i Preface This master thesis was prepared at Center for Energy Resources Engineering (CERE) at the department of Chemical and Biochemical Engineering at the Technical University of Denmark (DTU) in fulfillment of the requirements for acquiring a Master of Science degree in Petroleum Engineering. Mehrdad Ahkami July 26, 2015
ii Acknowledgment I would like to express my gratitude to my supervisor Alexander for his guidance and inspirations during my thesis and my master education. I would like to thank Artem because I would never been able to write the codes without his guidance. I would also like to thank Ioannis not only because he has been a good colleague but also he is a good friend. I would like to thank my parents and my brother. They were always supporting and encouraging me with their best wishes. Finally I would like to thank my girlfriend and friends as they were always stood by me through the good times and bad times.
Contents Preface Acknowledgements Contents List of Figures Nomenclature i ii iii vi xi 1 Introduction 1 2 Background Theory 4 2.1 Sw-EOR in sandstone........................ 4 2.1.1 Multicomponent ion exchange (MIE)........... 4 2.1.2 PH alteration........................ 6 2.1.3 Double layer expansion................... 8 2.1.4 IFT reduction........................ 10 2.1.5 Release and migration of mixed wet clay fines...... 11 2.1.6 Rock dissolution...................... 11 2.1.7 Increasing sweep efficiency................ 12 2.1.8 Conclusion......................... 14 2.2 Sw-EOR in chalk.......................... 15 2.2.1 Wettability alteration as a mechanism in Sw-EOR..... 16 2.2.1.1 Determining ions in wettability alteration of chalks 18 2.2.2 Other mechanisms in addition to wettability alteration.. 20 2.2.3 Formation of particles................... 21 2.2.4 Formation of microemulsions............... 23 2.2.5 Conclusion......................... 25 iii
CONTENTS iv 3 Numerical Modeling 26 3.1 Numerical solution features:.................... 26 3.2 Material balance equations..................... 27 3.2.1 Solid phase (minerals)................... 27 3.2.2 Aqueous ions........................ 28 3.2.3 Water flow......................... 28 3.2.4 Oil Flow.......................... 29 3.3 Darcy s law............................. 29 3.4 Fluid density modifications..................... 30 3.4.1 Water density........................ 31 3.4.2 Oil density......................... 32 3.5 Fluid viscosity modification.................... 32 3.6 Reactions.............................. 32 3.6.1 Determination of reactants and productions and their stoichiometric coefficients................... 32 3.6.2 Reaction rates........................ 33 3.7 Reaction to represent particle formation and precipitation..... 34 3.8 Reaction to represent wettability alteration............. 36 3.9 Porosity modification........................ 37 3.10 Absolute permeability modification................ 37 3.11 Residual oil modification...................... 39 3.12 Water and oil relative permeability modification.......... 39 3.13 Bringing the equations to a dimensionless form.......... 40 3.14 Initial conditions.......................... 43 3.15 Boundary conditions........................ 43 3.16 Spacial descritization........................ 43 3.17 Temporal descritization....................... 44 3.17.1 Variable matrix....................... 44 4 Results and Discussion 46 4.1 Numerical results of water flooding without reactions....... 48 4.1.1 Oil recovery......................... 49 4.1.2 Saturation profile and saturation front........... 49 4.1.3 Pressure........................... 51 4.1.4 Relative permeabilitites................... 52 4.2 Flooding with wettability alteration................. 53 4.2.1 Oil recovery......................... 53 4.2.2 Saturation profile and saturation front........... 54 4.2.3 Pressure........................... 57 4.2.4 Residual oil saturation................... 57 4.2.5 Relative permeabilitites................... 59
CONTENTS v 4.3 Flooding with solid precipitation.................. 59 4.3.1 Injection brine only contains sulfate and calcium presents in connate water....................... 60 4.3.1.1 Oil recovery................... 60 4.3.1.2 Saturation profile and saturation front...... 60 4.3.1.3 Pressure..................... 62 4.3.1.4 Porosity..................... 63 4.3.1.5 Absolute permeability.............. 64 4.3.2 Injection water contains sulfate and calcium........ 64 4.3.3 Injection water contains sulfate, dissolution and precipitation occurs in the medium................ 65 4.4 Cyclic waterflooding........................ 67 4.4.1 Oil recovery......................... 68 4.4.2 Saturation profile and saturation front........... 68 4.4.3 Pressure........................... 70 5 Conclusion 73 6 Future Work 75 Bibliography 76 7 Appendix 82 7.1 Reference values and model inputs................. 82 7.2 Waterflooding of heterogeneous medium without reaction..... 84 7.2.1 Numerical Modeling.................... 84 7.2.2 Results and discussion................... 85 7.3 Matlab Codes............................ 89 7.3.1 Main script......................... 89 7.3.2 Oil and water density.................... 97 7.3.3 Porosity........................... 98 7.3.4 Absolute permeability................... 99 7.3.5 Oil relative permeability.................. 99 7.3.6 Water relative permeability................. 100 7.3.7 Reaction rates........................ 101 7.3.8 Temporal discretization................... 104 7.3.9 Spacial discretization.................... 106 7.3.10 Cyclic waterflooding.................... 108 7.3.11 Waterflooding of heterogeneous medium......... 118 7.3.12 Spacial discretization and flux calculation for heterogeneous medium....................... 127
List of Figures 1.1 Oil recovery after cyclic waterflooding with three different brines[41] 3 2.1 Different adhesion mechanisms which are affected by Sw-EOR[25] 5 2.2 Tertiary oil recovery in the absence of divalent ions[16]...... 6 2.3 Upper: Desorption of basic material, Lower: Desorption of acidic material by the change in ph [7].................. 7 2.4 Adsorption of quinoline versus ph at ambient temperature in low salinity brine, LS1 (1000 ppm), and in high salinity brine, HS1(25000 ppm)[1]............................... 8 2.5 Schematic of oil adsorbed on clay surface through the Electrical Double layer[10].......................... 9 2.6 Effect of salinity on Electrical Double layer[10].......... 9 2.7 Increase of Electrical Double Layer for clay (left) and sand (right) type of particles with the change in salinity[10].......... 10 2.8 effect of brine dilution on IFT[44]................. 10 2.9 Dissolution of anhydrite in Tensleep rock ( the light colored regions show the regions of cement dissolution after flooding with injected water[23].......................... 11 2.10 Evolution of pressure in case of fast (solid) and slow (dashed) reactions: pressure profile at the injection time T= 1: 1 PVI; 2 : 2.5 PVI, 3 : 5 PVI.......................... 12 2.11 Dispersion curves for homogeneous core A1 and less homogeneous core B for the cleaned condition and with S or [36]...... 13 2.12 High magnification images of the same pore in a cut face befire (left) and after (right) one-phase, high to low salinity water flooding. Ellipses mark mineral features in right part which are not present in left part or vice versa[19]................ 14 2.13 High magnification of images of the same pore in a cut face of pore space before (left) and after (right) oil recovery by low salinity waterflooding. Arrows in right part indicates some of the locations of asphaltene deposits[19]................... 14 vi
