehence restrictesubstantially inwill happen aft5-c).

Fig. 3 (a) Dispermeability re

ervoir input fo

op of formationir pressure, psiaturation, % ration, %

mperature, F sity, %

zontal permeabvertical permeae volume, bbl essure, psi ssibility at Pref, ds (NxNyNzDyDz), ft

is the producsimulation m

around 150 mdows a transparb-grid in the reh complete frale drainage ar

tion of initial is simulated

ntinued until ths reaches 95%

relative permeaas initial wateral to 0.25 and ver, is neglectects various aspand at the be

e oil productioed flow capacncrease the oil pter two and hal

splay of the reepresenting th

or the base cas

n, ft

bility, mD ability ratio

psi-1 z)

t of fracture pmodel. The hyd

d-ft. rent display of efined region wcture plane) an

rea. Table 4 s

primary recovas a base cas

he recovery rea. The water injability curves ur saturation) anthe maximum ed. pects of the fireginning of waon rate as one city of the injproduction ratelf years. At the

(a) efined grids whhe hydraulic fr

se 5250 1350 15 5297 2520 25 75 127 12 0.61 0.1 2.2 106 1000 5.0 10-6 105275 50503

permeability andraulic fractur

the 3-D view with modified tnd two boundaummarizes the

very (all wells se for compariaches a plateauection operatio

used for the band critical gas relative perme

rst two stages oater-flooding sof the producejector, causes es. In this exame breakthrough

hich create thracture plane.

TableWell dWell leWell sBottomInjectiDuratiDuratiNumbNumbSpacinHF haHF heConduHF oriHF arr* HF is

nd width (fracres in our stud

of parent blocktransmissibilityary located wee properties of

are producers)ison with misc(~15%) and th

on will last for se case are shosaturation is 0.eability for gas

of simulated otage (convertiners is eliminate

considerable mple, under theh time the avera

he hydraulic fr.

e 4- Descriptiodiameter, ft ength, ft spacing, ft m hole pressuron rate, rb/dayion of primary rion of water flo

ber of HF* alongber of HF alongng between co

alf-length, ft eight, ft uctivity of HF, mientation rangement s abbreviated f

cture conductivdy have a con

ks enclosing ry equal to that ells (P1 and P3f the wells an

) and subsequcible gas floohe subsequent 15 years.

own in Fig. 4. .05. The residus and water are

oil recovery. Ang the central ed. Limited pedelay for wa

e water injectioage reservoir p

racture bound

on of wells and

re of producersy recovery, year

ooding stage, yeg producers

g injectors onsecutive HF,

md-ft

form of Hydrau

vity) and nstant width e

efined fractureof a real fractu

3 with one winnd their surrou

uent water-flooding and WAwater-flooding

The critical waual oil saturatioe 0.50 and 0.35

According to Fi well into inje

ermeability of ater to first ron rate of 300 spressures is clo

(b) daries and (b)

S

d hydraulic fra0.6 3650650

s, psia 3003205

ear 15 13 12

ft 300 f22515 150transstagg

ulic Fracture(s)

is the correqual to 2.0 ft

es in the modeure. One inner ng of fracture punding hydraul

oding (P2 is coAG process. Th

g is active unti

ater saturation on for both gas5, respectively

ig. 5-a, just aftector), there isthe reservoir meach the prodstb/day, the breose to its peak

refined grid w

SPE 152084

actures

0

ft

sverse gered

responding ft and their

l. Fig. 3-b, well at the plane) will lic fracture

onverted to he primary il the water

is equal to s and water y. Capillary

ter primary s an abrupt matrix, and ducers and eakthrough value (Fig.

with higher

8

os

Fd CIsmcbr rbgfp

8

on the sequestrsome extent the

Fig. 7 Variatidifferent inject

Conclusions In this paper, a simulator is usmiddle injectorcontact area wbreakthrough orecovery, almo

To recover tresults indicateby the reservoirgas causes rathfractures (path process would r

ation capacity e oil recovery f

ion of (a) oil retion schemes.

quarter sectionsed to investigr) have transveith the formati

of the injected st 70% of the othis remaining e that recovery r heterogeneity

her quick breakof least resistaremain immisc

of different scfactors.

ecovery facto.

n of a tight oil ate CO2 EOR

erse fractures inion as well asfluids and imp

original oil in poil saturation, factors from i

y and also the mkthrough at th

ance) was estabcible and not ga

hemes have be

r (b) average

reservoir withprocess. The

n a staggered maximizing dproving sweepplace remains tCO2 injection,

injection scenamobility of the

he producers. Ablished, the aveaining the bene

een neglected i

(a)

(b) reservoir pres

h a stochastic pthree horizontconfiguration. distance betwep efficiency. Atrapped in the i, either through

arios (with cone injected fluidAs such, once erage reservoirefit of miscible

in this study. T

ssure with res

permeability dital wells in thThis configur

een the fracturAt the end of p

inter-fracture sh injection of p

nstant rate consds. For continu

the connectior pressure fallse flood.

