Slides-13

Tayfun Babadagli, PhD, PEng Short Course - EOR File-131

EOR in Heavy Oil / Carbonate Reservoir

Carbonate Reservoirs40% of Total Reserves 65% of Middle East Reservoirs

Carbonate Heavy Oil ~1600 MMM bbl

EXAMPLES: Iran (>20 MMMbbl), Mexico, Canada (Grossmont, 5-9 API, 1,600,000 cp oil)


Field Experience on Steam Injection in Fractured Carbonates

• Qarn Alam Steam Project, Oman

• Lacq Superior Steam Project, France

• Ikiztepe Steam Pilot, Turkey

• Yates Steam Project, USA


Other examples• The Issaran (Egypt) is under consideration for steam

stimulation after a period of “cold production” (D= 2200 ft.)

• Only two carbonate fields under steamflooding in the US: Yates (Texas) and the Garland (Wyoming) fields.

• Garland field is 4,250 ft deep which is very close to the average depth of the Bati Raman field (no reports).

• Only one steam injection case in carbonates in China. The Gaoshen 2-3 field have been under steam injection since 1982 to enhance the recovery of 16-19 API oil with 1,000-2,000 cP viscosity (D= 5,081-5,740). This is the deepest steam injection in all type of reservoirs ever reported.


Recent trends in developing heavy-oil carbonates

• Grosmont, Canada (5-9 API)• Bangestan, Iran (10-12 API)• *Bati Raman, Turkey (10-13 API)• Zaqeh, Iran (16 API)• *Rospo Mare, Italy (12 API)• Issaran, Egypt (9-12 API)• *Varadero, Cuba (10 API)• Campos, Brazil (12-21 API)

*: Commercial


Recent trends in developing heavy-oil carbonates

• Bangestan, Iran (10-12 API): 1,200 m (Sarvak), 400 m (Jahrum) considering SAGD

• Zaqeh, Iran (16 API): 4,230 m, in-situ combustion

• *Rospo Mare, Italy (12 API): 1,300 mss, matrix full of water, horizontal wells produced 4,000 bbl/day (5 times the rate of verticals)

• *Varadero, Cuba (10 API): In production >30 yrs, oil in tight matrix


Core Name Lithology Absolute.Permeability, md Porosity,% Pore Volume, CC

KM-A Limestone 0.5 15 14.16

KM-B Limestone 0.3 20 18.88

KM-C Limestone 0.2 21 19.83

KM-D Limestone 0.5 21 19.83

MN-A Dolomite 0.3 17 16.05

MN-C Dolomite 0.5 11 10.39

MN-X Dolomite 3.0 21 19.83

Name Oil Density ,API

Dead Oil Viscosity @100°F,cp

Thermal Expansion Factor(from 70 to 150°F) 1F

Compressibility1psi

KM 12 16000 41000.4 61067.4 PY 17 2094 41024.4 61090.5

PYW 21 4 N/A N/A CHKH 26 10 N/A N/A

Relative Permeabilities under Temperature Effect

Sola, Rashidi, and Babadagli, J. Pet. Sci. and Eng. (2006)


Relative permeabilities obtained by history matching (KM-C-KM @ 150,200,250,300,400, and 500°F).



Temperature ,°F orrw Sk @ on wn orS ,%150 0.05 0.7 3.0 68 200 0.03 0.1 5.0 62 250 0.03 0.5 3.0 56 300 0.05 0.2 4.0 37 400 0.05 0.25 0.1 12 500 0.10 0.3 3.0 8



a) Relative permeabilities obtained by history matching (MN-X-PY @ 200,300,450°F). Comparison of the relative permeabilities obtained from

the JBN method and history matching b) @ 200°F c) @ 300°F d) @ 450°F)







Comparison between heavy oil carbonate relative permeabilities at high temperatures and the results of

similar works on heavy oil sandstones.



•The irreducible water saturation linearly increased with increasing temperature. (capillary pressure curves may be temperature sensitive.)

•The residual oil saturation decreased with increasing temperature and the trend, however, is non-linear.

•The shape of oil and water relative permeability in dolomite rocks significantly change with increasing temperature becoming more linear.

•If the intersection points are used as an indicator of wettability (shifting this point to right implies more water-wettability), one can state that the rock becomes more water-wet in dolomite/heavy oil system with increasing temperature. The opposite was observed for the limestone system.

•The oil relative permeability changed with increasing temperature for all different oil viscosities shifting to right. Change of wettability to more water-wet with increasing temperature could be one of the reasons of shifting the curves to right. For the extra heavy-oil case, the effect of temperature on the change of the water relative permeability curves is trivial.


QARN ALAM FIELD

OMAN

LocationSTOOIP = 213 MM m3

Ultim. Rec. = 4.65 MM m3

Low RF !

A CHALLENGING FIELD:Carbonate

Highly FracturedHigh Viscosity of Oil


Matrix-fracture interaction under static conditions for hot water and steam.