LIST OF FIGURES vii 2.14 Imbibition tests for crude oils with AN=0.17, 0.49, and 2.07 mgkoh/g. At 30 days, the imbibition brine was substituted with a solution of cationic surfactant dissolved in artificial sea water (SSW)[6]... 16 2.15 (A) proposed mechanism when Ca 2+ and SO 2 4 participate in reaction at lower temperature. (B) Mechanism of SO 2 4 and Mg2+ reaction at high temperature[53].................. 17 2.16 Wettability monitoring in the presence of sulfate ion[56]..... 17 2.17 The effect of brine salinity on wettability alteration pace and extent, top is the the sample with sea water salinity and bottom is the sample with 1 of sea water salinity[56]............ 18 40 2.18 Equal amount of Ca 2+ or Mg 2+ was added to imbibing fluid ([SO 2 4 ]=0.024 mol/l). Experiment was performed at 70-130 C[53]........... 18 2.19 Reservoir condition low capillary pressures (CP) of spontaneous imbibition test with sulfate free (left) and sulfate contained (right) brine[45].............................. 19 2.20 Recovery for formation water (sulfate free) and sea water (with sulfate) during spontaneous imbibition of cores in reservoir condition[45] 19 2.21 Effect of sulfate on oil recovery on water-wet cores at 110 C. (SW0S is free of sulfate, and SW3S has the highest sulfate concentration)[52] 20 2.22 Cumulative oil production and pressure difference curves[56]... 21 2.23 Correlating SO 2 4 concentration and CaSO 4 precipitation with oil recovery for a data set of literature by using extended UNIQUAC model[14].............................. 22 2.24 Formation of a microemulsion phase can be oberved for SW1.5S and SW3S, as a dark grey phase between the oil and the brine phases[50].............................. 23 2.25 Schematic diagram of experimental setup for emulsion formation[13] 24 2.26 Different brine used to study emulsion formation with different doped oils TC1, TC2, and TC3 and designed oils O1 and O2[13]. 25 3.1 Mass conservation law of cross section A limited by planes x and x+dx................................. 27 3.2 Oil density as a function of temperature, pressure and composition[9] 31 3.3 Brine density as a function of pressure, temperature, and salinity[9], PPM refers to sodium chloride concentration in part per million. 31 3.4 Stoichiometric coefficients matrix for the presented reactions... 33 3.5 Formation brine properties..................... 35 3.6 Saturation index of calcium sulfate in different temperatures and ion s concentrations (x axis is sulfate and calcium concentration as they have equal concentration in each step) and P = 250 bar.. 35
LIST OF FIGURES viii 3.7 Calcium sulfate molarite as a function of variable calcium and sulfate concentration in different temperatures and P = 250 bar.. 36 3.8 Corey-type oil and water relative permeability for s or =0.3, s wi =0.2, k rowi =0.8, k rwor =0.5, and a w = a o =2................ 40 3.9 The matrix of variables schematic for N x =6,N y =2, and N var =4.. 45 4.1 Percentage of recovered oil for injection without reaction..... 49 4.2 Saturation front........................... 50 4.3 Saturation profile at the end of injection time........... 50 4.4 Saturation evolution in the last cell................. 51 4.5 Pressure profile at the end of injection time............ 52 4.6 Pressure evolution in the inlet.................... 52 4.7 Oil and water relative permeabilities................ 53 4.8 Oil recovery with and without wettability alteration reaction where two different sets of reaction rate constants were used....... 54 4.9 Saturation front for three different condition where left figure is due to waterflooding without particle precipitation. Two other figures represent the waterflooding condition with wettability alteration where reaction rate constant is higher in the right one.... 55 4.10 Saturation profile of porous medium in the end of waterflooding, the solid line is correspondent to normal waterflooding and the dashed-line is due to the presence of wettability alteration..... 56 4.11 Saturation evolution in the outlet, the solid line is due to normal waterflooding and the dashed-line represents the evolution of saturation in the presence of wettability alteration.......... 56 4.12 Pressure gradient in the inlet in the presence of wettability alteration reacion with different reaction rates............. 57 4.13 Pressure profile of the porous medium in the end of injection time with wettability alteration reaction and with different reaction rates 58 4.14 Decrease in residual oil saturation because of wettability change towards a more water-wet condition (forwards reaction rate=5, backwards reaction rate=0). Initial S or =0.3 while its minimum value due to the reaction is S or =0.2................. 58 4.15 Evolution of relative permeabilitites ( water relative permeability in the left and oil relative permeability in the right) through the time 59 4.16 Oil recovery with and without precipitation of particles...... 60 4.17 Saturation front for three different condition where left figure is due to waterflooding without particle precipitation. Two other figures represent the waterflooding condition with precipitation of particles where reaction rate constant is higher in the right one.. 61 4.18 Saturation profile at the end of waterflooding........... 62
