CC BY
12
UDC 622.276.6
Increased oil recovery during low-ionic-strength waterflooding in a sandstone core as the result of wettability alteration and fines migration
G. Loi1, C. Nguyen1, A. Al-Sarihi1, V. Akhmetgareev2, A. Badalyan1*, A. Zeinijahromi1, R. Khisamov2, P. Bedrikovetsky1
1 Australian School of Petroleum and Energy Resources, The University of Adelaide, Adelaide, South Australia, 5000, Australia
2 Tatneft PJSC, Bld. 75, Lenina street, Almetyevsk, The Tatarstan Republic, 423450, Russian Federation * E-mail: alexander.badalyan@adelaide.edu.au
Abstract. Authors present the results of the combined effects of fines migration and wettability alteration on enhanced oil recovery during low-ionic-strength waterflood. Production of appreciable amount of additional crude oil during low-ionic-strength waterflood shows its advantage over high-ionic strength waterflood. Adsorption of di-valent Ca2+ and Mg2+ ions presented in high-ionic strength reservoir water onto the surface of kaolinite promoted adsorption of polar oil compounds onto the surface of kaolinite making clay surface more oil-wet during primary drainage. Stripping these di-valent ions during injection of low-ionic-strength water makes kaolinite surface more water-wet and leads to additional oil recovery. Significant amounts of fines in effluents during low-ionic-strength waterflood indicate that fines mobilisation causes permeability decline. Estimated contribution to oil recovery from fines migration is estimated as 8,7 % and from wettability alteration is estimated as 6,7 %.
Low-ionic-strength waterflooding has been successfully employed in the last two decades as a promising low-cost Enhanced Oil Recovery (EOR) method [1]. Several mechanisms are believed to be responsible for this effect. Among them are fines migration, wettability alteration, decrease of a contact angle and interfacial tension, and multi-component ionic exchange between fluid and porous media [2-6].
Numerous coreflood tests showed that decreasing water ionic strength results in lifting and mobilisation of fines which plug pores throats in rocks and, consequently, significantly decrease water relative permeability during low-ionic-strength waterflooding [5, 7-12]. Due to local reduction in rock permeability, water is then re-directed to unswept zones leading to sweep enhancement with production of trapped residual oil. As the result, this oil is pushed-out from the rock, thus increasing oil production.
Surface hydroxyl groups of kaolinite are responsible for its hydrophilic nature [13]. However, kaolinite surface becomes more oil-wet when di-valent ions form high-ionic-strength reservoir water are adsorbed onto its surface. This promotes polar components from crude oil to adsorb onto the surface of kaolinite. Alteration of kaolinite wettability during low-ionic-strength waterflood releases oil films from kaolinite surface and produce additional oil [14]. As the result, kaolinite surface contacts low-ionic-strength water, kaolinite particles mobilize and cause formation damage. Such fines-induced-formation damage in clay-bearing cores often accompanies clay wettability alteration. Therefore, it is very difficult to separate these two mechanisms responsible for EOR.
Bastrikskoye oilfield (Tatarstan, Russia) is characterised by a long history of low-ionic-strength water injection for EOR resulting in relatively low incremental oil recovery of only 1,1 %. This was explained by the production of appreciable volumes of high-ionic-strength Bastrikskoye Reservoir Water (BRW) prior to injection of low-ionic-strength Bastrikskoye Lake Water (BLW), by poor sweep of the central part of the reservoir by injected water. Our previous modelling of this field using a two-layer 5-spot pattern with size 200*200 m during 1400 days showed increase in oil recovery by about 8,7 % if low-ionic-strength BLW is injected from the first days of oil production [15]. This model accounts for fines-migration-induced formation damage and consecutive decrease of relative permeability for
Keywords:
Bastrikskoye oilfield, laboratory coreflood, enhancement of oil recovery, low-ionic-strength water injection, mineralogical analysis and porosity measurement for a core sample, measurement of oil density,
dynamic viscosity and dielectric constant.
water. The model does not account for the effects of wettability changes and decrease of residual oil saturation.
