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Smart water flooding
Transcript of Smart water flooding
Use the energy stored in the reservoir
Pressure support by injection fluids already present in the reservoir
Water injection (formation water or water available)
Injection of fluids/chemicals not initially present in the reservoir.
Chemicals: Polymers; Surfactants; Alkaline; etc.
“Smart water” to impose wettability alteration In the last decade, high salinity water flooding has been emerged as a prospective EOR method for chalk reservoirs.
Saudi Aramco reported significant increase in oil recovery by low salinity water flooding in Saudi Arabian carbonate reservoirs.
In this presentation we studied crude oil/seawater ions interaction at different temperatures, pressures and sulfate ion concentrations.
For low salinity waterflooding, flooding experiments were carried out initially with the seawater and after wards with diluted sea water. Introduction All formation water contains dissolved solids –primarily sodium chloride NaCl
Common cations –Na+, Ca++, Mg++, sometime K+, Ba++, Li+, Fe++, Sr++
Common anions –Cl-, SO4-, HCO3-, sometimes CO3-, NO3-, Br-, I-, BO3---, S- Composition of Oil Field Water Our results show that sulfate ions may help decrease the crude oil viscosity when high salinity brine is contacted with oil under high temperature and pressure .
We propose that the decrease in viscosity and formation lead to increase in oil recovery with sulfate ions at high temperature in chalk reservoirs.
More than half of the world oil is found in carbonate formations (chalk and limestone) .
High salinity seawater flooding in high temperature chalk reservoirs and low salinity water flooding in sandstone reservoirs are two examples of smart water flooding. Laboratory water flood and successful field tests have showed that low salinity water flooding can improve the oil recovery in sandstone reservoirs .
However, low salinity effect has not been thoroughly investigated for carbonates.
Contrary to these results, Saudi Aramco reported 16-18 % OOIP increase in oil recovery by low salinity waterflooding in composite rock samples from Saudi Arabian carbonate reservoirs. Experimental We used three natural crude oils from different parts of the world: Middle East-1 crude oil; a Latin American crude oil and Middle East-2 crude oil.
The synthetic brine solutions were prepared by adding different amounts of NaCl, NaHCO3, KCl, MgCl2.6H2O, CaCl2.2H2O and Na2SO4 to the distilled water. Seven brine solutions with different sulfate concentrations were prepared for crude oil/brine interaction study. Brine Solution Three core plugs from Middle East reservoir were used in the experiments.
The detailed properties of the core plugs used in this study are given in Table 4. Core plugs This is a high pressure cell allowing measurements for up to 700 bar and 180 ˚C Crude Oil/Brine Interaction in DBR PVT JEFRI Cell The entire PVT cell is installed on a rocking mechanism inside a temperature controlled forced air oven in the so-called air bath. The arrangement of the entire JEFRI cell in its rocking mechanism and inside the oven is showed in Figure 2. The core plugs were cleaned by flooding toluene and then with ethanol. After cleaning, the core plugs were dried in an oven at 90 ºC to constant weight. The dried core plugs were saturated with FW under vacuum and allowed 3 days to get ionic equilibrium between ions and rock
Core Preparation and Flooding Schemes
NMR experiments were performed to study the effect of ionic composition on the rock samples. All the core plugs with connate water saturation were first flooded with SSW and then sequentially with low salinity brines LS-2, LS-10 and LS-20. NMR scan was performed at different stages for two of the flooding tests. Laboratory NMR Tests
( Nuclear Magnetic resonance )
. The photographs taken of the various crude oil and brine systems are shown in Figures 3, 4, 5 and 6. Comparison of Figures 3 and 5, as well as Figures 4 and 6 clearly shows that increasing the temperature results in de- emulsification of the crude oil in almost all cases. Results and Observations A preliminary flooding test was carried out with core THB 6-26 at room condition. First, SSW was injected at an injection rate of 0.1cc/min. When the production stopped, injection rate was increased to 0.5 and finally to 1cc/min to make sure that there is no mobile oil. As shown in Figure 11a, 27.14% OOIP (original oil in place) was recovered at an injection rate of 0.1cc/min. 21.85 % OOIP oil was produced before the water breakthrough (WBT). Oil recovery after WBT resulted in a considerable increase in recovered oil (5.29 % OOIP). Increasing the injection rate to 0.5 and 1 cc/min produced additional 8.16 % and 1.95% OOIP oil, respectively. Increase in oil recovery with low salinity brine and the pressure profiles are consistent with the previous test where THB 6-28 core plug was used. As shown in Figure 15a, 30.7% OOIP was recovered with SSW injection. On the second step, injection of LS-2 resulted in a final oil recovery of 41.5% OOIP (10.7% OOIP additional oil). We observed that viscosity of Latin American crude oil in contacted with brine solution decreased with the increase in sulfate concentration at high temperature and pressure condition.
