The Pennsylvania State University. The Graduate School. Department of Energy and Mineral Engineering

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1 The Pennsylvania State University The Graduate School Department of Energy and Mineral Engineering ANALYSIS OF SCALING POTENTIALS IN MARCELLUS SHALE GAS WELLS A Thesis in Energy & Mineral Engineering by Phani Kiran Pamidimukkala 2012 Phani Kiran Pamidimukkala Submitted in Partial Fulfillment of the Requirements for the Degree of Master of Science May 2012

2 ii The thesis of Phani Kiran Pamidimukkala was reviewed and approved* by the following: John Yilin Wang Assistant Professor in Petroleum & Natural Gas Engineering Thesis Advisor Yaw D. Yeboah Professor and Department Head of Energy & Mineral Engineering Li Li Assistant Professor in Petroleum & Natural Gas Engineering R. Larry Grayson Professor of Energy and Mineral Engineering Graduate Program Officer for Energy and Mineral Engineering *Signatures are on file in the Graduate School

3 iii ABSTRACT With the production of oil and gas there is also production of water in large volumes which is also termed as the formation water inside the reservoir. This water when tested for the minerals present in it in a laboratory, it clearly shows a predominant presence of mineral salts which can cause a high risk of precipitations inside the reservoir due to pressure and temperature changes. These salts needs to be studied of their severity in causing the plugging of tubes, valves and the other production flow systems which can ultimately result in the abandonment of the wells. This is termed to be a very serious problem in the present day petroleum industry as it can incur very huge losses to the industry even though the wells may have the potential to produce more oil and gas. The potential players of scaling can be listed as calcium carbonates, calcium sulfates, barium sulfates and the sodium chloride. All these scales are evaluated on the basis of their saturation index values which would imply whether it would cause scaling or not. The general notation to imply the same is if the saturation index (SI) is greater than 0, it would result in scaling. If the SI value is less than 0, there is no scaling. So as to study these affects, this thesis concentrates more on the scaling potential of the different types of scales and their severity in causing the well to shut off completely. The various thermodynamics and solubility aspects involved in the determination of the saturation index of different scales are studied and quantified. Also we build a model to demonstrate the scaling potential in a particular gas reservoir with different temperature and pressure profiles to determine the saturation indices of the scales and study. The saturation index calculations for different scales are included in the model so that it shows the pressure and temperature profiles and also the scaling affects simultaneously in the model.

4 iv With this model the idea the scaling potential of four different scales are studied and quantified. This study could be a source to the major understanding of the scaling severity and how we adopt the scaling calculations into the reservoir simulation model so as to quantify the various parameters which would lead us to the identification and subsequently to the solutions to tackle this scaling problem in gas reservoirs.

5 v TABLE OF CONTENTS LIST OF FIGURES...vii LIST OF TABLES...viii ACKNOWLEDGEMENTS...ix Chapter 1 INTRODUCTION...1 Chapter 2 LITERATURE REVIEW The Scaling Problem Scale Control Measures Coiled Tubing Adding Fresh Water Seawater Injection Types of Formation water Aquifer water Transition zone Connate water Water dissolved in hydrocarbon phase Aquitard water Chemically bound water...12 Chapter 3 PROBLEM STATEMENT...13 Chapter 4 THEORETICAL CONSIDERATIONS Calcium Carbonate (CaCO3) Mechanism of Calcium Carbonate Scaling Langelier s Saturation Index Oddo & Tomson Method for Saturation Index Calculation Barium Sulfate (BaSO4) Calculation of Saturation Index Strontium Sulfate (SrSO4) Calcium Sulfate Mechanism Marcellus Shale Joule Thomson Effect...25 Chapter 5 MODEL DEVELOPMENT AND VALIDATION Conversion from mg/l to Molal:...28

6 vi 5.2. Calculation of Ionic Strength: Value of Solubility Product (Ksp): Validation of the Model:...29 Chapter 6 RESULTS AND DISCUSSION Calcium Carbonate: Barium Sulfate: Strontium Sulfate: Calcium Sulfate Joule Thomson Effect...51 Chapter 7 SUMMARY AND CONCLUSIONS...53 REFERENCES...55 Appendix: Flowback Water Analysis Report...58

7 vii LIST OF FIGURES Figure 1: Scales build up in wellbore tubulars (Ali Chareuf Afghoul, 2004)...8 Figure 2: Mechanical Scale Removal...9 Figure 3: Temperature vs constant pressure of 4000 psia at West Marcellus...38 Figure 4: Temperature vs constant pressure of 4000 psia at East Marcellus...39 Figure 5: Temperature vs SI for Barium Sulfate at West Marcellus...42 Figure 6: Temperature vs SI for Barium Sulfate at East Marcellus...43 Figure 7: Temperature vs. SI at constant pressure for Strontium Sulfate at Eastern Marcellus 45 Figure 8: Temperature vs. SI at constant pressure for Strontium Sulfate at Eastern Marcellus 46 Figure 9: Temperature vs SI for Calcium Sulfate at East Marcellus...49 Figure 11: Joule Thomson Effect for Natural Gas (Maric, 2005)...51