Only very limited information from the field is available. Therefore, significant amount of additional investigations (laboratory coreflooding, X-ray diffraction (XRD) analyses) must be performed for detailed analysis of the Bastrikskoye oilfield case. Therefore, in the present study we investigate the effect of low-ionic-strength water injection on oil recovery from a sandstone core from Bastrikskoye oilfield during two-phase laboratory corefloods.
Materials
Sandstone core. A cylindrical sandstone core from Bastrikskoye oil field with diameter of 3,813*10-2 m imbibed original crude oil. This sample was cut to the length of 8,100*10-2 m. Prior to coreflood tests this sample was cleaned using flowthrough solvents as discussed below.
Fluids. Bastrikskoye crude oil (later in the text referred to as crude oil) was used for coreflood tests. This oil was filtered through 20 ^m stainless steel mesh to remove particulate matter which can block sandstone core pores during corefloods.
Ionic compositions of high-ionic-strength BRW and low-ionic-strength BLW supplied by Tatneft are presented in table. 1. Using molar material balance, we calculated molecular compositions for high-ionic-strength Artificial Bastrikskoye Reservoir Water (ABRW) and low-ionic-strength Artificial Bastrikskoye Lake Water (ABLW) as shown in table 2. In order not to change ionic composition of ABRW and ABLW, no NaOH or HCl were added to the prepared solutions. As follows from these tables the artificial fluids very close match the real ones.
Experimental section
Experimental setup. Schematic and photo of an experimental setup for non-steady-state two-phase coreflood is shown in figure 1. Sandstone core 1 is placed inside a Viton sleeve 2, and is fixed in its position by two stainless steel flow-distributors 3. The entire arrangement is enclosed by a high-pressure stainless steel TEMCO coreholder 4 (model DHCH, 5000 psi maximum pressure, Core Laboratories Inc., USA). A manual pressure generator 5 (model HiP 87-6-5, 5000 psi maximum pressure, High Pressure Equipment Company, USA) compresses distilled water 6 and generates overburden pressure measured by a PA-33X absolute pressure transmitter 7 (KELLER AG fur Druckmesstechnik, Switzerland). Highperformance liquid chromatography (HPLC) pump 8 (Scientific Systems, Inc., USA) delivers brine solutions 9 through a series of 3-port valves 10 and 11 (Swagelok, USA) to the unconsolidated core. A TEMCO high-pressure stainless-steel separating vessel 12 (model CFR-50-100, Corelab, USA) is used to deliver the mineral oil 13 to unconsolidated core. A Teflon piston 14 separates brine/water 9 from the mineral oil. Two PA-33X absolute pressure transmitters 15 and 16 measure respectively inlet and outlet pressure for the unconsolidated core. A back-pressure regulator 17 (model BP-50-SS, Core Laboratories Inc., USA) ensures a smooth operation of the HPLC pump 8 and maintains constant pressure of fluids in the pore network. Compressed air from the cylinder 18 develops the required pressure over the elastomeric diaphragm of the back-pressure generator. Differential pressure across the unconsolidated core is measured by four differential pressure transducers (DPTs) 19...22 (models DP15-30,
Table 1
Average values of ionic compositions for BRW and BLW
Property BRW BLW
Density, kg/m3 1160 1030
pH 6,3 7,5
Ionic strength, g/l 244,5 0,85
chloride 147500 210
sulphate as SO42- 600 110
Substance bicarbonate as HCO3- 55 280
content, mg/l calcium 13000 100
magnesium 3150 35
sodium 75088 113
Table 2
Molecular composition of ABRW and ABLW
Property ABRW ABLW
pH 7,26 7,32
Ionic strength, g/l (mol/l) 239,4 (4,63) 0,848 (0,018)
Electric conductivity, mS/cm 211 1,027
Salt content, g/l NaCl 190,82 0,020
MgCl2 11,74 0,028
MgSO4 0,752 0,138
CaCl2 36,00 0,277
NaHCO3 0,076 0,385
1 2 6
f ( ^DO г—ПШПп
/ I J mm ОЭ - '
30
Waste Y
Fig. 1. Schematics (a, green colour denotes open valves; red colour denotes closed valves) and photo (b)
of the experimental setup
7