LIST OF FIGURES ix 4.19 Saturation in the outlet....................... 62 4.20 Pressure profile........................... 63 4.21 Pressure in inlet........................... 63 4.22 Porosity change as a result of CaSO 4 precipitation. Right hand side of the figure is due to higher precipitation rate and left hand side is due to lower rate....................... 64 4.23 Change of absolute permeability as a result of precipitation and change in porosity.......................... 64 4.24 Oil recovery............................. 66 4.25 Porosity change as a result of precipitation............. 66 4.26 Oil recovery for precipitation and dissolution of calcium sulfate. Reaction rate constants are forward rate = 5, backward rate = 0.5. 67 4.27 Porosity change as a result of precipitation and dissolution.... 67 4.28 Oil recovery after two rounds of water flooding. First round is injection of 5 pore volumes of brine without reaction and second round is same amount of injection with wettability alteration reaction................................ 68 4.29 Saturation profile at the end time of injection for two rounds of waterflooding. First round is injection of 5 pore volumes of brine without reaction and second round is same amount of injection with wettability alteration..................... 69 4.30 Saturation in the outlet for two rounds injection of water flooding. First round is injection of 5 pore volumes of brine without reaction and second round is same amount of injection with wettability alteration reaction......................... 70 4.31 Saturation front two rounds of water flooding. First round is injection of 5 pore volumes of brine without reaction and second round is same amount of injection with wettability alteration. Left figure is due to first injection round and the right figure is due to the second round of injection...................... 71 4.32 Pressure profile at the end time of two rounds of water flooding. First round is injection of 5 pore volumes of brine without reaction and second round is same amount of injection with wettability alteration.............................. 72 4.33 Inlet pressure evolution for two rounds of water flooding. First round is injection of 5 pore volumes of brine without reaction and second round is same amount of injection with wettability alteration................................ 72
LIST OF FIGURES x 7.1 Oil recovery in different layers with different absolute permeabilities. Upper figure is high permeable layer and lower layer has lower absolute permeability..................... 85 7.2 Saturation front in two layers. Upper figure is high permeable layer and lower has lower permeability............... 86 7.3 Saturation profile for two layers with different absolute permeabilitites where it is higher in the upper figure........... 86 7.4 Saturation in the outlet. Upper figure is due to layer with high permeability and lower is due to lower permeability........ 87 7.5 Pressure profile of heterogeneous medium where absolute permeability is higher in the upper figure................. 87 7.6 Pressure in the inlet for heterogeneous system. Absolute permeability is higher in the upper figure................. 88
Nomenclature α x γ i Coefficient for determination of absolute permeability dependecy on porosity Volume element length......................................... [cm] Dimensionless activity coefficient of component i µ o,µ w Dimensionless viscosity of oil and water µ o,µ w Oil and water viscosity......................................... [cp] φ φ,φ 0 ρ o,ρ w Porosity Dimensionless porosity and initial porosity prior to precipitation and dissoluion Dimensionless density of oil and dimensionless water ρ o,ρ w Oil and water densities....................................... [gr/cm 3 ] A Cross section area............................................ [cm 2 ] a i a o,a w AN c ci 0,c0 m c i,c m Acitivity of component i Oil and water empirical parameters for Corey type relative permeability Acid number Kozeny s factor Reference values for mineral and ion concentrations Dimensionless concentration of ions and minerals c i Concentration of ion i...................................... [mole/cm 3 ] c m Mineral concentration...................................... [mole/cm 3 ] xi
Nomenclature xii c P,o,c P,w Oil and water compressibiliy.................................[1/bar] c wc,i d m DIW EOR i IFT Water compressibility with regard to molar change of component i [cm 3 /mole] Change of volume due to change in mole number. It is the ratio of density divided by molecular weight Deionized water Enhanced oil recovery Indication for water soluble components which are refered as ions Interfacial tension..........................................[dynes/cm] I MPES Implicit pressure explicit saturation k k 0 f k,k 0 k b,k f k 1,k 2 k b,k f k rowi Absolute permeability........................................ [mda] Reference value of reaction rate constant. Its unit for first order and second order reaction is as follows......................... [1/sec],[cm 3 /mole.sec] Dimensionless permeability and reference permeability Dimensionless backward and forward reaction rate constants Minimum absolute permeabiliy of layer 1 and layer 2............ [mda] Backward and forward reaction rate constants. Their unit for first order and second order reaction is as follows.............. [1/sec],[cm 3 /mole.sec] Oil relative permeability at initial water saturation k ro,k rw k rwor L M m Oil and water relative permeabilities Water relative permeability at residual oil saturation Sample length................................................. [cm] Molecular weight........................................... [gr/mole] Indication for water insoluble components refered as minerals m 0 2 Maximum value of wettability modifier product m 2........... [mole/cm 3 ] m min MIE Number of minerals Multicomponent ion exchange
Nomenclature xiii n aq N var N x,n y Number of ions Number of variables Number of cells in x and y direction OOIP Original oil in place P Pressure...................................................... [bar] P, P Dimensionless pressure and characteristic pressure ph Q r 0 r i,r m Numeric scale to specify acidity or alkalinity of an aqueous solution Flow rate...................................................[cm 3 /sec] Reference value of reaction rate correspondent to formation of calcium sulfate in specific condition.............................. [mole/sec.cm 3 ] Dimensionless reaction rate of ions and minerals r b,r f Backward and forward reaction rates...................... [mole/sec.cm 3 ] r eq,r neq Equilibrium and non-equilibrium reaction rates of a reaction [mole/sec.cm 3 ] r i Reaction rate of ion i.................................... [mole/sec.cm 3 ] r m Reaction rate of mineral m............................... [mole/sec.cm 3 ] r p r sp Pore radius Calium sulfate radius which assumed to be half of sum of oxygen and sulfur radius.................................................. [pm] S,S p,s s Specific surface with respect to bulk volume, pore volume, and solid volume, respectively S or S wi SI Residual oil saturation Initial/irreducible water saturation Saturation index, defined as the ratio of non-equilibrium to equilibrium reaction rates Sw EOR Smart waterflooding enhanced oil recovery T Dimensionless time
Nomenclature xiv U 0 u 1,u 2 U o,u w u o,u w u tot V k X Reference value for superficial velocity, correspondent to velocity of one phase flow of water through the core...........................[cm/sec] Injection rate into layer 1 and layer 2, respectively...............[cm/sec] Oil and water superficial velocities............................ [cm/sec] Dimensionless flow rate of oil and water Total injection rate........................................... [cm/sec] Matrix of variable in kth finite volume Dimensionless length