The effect on viscosity is relatively small. When acidity of the solution changes the molecules of the polymeric acid may dissociate. The segments of such molecules become negatively charged and repel from each other.
This mechanism looks reasonable because we have observed decrease in viscosity only in the case of Latin American crude oil whose asphaltene content is three times higher than of the Middle East crude oil where we did not observe any decrease in viscosity
It has been established that seawater is an excellent EOR fluid for chalk reservoirs at high temperature Discussion A significant increase in pressure drop across the Middle East reservoir core plugs was observed with the decrease in the salinity of injecting. This increased pressure drop could be attributed to the migration of fines.
This could be a possible mechanism for observed increment in oil recovery in the Middle East reservoir core plugs.
Thus, microscopic migration of fines probably does not always results in additional recovery.
This indicates that rock dissolution may also be the possible mechanism for recovery increment. The fact that one of the core plugs was damaged (THB 6-28, see Figure 16) in the experiment also confirms the combined fine migration and dissolution effects as a possible reason for additional recovery. Saudi Aramco reported significant increment in oil recovery with low salinity brines from the Saudi Arabian carbonate reservoirs (Ali et al. 2011). Wettability alteration was reported as a driving mechanism for substantial increase in oil recovery. This was indicated by apparent shift in the position of T2 distribution between NMR results before and after injecting different salinity slugs of seawater. However, in our study no apparent shift in T2 distribution peak was observed in any of the tests.
The chemical mechanism behind this increment was claimed to be the same as previously reported for the seawater flooding in chalk reservoirs (sulfate ions adsorb to the rock surface, which changes the surface charge so that the adsorbed crude oil may be removed from the rock).
1. The DBR JEFRI PVT cell high-pressure studies show that an increase in temperature de-emulsifies crude oils in all cases.
2. The viscosity of the Latin American crude oil was significantly reduced after interacting with sulfate ions at high temperature and pressure conditions in the DBR JEFRI PVT cell. A trend of decrease in viscosity with the increase in sulfate concentration was observed.
3. No low salinity effect was observed from Middle East reservoircore plug at room temperature.
4. A substantial increase in oil recovery was achieved with diluted versions of sewater from Middle East reservoir core plugs at 90 °C. Conclusion 5. NMR measurements indicated that low salinity brines did not significantly change the surface relaxation of both used carbonate rocks.
6. Migration of fines, dissolution and destruction of rock particles are possible mechanisms for oil recovery increment with low salinity brines from Middle East reservoircore plugs at 90 °C.
LSW at initial water saturation (Swi) – Much higher oil recovery than with HS
LSW at residual oil saturation (Sor) – Requires very large water injection volume Two Possible Processes Some of the first observations of LSE for waterflood recoveries are summarized in the next Table LSW at Initial Water Saturation (Swi) The increase in recovery with reduced salinity clearly shows the improvements in recovery resulting from the LSE. LSW at Initial Water Saturation (Swi) There is special interest in applying LSW to watered-out reservoirs, nominally at Sor, after HS waterflooding (HSW).
Fig shows one of the more encouraging examples for reservoir rock, with recovery increased by 25% over HSW LSW at Residual-Oil Saturation (Sor)
It has been postulated that when wettability changes from less to more water-wet conditions, oil is released from rock surfaces and recovery is increased.