DR15-40, DP15-50 and DP15-60, respectively, Validyne Engineering, USA) with the following measuring ranges, psi: 0...1,25; 0...12,5; 0...125 and 0.1250. All DPTs are re-zeroed using equilibration three-way manual valves 23.26 prior differential pressure measurements. All information form pressure transmitters and DPTs is transmitted to a real-time data acquisition system consisted of ADAM-4019+ data acquisition module 27 (ADVANTECH™, Taiwan), ADAM-5060 RS-232/RS-485/RS-422 signal converter 28 (ADVANTECH™, Taiwan), and a standalone personal computer 29. Custom built software based on ADVANTECH ADAMView Ver. 4.25 application builder (ADVANTECH™, Taiwan) performs necessary calculations, and via dynamic data exchange server delivers values of differential pressures and fluid viscosity in real-time to Microsoft Excel™ file which incorporates all corresponding calculations and graphs. A fraction collector 30 (GE Healthcare Life Sciences Pty. Ltd., Australia) is used
to collect effluent suspensions in centrifuge 15 ml and 50 ml plastic tubes 31. Suspended particle concentrations (in ppm v/v) in effluent fluid samples were measured by two instruments 32: PAMAS 4031 GO portable particle counter (PAMAS, Germany; later in the text referred to as PAMAS) and POLA-2000 particle size analyser and counter (Particle & Surface Sciences Pty. Limited, Australia; later in the text referred to as POLA).
Core preparation. Supplied core imbibed crude oil from Bastrikskoye oil field. This core needs to be cleaned from this dried crude oil and saturated with the same oil prior to coreflood tests.
There are three common methods currently used in laboratories for core cleaning from crude oils, namely, Soxhlet extraction, total immersion Soxhlet extraction and solvent flush cleaning [16]. Since the last method ensures better penetration of solvents into a core, although at time expense, the solvent flush cleaning method was utilised in this project.
Procedure for core cleaning is very similar to that used in the traditional non-steady state two-phase coreflood technique. The only difference is that an appropriate solvent is filled into the separating vessel located between an HPLC pump and a coreholder with the purity of the effluent from the core being monitored/recorded by an UV-Vis spectrophotometer. In this arrangement, the GENESYS 10S UV-Vis spectrophotometer is used instead of a sampling carousel and a portable particle counter/sizer (see fig. 1b).
Initially, the core was placed in the coreholder, and overburden pressure of 1000 psi was developed. Backup pressure was kept at about 230 psi. Then, the first non-polar solvent (toluene) was filled into a separating vessel. Two separate tests were run to determine at which optical wavelength pure toluene gives maximum absorption: scans were run in 190-to-1100 and 250-to-350 nm wavelength ranges (figure 2, see a). The first test determined approximately the location of the maximum light absorption, whereas the second one more accurately determined that the maximum light absorption corresponded to 297,2 nm wavelength. This wavelength is in ultraviolet region. This value was set on the spectrophotometer, and it was re-zeroed during flow of pure toluene through a flowthrough quartz cell of the spectrophotometer. Then, the HPLC pump started to pump water into the separating vessel with volumetric flowrate of 0,5 ml/min corresponding to 7,30*10-6 m/s superficial velocity. This value of superficial velocity is approximately 4-times lower than
expected superficial velocity of 2,91*10-5 m/s during future two-phase coreflood. Such low solvent velocity prevents fines from mobilisation. Teflon piston located in the separating vessel started to push toluene through the core. Red filled circles in figure 2b show the decrease of UV-light absorbance with pore volume injected (PVI). Toluene injection stopped after light absorbance dropped down to 0,013. This means that toluene removed almost all non-polar crude oil components from the core.