Chapter 1 Introduction Water-flooding is one of the most well-known methods of Enhanced Oil Recovery (EOR)[42]. So far, it is widely accepted that a certain percentage of oil (known as residual oil) will remain in the porous media regardless of amounts of injected water. This oil is claimed to be trapped by complicated physical mechanisms (Chatzis et al. 1983[15]). Many EOR methods are claimed to be able to free up residual oils and increase the oil recovery. One of the promising methods is the modification of injection brine composition. Its application was discussed by Yildiz and Morrow 1996[48] based on the works of Jadhunadan and Morrow 1995[21]. Tang and Morrow 1999[41] observed an increase in oil recovery in the case of different salinities between injection brine and connate water. Zhang and Morrow 2006[54] performed flooding experiments with mixed-wet cores and reported an increase in both tertiary and secondary mode, however they indicate that the reservoir rocks show better response than outcrops, Zhang et al. 2007[55] water flooded two consolidated reservoir cores with cycles of high salinity formation brine of 29.690 ppm, low salinity brine of 1.479 ppm and two concentrations of sodium chloride. They reported that injection of low salinity brine increases both secondary and tertiary recovery, the presence of divalent ions also increases the recovery. The effect of water composition on the oil recovery was also investigated within the near well-bore region of a reservoir by Web et al. 2004[46], they injected 10-15 pore volumes of high salinity brine into the volume of interest to obtain residual oil saturation, which was followed by the injection of diluted water. The log measurement of saturation showed 25-50% reduction in residual oil saturation and certifies the experimental investigations. Yousef et al. 2011[49] also certified the previous experimental observations and reported the effect of water salinity and ion composition on oil recovery. They tagged it as Smart WaterFlood which will be used in this work. Smart WaterFlooding EOR will be mentioned as Sw-EOR in this work. The authors reported a change in pressure drop and also a change in effluent s ph during the Sw-EOR, they also mentioned 1
CHAPTER 1. INTRODUCTION 2 rock properties, oil properties, ion composition, divalent ions concentration, presence of clay contents and mobile particles, initial wettability, and temperature as the affecting factors on Sw-EOR. The mechanism or mechanisms of the Sw-EOR is not fully understood and have brought a discussion in the literature. Several authors have proposed different chemical and physical mechanisms but none of them have been globally accepted. These contradictions can be due to the variation in experimental materials and procedures as the oil production is affected by complicated chemical and physical interactions of rock/connate water/injecting water/oil. The proposed mechanisms and experimental investigation of Sw-EOR are discussed in chapter 2, it will be discussed in section 2.1.8 and section 2.2.5 that the suggested mechanism can be divided in two main categories, where the former explains the wettability alteration and the later emphasizes the importance of other mechanisms such as increase in sweep efficiency by fine formation and precipitation. One upcoming question is whether they have equal weight on the increase in oil recovery or one of the mechanisms overweights the other one. In addition as will be discussed in chapter 2, experimental observations showed an increase in pressure difference and a decrease in residual oil saturation; the former is believed to be an effect of fine formation and the later is explained by wettability alteration of the rock. In this manner, this study is to develop a numerical modeling of the Sw-EOR with arbitrary number of reactions to represent the mentioned mechanisms. The governing equations and the implicit approach of solving equations is described in chapter 3. Further it is illustrated that one reaction is dedicated to the formation of particles and rock dissolution where ions in the injecting water and formation water participate in a reaction to form particles. Then produced particles precipitate and in this way modify the local porosity of the system. This affects the absolute permeability of the system as well. The reaction is a two way reaction so either precipitation or dissolution can happen in the system based on reaction rates and reactant concentrations. The second reaction is dedicated to wettability alteration, however the numerical modeling of wettability is not easily possible because of its complex concept and algorithm. Wettability alteration is modeled through the decrease in residual oil saturation. The reaction is assumed to happen between an ion in the injecting water and a mineral on the rock surface. Its product changes the rock wettability by decreasing the residual oil saturation. The modification of residual oil saturation results in the change of relative permeability of oil and relative permeability of water as well. Numerical solution of different scenarios are illustrated in chapter 4. Oil recovery and other determining factors such as saturation and pressure are illustrated to compare the different waterflooding scenarios. The normal water flooding without any reaction is brought in section 4.1 while wettability alteration and fine
CHAPTER 1. INTRODUCTION 3 formation are investigated in section 4.2 and section 4.3 respectively. Formation of particles are also divided into three scenarios where injection water composition and reaction rates vary from each other, detailed explanation of each part is brought in section 4.3. Finally a cyclic waterflooding experiment is simulated where five pore volumes of water injection with wettability alteration came after five pore volumes of water injection without any reaction. Numerical results show the potential of wettability alteration to increase oil recovery both in secondary mode and tertiary mode. However its effect on pressure gradient is not completely correlated with the wettability modification rate and increase in oil recovery. On the other hand, formation and precipitation in a homogeneous medium such as the one in this study does not contribute to oil recovery. While it increases pressure gradient and this increase is correlated with precipitation rate and amount. Figure 1.1: Oil recovery after cyclic waterflooding with three different brines[41]