Figure shows scaled rates of imbibition for HS displacing HS, MS displacing MS, and LS displacing LS . LSE Mechanisms Porous medium
Sandstones (not documented in carbonates)
Clay must be present
Must contain polar components (acids and bases)
FW must contain divalent cations (i. e. Ca2+, Mg2+ …Lager et al. 2007)
Initial FW must be present
Efficiencyn related to Swi
Low Salinity fluid (Salinity: 1000-2000 ppm)
Appears to be sensitive to ion composition (Ca2+ vs. Na+)
pH of effluent water usually increases a little, but also decrease in pH has been observed. In both cases, Low Salinity effects were observed.
Are small changes in pH important for Low Salinity effects ?? Conditions for LoW Salinity effects
(Morrow et al. 2006) Fine Clay Migration and Permeability Reduction Mechanism #1 Clay tends to hydrate and swell when contacting with fresh water.
Less-saline water affects the dispersion of clay and silt in the formation Clay and silt then become mobile and follow the water into the high permeability paths
Mobile clay and silt become lodged in the smaller pore
Mobile clay and silt become lodged in the smaller pore spaces of the high permeability paths These high permeability paths become LESS permeable Resulting formation more uniform and water flood
Resulting formation more uniform and water flood performance is improved Clay is usually kaolinite and illite Fine Clay Migration and Permeability Reduction 2 of 2 Clay particles are released and transported at the oil-water interface, creating water-wet surface spots.
Can improve sweep efficiency by blocking pores in already water flooded area.
BP observed Low Salinity effects without detecting fines in the produced fluid Migration of fines Change Rock Wettability. Mechanism 2 The increased oil recovery by low-saline water flooding is related to wettability modification toward a more water-wet system.
Decreasing the NaCl concentration in seawater is related to a decrease in the non-active ions , which allows for better access of the active ions (Ca2+, Mg 2+, and SO42−) to the surface of contact between formation and injected water.
The results indicated that sulfate dissolved in the FW and SO42− (aq) appeared to be the active species dictating the wetting properties. Suggested wettability mechanism Multicomponent Ion Exchange (MIE)
DLVO theory (Named after Derjaguin Landau Verwey and Overbeek). Mechanism #3 Multicomponent Ion Exchange –Explanation 1
Reduced salinity allows the electrical double layers to expand
allows bound multivalent ions to exchange
complex cations at the surface are replaced
rock goes from oil wet to water wet. (wettability modification depends on the amount of suited clay minerals and especially their distribution of the rock surface) Electrical double layer
A double layer (DL, also called an electrical double layer, EDL) is a structure that appears on the surface of an object when it is placed into a liquid.
The object might be a solid particle, a gas bubble, a liquid droplet, or a porous body.
The second layer is composed of ions attracted to the surface charge via the coulomb force, electrically screening the first layer Difficult to write a model chemical reaction illustrating MIE clay clay Multicomp. Ion Exchange (MIE) Status in oil-wet rock: – Different affinities of ions on rock surfaces
– Multivalents or divalents such as Ca2+ and Mg2+ strongly adsorbed on rock surfaces – Multivalent cations at clay surfaces are bonded to polar compounds present in the oil phase (resin and asphaltene) forming organo-metallic complexes and ti il t k f
promoting oil-wetness on rock surfaces – Organic polar compounds are adsorbed directly to the mineral surface - also oil wet Multicomponent Ion Exchange –Explanation 2 Multicomponent Ion Exchange –Explanation 2
Low salinity water injection situation
– MIE removes organic polar compounds and organo-metallic complexes from the surface and replacing them with uncomplexed cations – Desorption of polar compounds from the clay/rock surface leads to a more water-wet surface
– Resulting in an increase in oil recovery The DL refers to two parallel layers of charge surrounding the object. The first layer, the surface charge (either positive or negative), comprises ions adsorbed directly onto the object due to a host of chemical interactions Carbonates
Often neutral to preferential oil wet
Water injection difficult without wettability modification.