Similar procedure was repeated for isopropyl alcohol (maximum UV absorbance is at 205 nm) and methanol (maximum UV absorbance is at 220 nm). Isopropyl alcohol is miscible with toluene in all ratios; however, methanol is miscible with toluene in ratios up to 0,8. Therefore, to completely remove non-polar toluene from the core, isopropyl alcohol which is also less polar than methanol is needed. The need for polar methanol is because isopropyl alcohol is not miscible with salt solutions (NaCl, KCl, etc.). Therefore, one will not be able to completely remove isopropyl alcohol from the core by aqueous 0,6 M NaCl solution during core saturation after its cleaning from crude oil by solvent. For this reason, these solvents are used for core cleaning in the following order: toluene, isopropyl alcohol, and methanol. Isopropyl alcohol injection stopped after light absorbance dropped down to 0,018, and methanol injection finished at 0,017 absorbance. Initial increase of UV absorbance at the beginning of injection of isopropyl alcohol and methanol
/
Í
Wavelength range, nm: — 190...1100 — 250...350 i i
Я 1,0
§
0,6
0,4
0,2
1 = toluene isopropyl alcohol methanol
\ 1
■
1 |
4. k V -J k
290 295 300 305 310 0 100 200 300 400 500
Wavelength, nm PVI
a b
Fig. 2. Two UV-Vis scans for pure toluene (a) and a pattern for successive core cleaning
by various solvents (b)
0
is a sure indication of the presence of polar components in the studied crude oil.
Core cleaning from crude oil with solvents should be followed by its saturation with ABRW. However, if after coreflood with methanol the core is saturated with ABRW then precipitation of salts may occur. Therefore, coreflood with methanol was followed by core saturation with 0,6 M NaCl solution with superficial velocity of 7,30*10-6 m/s for the duration of about 80 PVT. After that, the core was saturated with ABRW with the same superficial velocity for the duration of about 20 PVT. Finally, two-phase tests started with the injection of ABRW with superficial velocity of 2,92x10-5 m/s.
Core porosity measurement. After core-cleaning procedure, the sandstone core was saturated with ABRW. For this reason, it was not possible to measure its porosity by imbibition method, because it needs to be dried before these measurements. Additionally, this sample of sandstone looked like it can be easily disintegrated. To circumvent this problem, a small leftover piece of this sandstone of 5 mm thick and the same diameter as the original core was cleaned consecutively in toluene, isopropyl alcohol and methanol and being dried in atmospheric oven at 60 °C for 24 hours and in vacuum at residual pressure of 1,5 Pa for 12 hours. Due to irregular shape of this sandstone piece it was impossible to use Helium adsorption porosimetry technique to measure this sample's porosity. Instead, we used a weighing/imbibition method by measuring dry, wet and apparent masses, and pore and bulk volumes of this sandstone piece. Five independent measurements of sandstone sample porosity were performed.
Density, dynamic viscosity and dielectric constant of oil. Density of crude oil was measured by measuring masses of fixed volumes of crude oils. Volumes of crude oil were measured by an APPENDORF Research 5000 ^L pipette (random measurement error is ±0,6 %, and systematic measurement error is < 0,15 %). Masses of fixed volumes of crude oils were measured by an analytical balance (Model AB204-S, MettlerToledo Ltd., Switzerland) with both readability and repeatability equal to 0,1 mg. Measurements were carried at temperature of 22,0 ± 0,2 °C.
Dynamic viscosity of the crude oil in the temperature range from 20 to 25 °C was measured by a rheometer (model MCR301, Anton Paar Germany GmbH, Ostfildern, Germany). The
obtained data were interpolated by a linear relationship, and dynamic viscosity values calculated for 22,0 °C. These data were used to calculate end-point core permeabilities at the completion the two drainages.
Dielectric constant of the crude oil was measured using a capacitor made of two stainless steel co-axial cylinders with the following dimensions: diameter of the inner solid cylinder is equal to 25,89 mm, internal diameter of the outer cylinder is equal to 37,97 mm, the lengths of both cylinders are equal to 50,02 mm. LCR meter (model 9053, ISO-TECH) was used for capacitance measurements in the range from 0 to 2 nF.
XRD analysis. Mineralogical analysis of the cleaned and dried sandstone core was performed by quantitative XRD analysis using Bruker D8 Advance Powder X-ray Diffractometer with Cu-radiation source (Bruker Corporation, Germany). Bruker DIFFRAC.EVA software was used to process experimental data, and Crystallography Open Database reference patterns were employed to identify mineral phases. Quantification was carried out against an internal standard of zinc oxide at 10 % using RockJock software.
Experimental procedures. Saturation of a porous medium was achieved by pumping ABRW solution using the HPLC pump at low superficial velocity of 2,92*10-5 m/s (corresponding to volumetric flowrate of 2 ml/min) to avoid mobilisation of clay particles. This superficial velocity is in the range of velocities experienced in the close vicinity to wellbores. Backup pressure was kept at 320 psi.