Chapter 2 Background Theory 2.1 Sw-EOR in sandstone The applicability of Sw-EOR on sandstones has been widely investigated in the in the literature, experimental results and field pilot tests have shown promising results. As mentioned in the introduction, the presence of clay is mentioned to be related to the Sw-EOR oil recovery improvement. Based on the literature Ashraf et al. 2010[5] investigated the relationship between rock wettability and oil recovery with Sw-EOR during secondary EOR method, they observed that oil production increases with the change of wettability from water-wet to neutral and decreases as it changes from neutral to oil-wet. Further they observed an increase in recovery by Sw-EOR and concluded that wettability alteration and Sw-EOR are probably related. Some mechanism such as mixed wet fines migration, ph alteration, double layer expansion, multi-ion exchange, and interfacial tension (IFT) reduction have been proposed to explain the wettability alteration. Moreover rock dissolution and increasing sweep efficiency have been proposed as the contributing factors. The detailed explanations of mentioned mechanisms are brought in the following: 2.1.1 Multicomponent ion exchange (MIE) Lager et al. 2008[25], reported that the effluent brine has a lower concentration of Ca 2+ and Mg 2+ than the injected brine which indicates that these cations were strongly adsorbed by the rock surface. They concluded that among the eight possible mechanisms of organic material adsorption onto the clay mineral (Sposito 2008[38], and Arnarson and Keil 2000[4]), those which directly involve divalent cations ( cation exchange, ligand bonding, and cation and water bridging, as are shown in figue 2.1) are sensitive to Sw-EOR. 4
CHAPTER 2. BACKGROUND THEORY 5 Figure 2.1: Different adhesion mechanisms which are affected by Sw-EOR[25] They proposed a theory which explains the desorbtion of negatively and positively charged organic materials through the Sw-EOR injection. The negatively charged organic material + divalent cations will be replaced by inorganic cations. The same desorption phenomenon happens with directly adsorbed organic compounds. This theory explains some of the experimental observations such as the importance of divalent cations in the Sw-EOR and also the importance of cation exchange capacity of the rock. It also explains that no additional recovery mineral oil is due to its lack of polar components. However Cissokho et al. 2010[16] doubted the MIE theory as they observed +11% (OOIP) and +10.5% (OOIP) tertiary recovery with 11 gr/l 100% NaCl NaCl and 1 gr/l95% NaCl + 5% CaCl 2 which indicates that the tertiary recovery happens even no divalent ions are present in the injecting brine (figure 2.2).
CHAPTER 2. BACKGROUND THEORY 6 Figure 2.2: Tertiary oil recovery in the absence of divalent ions[16] 2.1.2 PH alteration Austad et al.2010[7] stated that ph of formation water in the vicinity of clay is bout 4 due to the presence of CO 2 and H 2 S. Injection of low salinity water will increase the substitution of divalent cations with H + of the water in the vicinity of brine-clay interface. This substitution increases the ph in the area and results in a reaction between OH and the adsorbed acidic and protonated basic materials of the crude oil, this reaction unbonds the mentioned components and improves the water wetness of the rock. They mentioned following parameters as the key factors of oil recovery: 1. Clay properties/type and its amount in the rock 2. Acidic and basic polar components of oil 3. Initial ph of formation brine 4. The increase in oil recovery is due to improvement in water wetness of clay minerals
CHAPTER 2. BACKGROUND THEORY 7 Figure 2.3: Upper: Desorption of basic material, Lower: Desorption of acidic material by the change in ph [7] Aksulu et al. 2012[1] investigated the importance of ph on oil recovery in different temperatures, they reported that static adsorption of basic material onto illite in the ph range of 3-8 is higher for low salinity water than the high salinity water, which certifies that a decrease in salinity cannot be responsible for wettability alteration. They also waterflooded two reservoirs and one outcrop sandstone cores with high salinity - low salinity - high salinity brine at different temperatures. The measurements of ph and concentrations ofca 2+ and SO 2 showed that ph increases as the fluid changes from high salinity to low salinity brine and it changes to normal ph as the brine changes to high salinity. The desorption rate of Ca 2+ from the clay surface is also correlated to the ph gradient. The presence of anhydrite in the rock material reduces the ph gradient and Ca 2+ desorption. Finaly they concluded that ph gradient can be linked to oil production and is a screening test for Sw-EOR potential.
CHAPTER 2. BACKGROUND THEORY 8 Figure 2.4: Adsorption of quinoline versus ph at ambient temperature in low salinity brine, LS1 (1000 ppm), and in high salinity brine, HS1(25000 ppm)[1] However some authors have doubted the importance of ph, for instance, McGuire et al. 2005[27], Zhang et al. 2007[55], and Pu et al. 2008[29] reported an increase in oil recovery without any considerable increase in ph. Cissokho et al. 2009[16], performed scondary and tertiary experiments on outcrop sandstones with 9.2% of clays content where they measures ph, brine composition and oil recovery. They observed that oil recovery is accompanied by ph and pressure drop increase but the ph increase can occur without additional oil production. 2.1.3 Double layer expansion Positively charged molecules will strongly adsorb to negatively charged surfaced clay, however in the presence of multivalent ions, oil will also adsorb by the process of cation bridging (figure 2.5). Lightem et al. 2009[26] stated that injection of low salinity brine reduces the overal salinity of medium and consequently reduces the electrolyte content within the area. This decrease in salinity and mutivalent cation concentrations reduces the screening potential of cations. As a result, the electrical diffuse double layers around the clay and oil particles will expand and will result in an increae in the repulsive forces between oil and clay particles (figure 2.6). This repulsion will separate the oil from the surface as it exceeds the binding forces of multivalent cation bridge. They finally concluded that expansion of double layers are the main mechanism of improved oil recovery in sandstones.
CHAPTER 2. BACKGROUND THEORY 9 Figure 2.5: Schematic of oil adsorbed on clay surface through the Electrical Double layer[10] Figure 2.6: Effect of salinity on Electrical Double layer[10] Lee BPI et al.2010[10] used physical chemistry techniques such as Small Angle Scattering to investigate the presence of thin water film and also its variation with salinity. They observed small increase in size of water layer thickness with reduction in salinity for sand type particles. However, for this expansion is enhanced for clay type particles (figure 2.7). They also reported that the divalent ions have higher effect on the the layer expansion than monovalent cations. The concluded that the observed results can support the double layer theory as a contributing factor in Sw-EOR oil recovery.