These importan

spect to the H

stribution is sehe model (two ration has the ares, which is imrimary and sec

spaces of this spure CO2 or Wstraint on injec

uous CO2 injecton between thes rapidly below

S

nt parameters m

CVP of injecte

et up and a comedge produce

advantage of mmportant in decondary (wateymmetric mod

WAG was consictors), is quite tion, high mob

e injectors andw the MMP, the

SPE 152084

may alter to

ed CO2 for

mpositional rs and one

maximizing elaying the r-flooding)

del. idered. The influenced

bility of the d producers ereafter the

Reference 12

CO2 WAG /W COMPLEX NANO FLUID SOLVING HETEROGINEITYCESI / FLOWTECH

FD Conformance

14

StimOil FD - 1 Pumped

FD Conformance

15

StimOil FD 1 Pumped

West Texas Pilot Sandstone Perm 50 - 200 mD Temp 150 F Oil 37.7 API Salinity 15 000 mg/L MMP 2200 psi 0.5 PV CnF

Reference 20

EOR Selection Criteria

NOT MENTIONED: 1. POLYMER - SMALL MW FOR IN DEPTH FRAC (BARROW ISLAND WINDALIA, AUSTRALIA) 2. SURFACTANT - CORE FLOODING SHENGLI OILFIELD - ABSORPTION? 3. MEOR - BREVIBACILLUS / BACCILUS ROD SHAPED 0.8 - 1.4 UM & 0.4-1 UM - GOOD PERM MODIFIER, PLUGGING? (DAQING, CHINA) 4. BIOLOGY ENZYMES - ALTER WETTABILITY, LOWER IFT - WORTH CONSIDERING (CHAOYANGGOU, CHINA)

Category Process ,Lithology

Hz,Perm,(mD)

Porosity(%)

ReservoirPressure,(Mpa)

Depth,(m)

Temp(C),

Thick,(m)

Gravity,(API)

Visc(cP)

Oil,Sat,(%) Comments

Secondary,Recovery

Advanced(Waterflood

SandstoneLimestone(Dolomite

>=(1(>(0.1)

Injectivity(IssuesWater(Source(/(Quality(CriticalDirection(of(Fracs(clear

CO2(WAG(Miscible 0.1I50 3.93I29 1.2I22 699(I(3202 11I121 3I56.7 >=(25(>(20) 0.34I3.5 17I89HeterogineityGas(FingeringGravity(SegregationSource(of(CO2?

CO2(Immiscible 36I500 13I32 732I2689 48I108 7I110 >=(15 0.46I32 36I80 Same(as(CO2(Misc

Hydrocarbon(WAG(Miscible

0.1I50 3.93I29 762(I(3202 3I56.7 (>=(30(>(23)

C2IC5(SolventSame(as(CO2(misc(plusHydrate(issues

N2(WAG(Misc 0.5I700 4I27 28I37 371I4816 41I141 8.5I70 >30 0.18I0.85 80I99 Typically(considered(in(offshore(applications.

N2(Immiscible 3I2050 4I28 21I41 366I5642 26.7I163 7I110 >24 0.07I3.5 47I98.5No(cracks(in(rock

Thermal Steam(FloodSandstone

Carbonate(Conditionnal)

>0.1 >12% >100(m >(2m

Water(Source(/(Quality(CriticalHeat(loss(to(over/underburden

PermModifiers

Nano(Technology Sandstone

Top EOR Picks for LTO

1. CO2 Nano Water Alternating Gas misc (CO2 source?)

2. Advance WF /w nano chaser (Injectivity?)

3. Steam Flood to solve wax / injectivity issues.

References:)1.##Advanced#Water#Injec0on#for#Low#perm#Reservoirs#Ran#Xinquan#Petroleum#Industry#Press#2013#2.##Study#on#Advanced#Water#Injec0on#Time#on#Low#Permeability#Reservoirs#Lijun#Wang,#Linli#Wei#Energy#and#Power#Engineering,#2011,#3,#