The experimental procedure for two-phase corefloods is presented in table 3. Fractional oil and water volumes in the collected effluent tubes were determined after centrifugation and were used to calculate PVI during corefloods and for calculation of effluent fractional oil and brine volumes.
Results and discussion
XRD mineralogical composition. Mineralogical composition, %, of the studied sandstone showed the following results: quartz - 89,5; pyrite -0,4; zincite - 8,9; kaolinite - 1,2. This core is characterised by a relatively low kaolinite concentration.
Physical properties of crude oil. Calculated value of oil density is equal to 849,4 kg/m3. The
Table 3
Experimental procedure
Injection number Injecting fluid Duration of injection, PVI Number of samples Calculated parameter (see formulas (5), (6))
0,042 PV (1 ml) 0,422 PV (10 ml) 2,109 PV (50 ml)
1 ABRW 95 50 20 40 N/A
2 Crude oil 10 50 20 N/A ^wi,
Core ageing for 3 weeks at final experimental conditions (22 °C and 320 psi)
3 ABRW 95 50 20 40 ^or,
4 Crude oil 10 50 20 40 Swi2
If Sw-h = Swi] within experimental uncertainty, then inject low-ionic-strength fluid (ABLW). If Swiz ^ Swi] within experimental uncertainty, then inject high-ionic-strength fluid (ABRW)
5 ABLW 95 50 20 40 Sor,2
6 DI-water 95 50 20 40 Sor,3
obtained value of dynamic viscosity is equal to 0,0444 Pas. Dielectric constant is equal to 2,12.
Initial single-phase coreflood. Imbibition porosity of the core was equal to 25,6 %, and calculated pore volume was equal to 23,712 cm3. This value was used to calculate PVI during corefloods. Undamaged core permeability 1178,9 ± 22,2 mD was calculated after initial single-phase coreflood with ABRW for the duration of about 95,5 PVI as shown in figure 3. Fluctuation of core permeability was characterised by its standard deviation of 1,9 %, which is within experimental uncertainty 3,2 % for core permeability measurements.
DLVO kaolinite-sand interaction.
According to the DLVO1 theory, the total particle-wall interaction potential energy, Vtot, is equal to the sum of interaction potential energies arising from the attractive long-range (10 nm < h < 100 nm) London - van der Waals (LW) [17], the short-range (0,2 nm < h <10 nm) attractive/repulsive electrical double layer (EDL) [18, 19], and Born repulsion (BR) interactions [18-20] as follows:
Vot = Vw + VEDL + VBR;
V =-
r LW
A132 Г1Г2
6h(rl + r2)
, 5,32h, i X 1 —'-In I 1 + -
5,32h,
(1)
; (2)
1600
Ö 1400
см
1200
1000
V = 128ЛГ1ГПkT у у e-h .
EDL , ч 2 1П 2 '
(rl r2) к
V _
V R
7560
8r + h 6rl - h
(2rl + h)7 h7
(3)
(4)
0 20 40 60 80 100
PVI
Fig. 3. Undamaged core permeability as function of PVI
where kB = 1,380649x10 23 JK1 - Boltzmann constant; T - absolute temperature, K; VLW, VEDL, VBR are LW, EDL and BR potential energies, kBT, respectively; ^132 stands for Hamaker constants, J, for kaolinite-electrolyte-sand system [17]; rl, and r2 are mean-volume radii, m, of kaolinite particles and sand grains; h is particle-surface separation distance, m (h << r^; « = 6,022*1025 number/m3 is bulk number
density of ions; ^ and are zeta potentials, V,
for particles and walls; = tanh
v4kBTy
and
1 Named after Boris Deryaguin and Lev Landau, Evert Verwey and Theodoor Overbeek.
у 2 = tanh
4кнГ
are reduced surface potentials
for pairs particle-particle and particle-wall [19]; z is valence of a symmetrical electrolyte solution, z = 1 for NaCl; e = 1,602x10-19 C is the elementary electric charge; k is the Debye-Huckel parameter, m-1; X = 100 nm is the characteristic wavelength of the interaction [18]; cc = 0,5 nm is the typical value for the collision diameter [19].