CHAPTER 2. BACKGROUND THEORY 10 Figure 2.7: Increase of Electrical Double Layer for clay (left) and sand (right) type of particles with the change in salinity[10] 2.1.4 IFT reduction Vijapurapu and Rao 2003[44] mixed formation brine and deionized water (DIW) in different properties and measured the crude oil-water IFT and dynamic contact angles. They reported that as the IFT decreases from 25.3 dynes/cm to 10 dynes/cm as the formation water is added to the 100% DIW until it makes a 50-50 mixture. From then, adding the formation brine increases the IFT to a maximum of 27.9 dynes/cmfor 100% brine mixture (figure 2.8). Same conclusions are stated in the work of Alotaibi and Nasr 2009[3]. Figure 2.8: effect of brine dilution on IFT[44] On the other hand, Yousef et al. 2011[49] concluded that the effect of Sw-EOR on live oil IFT is not significant. Zahid et al. 2011[50] also reported that the change in IFT is not sufficient for the increase in oil recovery.
CHAPTER 2. BACKGROUND THEORY 11 2.1.5 Release and migration of mixed wet clay fines Tang and Morrow 1999[41] concluded that the injection of Sw-EOR detaches the oil wet particles from the rock surface. The release and transport of the oil wet particles will improve the overall wetness of the rock and increase the oil recovery. However contradictory results of additional oil recovery and without fine production were reported. 2.1.6 Rock dissolution Pu et al. 2010[30], conducted experiments on sandstone reservoir cores which contained anhydrite, dolomite, and occasional calcite cements while none of them had significant clay content, they observed a 5% increase in oil recovery which doubts the importance and role of clay in the effectiveness of Sw-EOR. They also correlated the increase of sulfate ions in the effluents to the dissolution of anhydrite. This dissolution is also showed in the X-ray CT images of the works of Lebedeva et al. 2009[23] (figure 2.9). They concluded that the wettability shift towards a more water -wet condition is due to a mechanism that involves dissolution of anhydrite and dolomite crystals and also due to formation of fine materials in the porous medium. They also related the increase in pressure drop to the brine-rock interaction which can be slow release of fine materials and blocking of pore throats. Figure 2.9: Dissolution of anhydrite in Tensleep rock ( the light colored regions show the regions of cement dissolution after flooding with injected water[23] Alexeev et al. 2014[2] developed a 1D numerical model for water flooding with dissolution and precipitation of the components, they observed that the displacement front velocity is a function of volumetric effects. Also in the case of high reaction rates, the variation of permeability and porosity close to the injection
CHAPTER 2. BACKGROUND THEORY 12 point represents the wormhole formation. Their results also certifies that pressure drop increases with the brine/rock interactions. Figure 2.10: Evolution of pressure in case of fast (solid) and slow (dashed) reactions: pressure profile at the injection time T= 1: 1 PVI; 2 : 2.5 PVI, 3 : 5 PVI 2.1.7 Increasing sweep efficiency Spildo et al. 2012[36] stated that in a homogeneous, half of injecting concentration breaks through after 1PV. While earlier breakthrough represents the presence of isolated pores which are dead end and are not participating in flow i.e. the effective pore volume during the flow is less than the total pore volume. The asymmetrical profile also indicates the mass exchange between flow and dead-end pores. Two homogeneous and heterogeneous cores were used. They observed that for homogeneous core, dispersion profiles are almost equal in the cleaned state and with S or. However, the dispersion curve is more asymmetrical for the cleaned state which indicates higher mass exchange between flow and dead end pores. For the less homogeneous core, the dispersion curves for the cleaned condition and with S or are largely different which indicates the effect of sweep efficiency in oil recovery (figure 2.11). They finally concluded that during Sw-EOR, the change in sweep efficiency because of change in crude oil-brine-rock interactions can give rise to oil recovery.
CHAPTER 2. BACKGROUND THEORY 13 Figure 2.11: Dispersion curves for homogeneous core A1 and less homogeneous core B for the cleaned condition and with S or [36] Fogden et al. 2008[19] stated that lack of observation of fines production from the cores cannot be interpreted as lack of fines mobilization and migration at pore scale. They tracked the changes in the location of fines and deposited organic materials before and after waterflooding experiments with different salinity by using scanning electron microscopy. They concluded that mobilization of fine particles is considerably greater in the presence of crude oil because of its ability to detach oil-wet grains during waterflooding. The mobilization of particles happens for both high salinity and low salinity waterflooding but is more considerable in lower salinity. These detached particles will be carried by oil phase and will deposit in the downstream. They also reported a significant increase in asphaltene - based film during the low Sw-EOR which indicates the adsorption of oil to the underlying layers of rock after mobilization of surface particles. The later result is contradictory to many of the previous theories which believe that Sw-EOR releases oil molecules from rock surface. (figure 2.12 and 2.13)
CHAPTER 2. BACKGROUND THEORY 14 Figure 2.12: High magnification images of the same pore in a cut face befire (left) and after (right) one-phase, high to low salinity water flooding. Ellipses mark mineral features in right part which are not present in left part or vice versa[19] Figure 2.13: High magnification of images of the same pore in a cut face of pore space before (left) and after (right) oil recovery by low salinity waterflooding. Arrows in right part indicates some of the locations of asphaltene deposits[19] Application of particles in EOR and its role in providing sweep improvement in reservoirs with unfavorable mobility ratio is also disscudes in the work of Skauge et al. 2010[34]. 2.1.8 Conclusion It is finely stated that the presence of clay and divalent cations contribute to the Sw-EOR recovery however the counter examples for each of the factors showed the applicability of Sw-EOR in the absence of clay content and divalent cations. Suggested mechanisms such as ph alteration, IFT alteration or MIE can explain many experimental observations of the literature but many authors have doubted
CHAPTER 2. BACKGROUND THEORY 15 their reliability with different experiments. Double layer expansion is being being supported by some authors which can explain the desorption of oil contents from the rock surface but it cannot explain the variation in pressure drop through the Sw-EOR. Many of the proposed mechanisms explain either the change in wettability (change in residual saturation) or the variation in pressure drop and absolute permeability. A certain conclusion about the main mechanism of Sw-EOR needs further research and study but it can be concluded that a combination of proposed mechanisms might be contributing to additional recovery of Sw-EOR. These mechanisms can be divided into two main categories: 1. Change in oil residual saturation and freeing trapped oil from capillaries 2. Formation of fines and particles and increase in sweep efficiency. 2.2 Sw-EOR in chalk The application of Sw-EOR in sandstones is well documented in the literature. Experimental investigations have shown promising results and many recovery mechanisms are proposed. However as it is discussed in section 2.1.8, still many prospects of the contributing mechanism is not globally accepted. On the other hand, the Sw-EOR potential for the carbonate reservoirs has not being investigated thoroughly. Some authors have even doubted the applicability of Sw-EOR (Lager et al. 2006[25], and Doust et al. 2009[32]. However, the works of some authors have shown the applicability of Sw-EOR in chalks. Austad et al. 2005[6] performed spontaneous imbibition experiments by changing certain surface active compounds of the cationic type [R-N(CH 3 ) 3 ] + of the water phase and with oils with different acid numbers (AN) in different temperatures. They concluded that the injecting water components (in specific the sulfate concentration) are crucial factors in increased oil recovery (figure 2.14). Bagci et al. 2001[8] also injected ten different brine composition into unconsolidated limestone and reported an increase in oil recovery Same results were also reported by Austad and co-workers (Strand et al. 2006[40], Zhang et al. 2007[53]). The different authors have proposed different mechanisms to explain the increase in oil recovery in chalk, but similar to sandstone none of the proposed mechanisms are globaly accepted. Some of the mechanism focus on the role of wettability alteration while other mechanisms claim that formation of particles and the effect of emulsion formation contribute to the increase in oil recovery in Sw-EOR. It is discussed that the increase in oil recovery is sensitive to temperature, salinity of the fluid and the available ions composition in the brine.