Optimal water flood at weakly water-wet condition (Morrow)
Mixed wet (oil-wetness linked to clays) “Smart Water” to obtain improved wetting conditions Chalk: SW as “smart water” Smart Water Flooding By: Webb et al. 2005. (1,500 ppm) (15,000 ppm) Sandstone: Low Salinity flooding (By: Lager et al. 2007) Low Salinity effect well documented by BP What is the chemical mechanism for enhanced oil recovery by “Smart Water”??
Are there any similarities?? Outline SO42- SO42- SO42- - - - - - - - - - Ca2+ Ca2+ Ca2+ + + + + + + + - - - - Carboxylylic acids, R-COOH
Bases (minor importance)
Charge on interfaces
Potential determining ions
Ca2+, Mg2+, SO42-, CO32-, pH Wetting properties for carbonates Comp. Ekofisk Seawater
Na+ 0.685 0.450
K+ 0 0.010
Mg2+ 0.025 0.045
Ca2+ 0.231 0.013
Cl- 1.197 0.528
HCO3- 0 0.002
SO42- 0 0.024
Seawater: [SO42-]~2 [Ca2+]; [Mg2+]~ 2 [SO42-] ; [Mg2+]~4 [Ca2+]
[Mg2+..SO42-]aq = Mg2+ + SO42-
Stronger interaction as T increases. Model composition of FB and SW Effcets of Ca2+
Crude oil: AN=0.55 mgKOH/g
Swi = 0;
Imbibing fluid: Modified SSW
Temperature: 70 oC Effects of SO42-
Crude oil: AN=2.0 mgKOH/g
Initial brine: EF-water
Imbibing fluid: Modified SSW
T = 100 oC Imbibition of modified SW NaCl-brine,
T= 130 oC,
[Ca2+]= [Mg2+]= 0.013 mole/l
SCN- as tracer NaCl-brine,
T= 23 oC,
[Ca2+]= [Mg2+]= 0.013 mole/l
SCN- as tracer Affinity of Ca2+ and Mg2+ towards chalk Slow injection of SW without Mg2+
1 PV/D Slow injection of SW
1 PV/D Substitution of Ca2+ by Mg2+ Effects of potential determining ions and temperature on spontaneous imbibition The main mechanism for Low Salinity effects is related to changes in the solubility of polar organic components in the aqueous phase, described as a “Salting In” effect. Hypothesis Low Salinity fluid should be characterized in terms of Ionic strength rather than salinity
Compare Low Salinity effects using NaCl and CaCl2 ( [CaCl2] = ½ [NaCl] )
If the Low Salinity effect is quite similar for the two fluids, the Low Salinity mechanism is more linked to solubility properties rather than MIE at the rock surface. (1) Experiments to verify the hypothesis Test Low Salinity effects for oils with and without water extractable acids and bases present.
Is there a correlation between AN and BN of extractable acids and bases and Low Salinity effect ??? No correlation between AN and Low Salinity effect (Lager et al. 2006)
According to the hypothesis, the desorbed organic material must be partly soluble in water (2) Experiments to verify the hypothesis + Kaolinite Test the difference in hysteresis for the adsorption and desorption of substituted benzoic acid onto kaolinite using FW and Low Salinity fluid.
Difference in hysteresis will reflect difference in solubility properties for FW and Low Salinity water
Temperature effects ?
Effects of Low Salinity fluid composition ?? (3) Experiments to verify the hypothesis Carbonate
The chemistry of fluid-rock interaction is well characterized
Wetting agent: Carboxylic materials, difficult to remove
Wettability modifiers: Ca2+, Mg2+, SO42-, Temp.
Wetting modification at SW-salinity, which is not regarded as a Low salinity fluid.
The chemistry of fluid–rock interaction is more complicated
The organic material adsorbs differently onto clay minerals, but it is more easily removed compared to carbonates.
So fare, no single proposed mechanism has been clearly accepted for the observed Low Salinity effect.
A hypothesis involving “Salting In” effects has been suggested, and actual experiments are proposed to verify the hypothesis. Conclusion on “Smart Water” The chemical mechanism for using “Smart Water” for wettability alteration to enhance oil recovery is different for Carbonates and Sandstones. Conclusion on “Smart Water” Thank You