Particles are attracted to sand grain surface when attractive LW force is greater than the sum of repulsive EDL and BR forces resulting in the negative sign for Ftot and vice versa [21]. The inverse of the Debye-Huckel parameter k-1 (the so-called Debye length) determines the EDL thickness. Kaolinite particles are attracted to sand grains during injection of ABRW due to significant negative DLVO potential of interaction about -1766 kBT with EDL thickness 0,08 nm (figure 4). Injection of ABLW with ionic strength 0,02 M results in the upward shift of Ftot, expansion of EDL to 2,26 nm, repulsion between kaolinite particles and sand grains, and mobilisation of kaolinite particles. Expansion of EDL leads to two processes which occur during gradual decrease of ionic strength of injecting water: firstly, repulsion between kaolinite surface and adsorbed polar components of crude oil which results in wettability alteration, desorption of these oil components and additional oil production, and, secondly, repulsion
к
I, л — ABLW — ABRW
V/ Л s
У z'
-2
h, m
Fig. 4. DLVO total potential of interaction between kaolinite and sand for high- and low-ionic strength injected fluids
of kaolinite particles from sand grains, their mobilisation and consecutive formation damage. Careful adjustment of water ionic strength allows the first mechanism to occur without activation of the second one.
Effluent particle concentration, size and pH of effluent suspensions
Significant higher effluent particle concentrations (ceff.p) are associated with injection of ABLW water compared to those during ABRW injection (figure 5) and cause formation damage. Effluent pH was almost stable during ABRW injection (see fig. 5a) and increased from 7,32 to 8,81 during injection of ABLW, due to exchange of H+ ions from injected ABLW with adsorbed di-valent Ca2+ and Mg2+ ions (see fig. 5b).
Volume-mean particle sizes (ds) in effluent fractions don't depend on ionic strength of injected fluids and agree with "1/3.. ,1/7"-rule of deep-bed-filtration: particles with jamming ration factor < 1/7 move through a porous medium without being captured. However, injection of each consecutive fluid decreased core permeability due to mobilisation of fines and capture of particles with sizes corresponding to jamming rations greater than 1/7 (table 4).
Sequential two-phase corefloods
Initial brine (water) and residual oil saturations, Swi and Sor, respectively, are calculated as follows:
S„„ = 1 —
Vе'
F
and S„r = 1 - SF-
Va
F„
(5)
(6)
where Focum is cumulative produced oil volume, m3; Fwcum is cumulative brine volume, m3; and Fpore is core's pore volume, m3. Reliable comparison of oil production during ABRW (high-salinity) and ABLW (low-salinity) corefloods can be carried out if the core can be brought to the same initial condition after the second drainage: Swi2 = Swi, i.e. when initial water saturations after 1st and 2nd drainages are equal. Taking into an account that experimental uncertainty for initial water saturation is equal to wcvol(Swi) = 0,011, agreement between Swi2 and Swi is good and « 5,1 % (table 5).
Volumes of oil and water during two-phase coreflood experiments are used to calculate oil and water saturations.
4
2
0
В 2,5 &
2,0
I 1'5
1,0
0,5
fl
j
IlLk^
В 16
ft ft
I 12
20
40
60
80
20
40
60
80
7,5 %
7,4
7,3
7,2
7,1
100 PVI
7,0
—1-
A
Li ssJ\. /V
11®
а
3 100 PVI
Fig. 5. Variation of effluent particle concentration and pH of effluent suspensions: injection of ABRW (a) and ABLW (b)
Table 4
Consecutive injection of fluids: effluent particle size, core permeability and pH of fluids
Injected fluid ds, mm Jamming ration, J Permeability, mD pH variation: injected / effluent
1. ABRW 2,30 0,12 1178,9 7,26 / 7,22
2. Crude oil N/A N/A 978,8 N/A
3. ABRW 2,23 0,10 285,1 7,26 / 7,46
4. Crude oil N/A N/A 791,9 N/A
5. ABLW 2,28 0,11 136,7 7,32 / 8,81
6. Deionized (DI-) water 2,49 0,12 145,0 7,03 / 5,23
Variation of pressure drop (AP) across the core during primary and secondary drainages is shown in figure 6. Stabilisation of AP across the core starts after about 3 PVI during drainages, which is explained by the absence of ABRW and ABLW in the effluent samples after about 3 PVI.