CHAPTER 2. BACKGROUND THEORY 16 Figure 2.14: Imbibition tests for crude oils with AN=0.17, 0.49, and 2.07 mgkoh/g. At 30 days, the imbibition brine was substituted with a solution of cationic surfactant dissolved in artificial sea water (SSW)[6] 2.2.1 Wettability alteration as a mechanism in Sw-EOR Seethepalli et al. 2004[33] and Hirashki et al. 2004[20] performed spontaneous imbibition experiments on fractured chalk samples and observed an increase in oil recovery by adding anionic surfactants to the water. They concluded that the change of wettability from a mix-wet condition towards a more water-wet condition is the reason of increase in oil recovery. Austad and co-workers (Standnes and Austad 2000[39], Austad et al. 2005[6], Zhang et al. 2007[53], Strand et al. 2006[40], and Pountervold et al. 2007[31]) reported an increase in oil recovery by injecting Sw-EOR and concluded that the additional recovery is due to wettability alteration of carbonate surface towards a more water-wet condition. Zhang et al. 2007[53] proposed a chemical mechanism where Ca 2+ reacts with carboxylic group and release it from the surface. At high temperature another reaction contributes to oil recovery where Mg 2+ displaces the Ca 2+ -carboxylate, the latter reaction explains why wettability alteration in the presence of Mg 2+ and SO 2 4 is only active at high temperatures (figure 2.15).
CHAPTER 2. BACKGROUND THEORY 17 Figure 2.15: (A) proposed mechanism when Ca 2+ and SO 2 4 participate in reaction at lower temperature. (B) Mechanism of SO 2 4 and Mg2+ reaction at high temperature[53] Yi and Sarma 2012[56] performed a set of flooding and spontaneous imbibition tests on carbonate rocks to investigate displacement efficiency, and wettability alteration. Based on the experimental results they concluded that injecting brine salinity and sulfate ion concentration affect the oil recovery, moreover the effect of brine salinity on wettability alteration overwhelms the effect of sulfate concentration in lower temperature (70 C) whereas the sulfate concentration is more effective in higher temperature (120 C). They performed 8 sets of wettability monitoring in (90 C) to see the effects of ionic composition, brine salinity, and brine harness on rock wettability. Their results showed that the presence of sulfate in brine can greatly promote wetability alteration towards less oil-wet condition(figure 2.16), but the effect of divalent ions on the wettability alteration is very limited. The salinity level of brine (without the consideration of ionic composition) also affects the wettability alteration where lowering brine salinity lead to faster and a larger extent of wettability alteration (figure 2.17). Figure 2.16: Wettability monitoring in the presence of sulfate ion[56]
CHAPTER 2. BACKGROUND THEORY 18 Figure 2.17: The effect of brine salinity on wettability alteration pace and extent, top is the the sample with sea water salinity and bottom is the sample with 1 40 of sea water salinity[56] 2.2.1.1 Determining ions in wettability alteration of chalks Zhang et al. 2007[53] investigated the effects of divalent ions (Mg 2+, and Ca 2+ ) in the presence of SO 2 4 by performing core waterflooding and spontaneous imbibition where different ions were added to the brine gradually. They verified the Mg 2+ is a determining ion in Sw-EOR performance where it substitutes Ca 2+ from the chalk surface as temperature increases. SO 2 4 must act together with either Ca 2+ or Mg 2+ to increase the Sw-EOR efficiency. In addition they also concluded that increase in temperature contributes to increase in oil recovery (figure 2.18). Figure 2.18: Equal amount of Ca 2+ or Mg 2+ was added to imbibing fluid ([SO 2 4 ]=0.024 mol/l). Experiment was performed at 70-130 C[53] The effect of sulfate on Sw-EOR performance is also reported n the work of
CHAPTER 2. BACKGROUND THEORY 19 Puntervold et al. 2007[31]. Webb et al. 2005[45] investigated the applicability of Sw-EOR by performing a reservoir condition coreflood study with live crude oil and brine. Two similar samples were brought to initial water saturation and were aged in live crude oil to restore wettability. Imbibition capillary pressure tests were then performed with formation water and sea water. They concluded that the presence of sulfate ion contribute to the wettabililty change of the system, this results were interpreted based on the saturation and capillary pressure change in the spontaneous imbibition phase of formation water and sea water (figure 2.19). Figure 2.19: Reservoir condition low capillary pressures (CP) of spontaneous imbibition test with sulfate free (left) and sulfate contained (right) brine[45] Figure 2.20: Recovery for formation water (sulfate free) and sea water (with sulfate) during spontaneous imbibition of cores in reservoir condition[45]
CHAPTER 2. BACKGROUND THEORY 20 2.2.2 Other mechanisms in addition to wettability alteration Zahid et al 2010[52] doubted the wettability alteration theory for chalks as the effects of miscibility,mobility control, and IFT were neglected in the previous works. They conducted a number of waterflooding experiments on the water wet cores which were not being aged in crude oil and just were saturated with crude oil under vacuum. They waterflooded a fully oil saturated core with sulfate free brine and continued with two sulfate contained brine with different concentrations at 40 C, no increase in oil recovery was observed in that temperature. They performed same experimental procedure at 90 C and observed additional 3.7% of recovery in the presence of sulfate. In order to verify the effect of temperature, three cores were waterflooded with brine with three different sulfate concentration. They observed that the highest recovery is for the core with highest sulfate concentration and the lowest recovery is for the sulfate free brine (figure 2.21). They concluded that the effect of sulfate on oil recovery increases with temperature on water-wet cores. This additional oil recovery indicates that other mechanisms except from wettability alteration (such as the interactions between crude oil and brine) might contribute to oil recovery. Figure 2.21: Effect of sulfate on oil recovery on water-wet cores at 110 C. (SW0S is free of sulfate, and SW3S has the highest sulfate concentration)[52]
