Lab scale co-injection of gas and surfactant in presence of oil

Transcription

1 Lab scale co-injection of gas and surfactant in presence of oil Dag Wessel-Berg, Sintef Petroleum Research Dennis Coombe, Computer Modeling Group Arne Stavland, IRIS Arild Moen, Statoil Bård Bjørkvik, Sintef Petroleum Research

2 Outline Experimental work Background Co-injection with no oil and varying salinity Co-injection with presence of oil Modeling and simulation Present foam option in STARS Proposed modifications Simulation of experiment Conclusions

3 Experiments Co-injection of gas (CH 4 ) and surfactant (C 12 AOS) at 90 C, pressures 100Bar and 300Bar with salinities 1% and 7%. Foam qualities from 65% and up (IRIS). Low pressure co-injection of gas (N 2 ) surfactant (C 14 AOS) with presence of oil having varying composition of n-decane and acetophenone. Salinity 3.5% (Sintef and IRIS). Core 0.5m long, 2 pore volumes per day injection rate. IFT measurements (Sintef).

4 Experimental setup for co-injection

5 2-phase co-injection with increasing foam qualities

6 Would be nice... Are (cheap) measurements of interfacial tension (IFT) sufficient for assessing foam strength for a given system? I.e. is it possible to get away without more expensive core floods?

7 Measured gas/water IFT p = 10 bara p = 100 bara p = 300 bara p = 600 bara 20 IFT, mn/m Salinity, wt %

8 Pressure drops Foam strength decreases with pressure, increases significantly with salinity

9 Relative permeabilities Total mobility is very low for co-injection

10 Co-injection total mobility At constant foam quality (co-injection)one has λg 1 Γ Γ= λw = λg λ + λ Γ Total mobility is dictated by gas mobility g w 1 Γ λt = λg + λw = λg 1+ = Γ λ g Γ How informative are co-injection experiments for a FAWAG?

11 Main conclusion for 2-phase experiments Increased salinity makes the foam significantly stronger. Field scale fresh water foam injection to improve injectivity...?

12 Second experimental run: Co-injection with presence of oil Using a synthetic n-decane/acetophenone oil of varying composition at low pressure and temperature. Check how combinations of the measured interfacial tensions correlate to foam strength.

13 Entering coefficient

14 Negative entering coefficient means stronger foam?

15 Spreading coefficient and bridging number B = σ + σ σ > wg ow og Oil droplet bridges across interface degrading the foam

16 Miscellaneous parameters versus oil composition E = σow + σwg σog > S σ σ σ 0 oil / water = wg ow og > 0 B = σ + σ σ > ow wg og 0 Positive values means weaker foam?

17 Appearent gas viscosity Apparent viscosity Foam quality (%) ref decane acetoph 80/20decane/acetoph 50/50decane/acetoph Ranks fairly well with previous slide. Foam in pure acethophenone system stronger than 2-phase reference

18 Ageing effect of oil on foam 80% acetophenone 100% n-decane

19 Conclusions for co-injection in presence of oil Entering coefficient and bridging number rank fairly well to foam strength. Ageing effect on foam strength is significant.

20 Modeling Present STARS foam option Discussion of proposed modification for accommodating oils influence on foam strength Validation of new formulation

21 Pressure drop profile in present STARS foam option Dp 2-phase: An immediate pressure buildup occurs when gas enters. Generally not the case when oil is present. Time

22 Critical water saturation S wd k rg Gas relative permeability for gas/surfactant system Dry regime Wet regime (strong foam) S wc S wd Critical water saturation S w

23 Present STARS foam option In STARS one interpolates between two sets of relative permeabilities, one relative permeability table for a foam free system, and one table for maximal foam strength.

24 Present STARS foam option, cont. Mobility reduction factor MRF 1 = 1 + f H c, N, S, ( S ) m o w ε ε c N o c N S o 1 1 H( c, N, So, Sw) = arctan * * * + ( D( Sw SwD) ) c N So 2 π ε Dryout

25 Saturation path and ageing Oil: 80% acetophenone 20% n-decane Saturation path at 65% foam quality

26 Hypothesis As oil is displaced by gas from S orw to S org the foam builds in strength caused by the decreasing oil saturation.

27 Proposed generalization for handling the effect of oil on dryout k rg ( ) ( 1 ) S S S S o org wd o = wd + wd Sorw S org S S 1 1 Dryout factor = + arctan( D S S S 2 π α ( w wd( o) ) Decreasing oil saturation α Just one additional parameter,, to adjust critical water saturations dependency on oil saturation. S wd (S org ) S wd (S o ) S w

28 Foam strength in ternary diagram Foam strength S96 S91 S86 S81 S76 S71 S66 S61 S56 S51 S46 S41 S36 Oil saturation S S S S S11 S S1 Water saturation

29 Saturation path

30 Simulation of ageing effect 80% acetophenone, 20% n-decane oil. Foam quality 65% Alpha=2 gives a near perfect match

31 Flow of oil The oil relative permeability dictates, together with value of alpha, how fast the foam builds in strength. ( ) ( 1 ) S S S S o org wd o = wd + wd Sorw S org S S α

32 Oil rate Oil drains from S orw =0.255 to S org =0.179 at constant rate during 65% foam quality period The match is fair

33 Additional STARS implementations Simulatanous effect of foam and surfactant drainage of oil. Critical water saturation depends on capillary number. Foam strength dependence on salinity.

34 Conclusions Experiments show that foam strength increases significantly with salinity. IFT data for three-phase system rank fairly well with foam strength. Flow experiments needed to assess absolute strength of foam. Co-injection experiments not necessarely the best for FWAG A new foam option implemented in STARS Presence of oil gives an ageing effect on foam strength. New formulation matches core experiment. Shape of foam gas relative permeability and field scale...

35 Shape of foam gas relative permeability, what does it mean? Slope of dryout Strength of wet foam Critical water saturation All mean something for field scale simulation of foam behaviour!