Pressure drops across the core during flooding with ABRW and ABLW are shown in figure 7. In this case, it takes about 34 and 20 PVI for pressure drop across the core to stabilise during injections of ABRW and ABLW, respectively.
a
0
0
9
8
7
b
5
4
0
0
Table 5
Results of sequential two-phase corefloods
Injected fluid Swi Sor Relative permeability Corey exponent
for water at oil residual* (kfj for oil at initial water saturation** (k0re^) water («w) oil («o)
Crude oil 0,118 N/A N/A 0,849 2,0 1,5
ABRW N/A 0,221 0,247 N/A
Crude oil 0,124 N/A N/A 0,687 2,5 1,2
ABLW N/A 0,077 0,119 N/A
DI-water N/A 0,016 0,126 N/A N/A N/A
' Measured at the end of ABRW/ABLW injection when pressure drop across the core is stabilised. '* Measured at the end of oil injection when pressure drop across the core is stabilised.
20
15
10
0
30 25 20 15 10 5 0
9 12
PVI
6 9 12 0 3 6
a b
Fig. 6. Variation of pressure drop across the core during primary (a) and secondary (b) drainages
■й 20 л
15
10
0
L
■й 20 ft
15
10
0
100 0 20 40 60 80 100 PVI , PVI
0 20 40 60 80
PVI
a b
Fig. 7. Variation of pressure drop across the core during flooding with ABRW (a) and ABLW (b)
5
5
5
1,0
л
1ч
Рч
0,6
0,4
0,2
0 сгаоо
0 0,4 0,8 1,2 1,6 2,0
PVI
1,0
О S3 О
О
S3
Рч
0,6
0,4
0,2
0 агоооо
О
3 CP о I ° ОЭ
f ° 1 °
о
3
0 0,4 0,8 1,2 1,6 2,0
PVI
1,0
о а о
о л
1ч
Рч
0,6
0,4
0,2
/ fr\I / //1/ Г ШШ г и я
/ r / r / r A / ГЖ — ABRW ABLW
0 0,2 0,4 0,6 0,8 1,0
S
Fig. 8. Fitting water cut experimental data to mathematical model during ABRW (a) and ABLW (b) corefloods, fractional flow curves (c)
Oil (koel) and water (kwel ) relative permeabilities were calculated using Corey's correlation:
(1 - - S,„ Y
klei = k
k = k"
\ 1 Sor SW1 J
Sw SW1
V 1 _ Sor _ Swi J
(7)
(8)
where Sw is water saturation.
Experimental water cut data during ABRW and ABLW injection were fitted with the model by changing no and nw as shown in figure 8. Water cut is observed at around 0,72 (see fig. 8a) and 0,65 (see fig. 8b) at breakthrough times during injection of ABRW and ABLW, respectively. Water breakthrough during ABLW is observed later than that during ABRW. Shift of fractional flow curves to the right is an indication of fines migration and wettability alteration effects on enhanced oil recovery (see fig. 8c).
The history matching approach is used to construct relative permeability curves during injection of ABRW and ABLW. The critical parameters which define the success of this matching are exponents nw and no. The obtained results are presented in figure 9 (see a). Phase relative permeability curves to oil and water during injections of ABRW and ABLW were calculated after history matching. An increase in oil relative permeability after 0,3 water saturation is observed when low-ionic strength water is flooded compared to high-ionic strength water coreflood (see fig. 9a). There is a reduction in residual oil saturation from 0,221 to 0,077 during injection of ABLW (see table 5). This is equivalent to the increase of oil recovered (RF) from 64,2 % (injection of ABRW) to 79,6 % (injection of ABLW). The results also show a significant decrease of relative permeabilities from 0,247 to 0,119 during injections of ABRW and ABLW, respectively. This permeability damage is caused by mobilisation of the reservoir fines during injection of ABLW. Additional 3,4 % of oil were recovered during DI-water coreflood.