CHAPTER 2. BACKGROUND THEORY 21 2.2.3 Formation of particles Zahid et al. 2012[51] experimentally investigated the applicability of Sw-EOR for carbonates with both reservoir rock and outcrops. Injected of sea water was followed by injection of more diluted brine. Investigation of the total oil recovery, interaction of different ions with the rock, and the wettability changes came to the conclusion that the increase in oil recovery is not achieved in room temperature for outcrop and reservoir core, it was only observed for the reservoir rock and in reservoir temperature. They also doubted the substitution theory of Zhang et al.[53] because substitution reaction did not correlate with the increase in oil recovery, as the reaction was observed only for the outcrop core while the increase in oil production was reported for the reservoir core. They also observed an increase in pressure drop with the injection of diluted brine. Formation of fines and dissolution of rock were reported as the possible mechanism of increase in oil recovery which can also explain the change in pressure drop over the Sw- EOR experiments. Yi and Sarma 2012[56] also observed that oil production is accompanied with pressure drop increase(figure 2.22), this increase is sharper for reservoir condition than lower temperatures, this can be due to increase in dissolution rate of some minerals suchas, clay and dolomite. Based on presented results they claimed that the formation of particles together with wettability alteration contribute to the increase in oil recovery. Figure 2.22: Cumulative oil production and pressure difference curves[56] Chakvarty et al. 2015[12] experimentally investigated the role of fines in Sw- EOR by adding insoluble salt to water and oil to study oil miscelles formation. Their experiments showed that the interactions among fines-oil-water, produces water soluble oil emulsion. In order to form the emulsions, the crude oil must
CHAPTER 2. BACKGROUND THEORY 22 contain polar fractions and the oil emulsions are more stable when oil contains heavier acids, whereas the emulsions are independent of fine type and as they being formed for all different kinds of carbonate, sulfate, and clay fines. In addition the cations of the fines does not have effect on the amount of formed emulsions. This results showed the potential of fines in Sw-EOR because they can act as a catalyst to form the emulsions and due to the high mobility of emulsions in comparison with trapped oil, they play can boost the oil recovery. Chakravarty et al. 2015[14] used the extended UNIQUAC model (Thomsen and Rasmussen 1999) to calculate the amount of SO 2 4 and CaSO 4 precipitation in 61 Sw-EOR experiments of the literature and correlate them with oil recovery. They concluded that ion substitution can change the injecting brine significantly so the properties of the brine present in the pore space - after substitution - shoulb be correlated with the oil recovery instead of injecting brine properties. The ion substitution enhances the precipitation of CaSO 4. They reported that amount of soluble SO 2 4 is partially correlated with oil recovery but the precipitation of CaSO 4 is nicely correlated with the oil recovery. For instance as it is shown in figure 2.23 the increase in Ca 2+ increases oil recovery while the SO 2 4 concentration decreases and CaSO 4 precipitation increases, same trend can be seen due to temperature where the precipitation and oil recovery increases with temperatures and SO 2 4 concentration decreases. Figure 2.23: Correlating SO 2 4 concentration and CaSO 4 precipitation with oil recovery for a data set of literature by using extended UNIQUAC model[14]
CHAPTER 2. BACKGROUND THEORY 23 2.2.4 Formation of microemulsions Formation of oil emulsions in water can significantly increase the oil recovery since the oil bounded to the mineral surface has significantly higher immobility in comparison with water soluble oil emulsions. Zahid et al. 2011[50] investigated the crude oil-sea water ions interaction, IFT, density, viscosity, and water content at different temperatures, pressures, and sulfate ion concentrations. They observed a significant reduction in Latin American crude oil after interacting with sulfate in high pressure and temperature condition, this decrease in viscosity can be explained in a way that salt ions (sulfate or other determining ions) neutralize the negatively charged molecules and transform the oil into a coiled shape. This theory also explain why viscosity change is significant for the oil sample with higher asphaltene content. They also observed the formation of a transient phase between oil and water for the Middle East crude oil at high temperature, pressure, and sulfate concentration (figure 2.24). In spite of the complexity of analyses of the formed phase, authors believe that the new phase is microemuslions and has a major effect on oil recovery. Both effects happens with the increase in temperature which is correlated with the increase in oil recovery in higher temperatures. They finally concluded that the effects can contribute to the increase in oil recovery but the complex interaction between crude oil and brine must be investigated in future. Figure 2.24: Formation of a microemulsion phase can be oberved for SW1.5S and SW3S, as a dark grey phase between the oil and the brine phases[50]