– Capillary Imbibition– Thermal Expansion– Gas Generation– Chemical Alteration of Oil– Gravity Drainage– Pressure Depletion– In-situ Steam Generation– Alteration of Rock Matrix– Oil Generation– Distillation– Solution-gas Drive– Rock Compaction

Internal Drive

Challenge: Recovery mechanisms in BR and

effects of micro and macro scale heterogeneity


Mechanisms

• Thermal expansion (order of 1 to 100 days with maximum recovery of 15%)

• Gas-oil gravity drainage (GOGD) (order of 1 to 10 years with maximum recovery of 50%)

• Capillary imbibition (order of 1 to >10 years with maximum recovery of 20%)

• Steam stripping (order of 1 month to several years with maximum recovery of 10%)


• GOGD promises the highest recovery but the slowest process. • Several other mechanisms were also proposed including the

connate water flashing (Babadagli and Bemani, 2007). • Shahin et al (2006) concluded that the recovery goes from 4% by

GOGD up to 27% with thermally assisted TAGOGD. • The recovery is most sensitive to fracture geometry, fracture thermal

properties, matrix size, kv / kh and oil relative permeabilities. • Fracture characterization is critical and different fracture scenarios

were tested against the oil recovery (Penney et al., 2005). • They also considered different development options testing the

importance of steam rate, steam phasing, steam tapering, injector and producer location and type, and producing BHP. They observed that the steam injection rate by far the most important parameter and under and/or over injecting steam has the biggest impact on the process.


• Oil will be produced for at least 60 years.

• Steam injection rate, bottom hole pressure, and fracture properties (geometry, connectivity, spacing, etc.) and obviously oil relative permeability are the most critical parameters on the TA-GOGD recovery.


Mechanics of TA-GOGD process in the Qarn Alamfield (IPTC-10727) Sensitivity of subsurface

parameters on the TA-GOGD recovery at fixed steam rate (IPTC-10727).


• Ayetollahi et al. [2005] tested the effect of wettability in the matrix drainage process. They reported that oil recovery by gravity drainage could be as high as 84% in water wet case. Oil wet case yielded only 46% oil recovery under the same conditions.


EXPERIMENTAL PROGRAM

So (100%)

CORE PREPARATION

So + Swi

STATIC IMBIBITION EXPERIMENTS(at room temp. and in the oven)

Berea sandstonesOil wet (induced) Berea sand.Original QA cores (cleaned)Original QA cores (preserved) 90 oC

200 oC212 oC

20 oC


VISCOSITY (QA OIL)

0

500

1000

1500

2000

2500

3000

3500

4000

0 10 20 30 40 50 60 70

Temperature, oC

Visc

osity

, cP

Babadagli and Bemani, J. Pet. Sci. and Eng., 2007


IFT (QA OIL-BRINE)

15

17

19

21

23

25

0 20 40 60 80 100

Temperature, C

IFTdyne/cm

Babadagli and Bemani, J. Pet. Sci. and Eng., 2007


COMPARISON OF STATIC IMBIBITION TEST : WITH and WITHOUT Swi

BEREA, Swi=0 and >0

0

10

20

30

40

50

1 10 100 1000 10000 100000 1000000Time, min.

Oil

Rec

over

y, P

V (%

)

Berea 20 C, Swi>0 (B3) Berea 90 C, Swi>0 (B5)Berea 20 C, Swi=0 (B1) Berea 90 C, Swi=0 (B7)

05

1015202530

1 10 100 1000 10000 100000Time, min.

Oil

Rec

over

y, P

V (%

)

Berea 90 C, Swi>0 (B9) Berea 90 C, Swi=0 (B11)

BEREA (oil wet), Swi=0 and >0

02468

10

1000 10000 100000Time, min.

Oil

Rec

over

y, P

V (%

)

QA 90 C, Swi=0 (QA10) QA 90 C, Swi>0 (QA1)

QA, Swi=0 and >0

90 C experiment was corrected for thermal expansion by dividing the recovery by 1.04

Babadagli and Bemani, J. Pet. Sci.

and Eng., 2007


Gas Generation, Chemical Alteration of Oil In-situ Steam Generation Alteration of Rock Matrix

Oil Generation Distillation

Solution-Gas DriveCO2 generation

0

10

20

30

40

50

60

70

80

B1 B7 B12

B10

B11

B14 B3 B2 B5 B6 B8 B9 B15

QA1

4

QA1

QA5

QA1

1

QA1

0

QA2

Experiment No

Oil

Rec

over

y %

OO

IP

Recovery at 3 different temperatures by volumetric measurement

Recovery at 200 C measured by the weight difference (before and after experimentation)

Swi=0 Swi=0Swi=0 Swi>0 Swi>0 Swi>0TREATED TREATED

INTERNAL DRIVE FORCES47%-16% = 31% - 3% = 28%

Swi Thermal Exp.

Babadagli and Bemani, J. Pet. Sci. and Eng. (to appear)

2007


Main Challenges in Steam Projects and Recent Developments

• Heterogeneous structure that causes early breakthrough of injected steam and uneven distribution of the heat

• A steam project could be viable if the project is designed optimally. This may require advanced technologies to minimize the heat loss either by using a proper tubing design or downhole steam generators

• Downhole steam generators are an option for deep reservoirs and the US Department of Energy supported a project called DEEP STEAM.


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Main Challenges in Steam Projects and Recent Developments

• Horizontal well methods,• Processing steeply dipping reservoirs,• Steam injection followed by waterflooding, or alternating

with other methods,• Steam conformance control,• Cogeneration of steam and power,• Surface distribution and metering of two-phase steam,• Separation and treatment of produced water,• Downhole steam generation,• Insulated tubing,• Multizone steam injection,• Computer simulation of steam injection. Hong [1999]


CRITICAL ISSUES• WASP: Steam injection followed by waterflooding, or alternating

with other methods: To reduce fingering, and improve vertical sweep efficiency

• Downhole steam generation: Two approaches in generating downhole steam exist: (1) Direct, and (2) indirect contact of steam generation.

• Tubing insulation: For the depths greater than 2,500 ft insulated tubings are suggested. Commercially available insulated pipes consist of two concentric API tubulars welded together at the ends. The annular space is filled with low conducting gas (Krypton) or it is evacuated of all gases.

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