194K197#3.##Polymer#Nanospheres#Control#and#Flooding#in#Low#Permeability#Oil#Fields#and#Effects#Zheng#et#al#Petrochemical#Industry#Applica0on#

Vol#31#No#12#Dec#2012#4.##Research#on#the#Adaptability#of#Polymeric#Nanospheres#Flooding#in#Extra#Low#Permeability#Reservoir#in#Changqing#Oil#Field,#Wu#

Feipeng#et#all,#Oil#Drilling#Produc0on#Technology#Vol#35,#NO#4#Ar0cle#1000K7393(2013)04K088K06#5.##SPE#148995#Inves0ga0on#of#Primary#Recovery#in#Tight#Oil#Forma0ons:#A#Look#at#Cardium#Forma0on,#Alberta,#Ghaderi#et#all#2011#6.##SPE#145024#An#Integrated#EOR#Successfully#Applied#in#ChangK6#Ultralow#Permeability#Reservoir#Gua#Xiao#et#al,#2011#7.##Enhanced#Oil#Recovery#in#Fractured#Reservoirs#Mar0n#A.#Ferno#www.intechopen.com##8.##SPE#145005#Steam#Flooding#to#Enhance#Recovery#of#Water#Flooded#Light#Oil,#Dennis#Denney,#July#2011.#9.##Impact#of#Ultra#Low#Interfacial#Tension#on#Enhanced#Oil#Recovery#of#Ultra=Low#Permeability#Reservoir,#Zhao#Lin#et#all,#Advances#in#

Petroleum#Explora0on#and#Development,#Vo#4,#No1#2012#pp#49K54#10.##SPE#165301#Inves0ga0on#of#Economic#Uncertain0es#of#CO2#EOR#and#Sequestra0on#in#Tight#Oil#Forma0ons,#S.M#Ghaderi#et#all,#2013#11.##SPE#161884#Op0miza0on#of#WAG#Process#for#Coupled#CO2#EOR#Storage#in#Tight#Oil#Forma0ons:#An#Experimental#Design#Approach#

S.M.#Ghaderi#et#all#2012#12.##SPE#152084#Evalua0on#of#Recovery#Performance#of#Miscible#Displacement#and#WAG#Process#in#Tight#Oil#Forma0ons,#Ghaderi#2012#13.##Assessment#of#CO2#Flooding#Poten0al#for#Bakken#Forma0on,#Saskatchewan,#Wang#et#al,#2010#14.##SPE#112793#Developing#a#Chemical#EOR#Pilot#Strategy#for#a#Complex,#Low#Perm#Water#Flood,#A.J.P#Fletcher#et#all#2008#15.##SPE#144281#Biological#Enzyme#EOR#for#Low#Permeability#Reservoirs,#Liu#He#et#all,#2011#16.##NEB#Energy#Reports##Tight#Oil#Development#in#the#Western#Canada#Sedimentary#Basin#Energy#Briefing#Note#17.##hip://petrowiki.org/Miscible_flooding##18.##SPE#152084#Evalua0on#of#Recovery#Performance#of#Miscible#Displacement#and#WAG#Process#in#Tight#Oil#Forma0ons,#Ghanderi#et#all,#

2012#19.##SPE#112793#Developing#Chemical#EOR#Pilot#for#Complex#Low#Permeability#Waterflood,#Fletcher#et#all,#2008#20.##hip://www.co2conference.net/wpKcontent/uploads/2012/12/03KPennyKCESIKComplexKNanoKFluidsKandKConformanceK12K6K12.pdf##21.##Nano#Principles#and#Lab#Presenta0on,#ZL#Petrochemicals#22.##SPE#147531#Chemical#Process#for#Improved#Oil#Recovery#from#Bakken#Shale,#Schuler#et#all,#2011#23.##The#Applica0on#of#MEOR#in#Chaoyanggou#Daqing#Low#Perm#Oil#Field,#Xiaolin#et#all,#2012#24.##SPE#144281#Biology#Enzyme#EOR#for#Low#Perm#Reservoir,#He#et#all,#2011.

http://www.co2conference.net/wp-content/uploads/2012/12/03-Penny-CESI-Complex-Nano-Fluids-and-Conformance-12-6-12.pdf

Date post:	09-Feb-2017
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