Our previous modelling studies on Bastrikskoye oilfield showed about 8,7 % of additional oil recovery due to injection of BLW due to fines-migration-induced formation damage and consecutive decrease of relative permeability for water. Taking onto an account that during present laboratory study the combined effect from fines migration and wettability alteration on oil
a
b
c
0
ä 1,0
0,8
0,6
0,4
0,2
0 0,2 0,4 0,6 0,8 1,0
S™
— ABRW _ — ABLW — DI-water 1 1
6 b
10 12 PVI
Fig. 9. Phase relative permeabilities (a) and oil recovery factor (b) for corefloods with ABRW and ABLW
0
0
recovery is 15,4 %, we estimate contribution
of wettability alteration as 6,7 %.
***
Analysis of laboratory data on two-phase corefloods with high-ionic-strength artificial reservoir water and low-ionic-strength lake water together with mathematical modelling using Corey correlations allow drawing the following conclusions:
• advantage of low-ionic-strength waterflooding over high-ionic-strength one is supported by almost three-fold decrease in residual oil saturation during injection of low-ionic-strength water, which translates to about 15,4 % of additional oil production;
• since the above 15,4 % of additional oil production are the result of combined effects of fines migration and wettability alteration, the estimated contribution from fines migration is 8,7 % from our previous modelling studies, and 6,7 % from wettability alteration;
• injection of Dl-water further increased oil production by about 3,4 %;
• increase of pH of effluent water samples during low-ionic-strength waterflooding indicates to replacement of di-valent ions Ca2+ and Mg2+ by protons H+;
• stripping these di-valent ions during injection of low-ionic-strength water makes kaolinite surface more water-wet and leads to additional oil recovery;
• expansion of EDL also leads to additional oil recovery;
• decrease of water relative permeabilities during low-ionic-strength waterflooding is a sure indication of core wettability alteration towards the more water-wet state; and
• mobilised fines cause core damage.
Overall, it is still difficult to determine the
degree of contribution of various mechanisms associated with low-ionic-strength waterflooding to EOR.
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Повышение нефтеотдачи при низкоминерализованном заводнении в керне-песчанике как результат изменения смачиваемости и миграции мелкодисперсных частиц
Г. Лой1, К. Нгуен1, А. Аль-Сарихи1, В.В. Ахметгареев2, А.Г. Бадалян1*, А. Зейнижахроми1, Р. С. Хисамов2, П.Г. Бедриковецкий1
1 Австралийская кафедра нефти, газа и энергетических ресурсов, Университет Аделаиды, Австралия, 5000, г. Аделаида
2 ПАО «Татнефть», Российская Федерация, 423450, Республика Татарстан, г. Альметьевск, ул. Ленина, д. 75
* E-mail: alexander.badalyan@adelaide.edu.au
Тезисы. Представлены результаты исследований комбинированных эффектов увеличения нефтеотдачи пластов, таких как миграция пластовых мелкодисперсных частиц и изменение смачиваемости поверхности пор за счет низкоминерализованного заводнения. Получение значительного объема дополнительной нефти (15,4 %) в ходе низкоминерализованного заводнения указывает на его преимущество перед заводнением высокоминерализованной водой. Во время высокоминерализованного заводнения двухвалентные ионы Ca2+ and Mg2+, присутствующие в высокоминерализованной пластовой воде в относительно высоких концентрациях, адсорбируются на поверхности каолинита, покрывающего поверхность пор. Это способствует адсорбции полярных компонентов нефти таким образом модифицированной поверхностью каолинита, превращая последнюю в преимущественно гидрофобную во время первого дренирования. Замещение этих двухвалентных ионов протонами из закачиваемой низкоминерализованной воды преобразует поверхность каолинита в преимущественно гидрофильную, что способствует дополнительной нефтеотдаче. Значительное количество мелкодисперсных частиц в выходных фракциях указывает на снижение проницаемости керна из-за мобилизации этих частиц. Вклад в дополнительную нефтеотдачу со стороны мобилизации мелкодисперсных частиц составляет 8,7 %, а со стороны изменения смачиваемости керна - 6,7 %.
Ключевые слова: Бастрыкское нефтяное месторождение, увеличение нефтеотдачи пласта, заводнение керна, низкоминерализованное заводнение, измерение пористости керна, измерение плотности, динамической вязкости и диэлектрической проницаемости нефти.