8 viii LIST OF TABLES Table 1: Solubility data for Calcium Sulfate...24 Table 2: Input for calculation of SI...29 Table 3: Comparison of SI's with the model and the Saudi Aramco Wells...30 Table 4: Comparison of SI's with the model and the Saudi Aramco Wells for sulfate scales.31 Table 5: Interface Page for the Excel Sheet representing the calculation of Barium Sulfate Saturation Index Values...32 Table 6: Interface Page for the Calcium Carbonate SI calculation...33 Table 7: SI values for Calcium Carbonate at West Marcellus (1066 bbls)...35 Table 8: SI values for Calcium Carbonate at West Marcellus (16126 bbls)...36 Table 9: SI values for Calcium Carbonate at East Marcellus (500 bbls)...36 Table 10: SI values for Calcium Carbonate at East Marcellus (4500 bbls)...37 Table 11: SI values for Barium Sulfate at East Marcellus (500 bbls)...40 Table 12: SI values for Barium Sulfate at East Marcellus (4500 bbls)...41 Table 13: SI values for Barium Sulfate at West Marcellus (1066 bbls)...41 Table 14: SI values for Barium Sulfate at West Marcellus (9102 bbls)...41 Table 15: SI values for Strontium Sulfate at East Marcellus (500 bbls)...44 Table 16. SI values for Strontium Sulfate at East Marcellus (4500 bbls)...44 Table 17: SI values for Calcium Sulfate at West Marcellus (1066 bbls)...47 Table 18: SI values for Calcium Sulfate at West Marcellus (9102 bbls)...47 Table 19: SI values for Calcium Sulfate at East Marcellus (500 bbls)...48 Table 20: SI values for Calcium Sulfate at East Marcellus (4500 bbls)...48 Table 21. Temperature difference from the JTC effect...52 Table 22. Change in SI for Calcium Carbonate when JTC effect is applied...52

9 ix ACKNOWLEDGEMENTS I would like to show my gratitude towards the Department of Energy & Mineral Engineering for giving me an opportunity to pursue my Master s degree at the Pennsylvania State University. I am grateful to my thesis advisor, Dr John Yilin Wang for having me in his team of building up of 3S Laboratory along with my other friends. Also I would like to thank him for allowing me to choose the thesis topic which suited me the most and it is due to his motivation and guidance that I could complete my thesis study and able to understand various concepts of Petroleum and Natural Gas study. His planned approach of arranging the group meetings and the annual meetings of 3S Laboratory through the year has provided a great platform in preparing for the thesis defense which has boosted up my confidence level. I would also like to thank my thesis committee members, Dr Yaw Yeboah and Dr Li Li for spending their precious time at my thesis defense and also for providing me various suggestions and inputs to make my thesis more presentable. I take this opportunity to thank my parents and family whose continuous support in all forms has strengthened me to be the person I am right now and for which I shall be completely indebted throughout my life. And lastly not to forget my friends who have been with me during my Master s study and has remained as a pillar of support throughout the difficult times. I personally thank Santosh Kandregula, Sarath Pavan Ketineni, Sachin Rana, Tushar Vatsa, Sridhar Ranganathan, my roommates and my several other close friends whose names I couldn t mention here for helping me out in different ways to achieve the things I desired for.

10 1 Chapter 1 INTRODUCTION In oil and gas reservoirs, entrainment of water has been a major issue due to the salts in solution that could precipitate and lead to the loss of production temporarily or abandonment of wells ultimately. The major scales include calcium carbonate, barium sulfate, calcium sulfate, strontium sulfate and sodium chloride. These scales primarily cause the fluid flow impairment and even plug-up of perforations, tubular, valves and surface equipments. The scaling mechanism is very complex where we need to consider thermodynamics, kinetic, transport phenomenon and reservoir engineering to adequately understand different scales in a given reservoir. The chemistry of the mineral scale formed is to be comprehended in an effective way so as to trouble shoot the problem arising in the reservoirs. Generally in the reservoirs where the brine is present in large volumes, when it flows out of the formation, the pressure drops and as a result the carbon dioxide in the solution comes out and causes the ph to raise, due to which the bicarbonate ions are converted to carbonate ion which initiates the process of precipitation of calcium carbonate in the reservoir formation near the well bore region which ultimately carries forward on to the tubes and valves of the production flow system on to the surface. In the case of sulfate scales, it occurs mostly at the time of the water flooding operations with incompatible injected and formation waters. This results in the formation of barium/ strontium sulfate from the mixture of both waters and the consequent permeability reduction resulting in loss of well productivity.

11 2 The salt precipitation or deposition in the oil/gas wells occur when the solubility product of the dissolved ions are exceeded due to evaporation or dissolution of rock minerals which subsequently causes a water saturation reduction and increase in the salt ion concentration, which might be the combination of any feasible combination of mineral salts. The gas expansion in the near well bore region causes the evaporation in the gas wells. (Mahadevan, 2010). In this study the scaling potential of four of the major scaling minerals are quantified which are Calcium Carbonate, Barium Sulfate, Calcium Sulfate and Strontium Sulfate. The area of study here is the Marcellus region which includes Eastern & Western Marcellus areas. The analyses of the scaling potentials are based on the calculation of saturation indices values which are obtained from the thermodynamic and the solubility approach methods. The significance of this study is that we are able to conclude in saying which type of mineral might be responsible in causing the precipitation of scale at different temperature and pressure.

12 Chapter 2 3 LITERATURE REVIEW 2.1 The Scaling Problem In the oil & gas industry, scaling problem has been a major problem in resulting production losses. It occurs on the surfaces of downhole equipment, tubulars, valves and perforations. Thus it is costly to remediate the scaling by re-perforation of producing intervals, stimulation of plugged gasbearing formations and other workovers. It is critical to identify the location and types of scale formation from reservoirs to surface due to pressure and temperature changes along the flow path. Kleinitz (2001) discussed about the precipitation of salt in gas reservoirs due to the entrainment of reservoir water may be the reason for impairing the productivity which might result in the abandonment of wells. The thermodynamic stability of the reservoir water and gas and the equilibrium for the reservoir water and the dissolved salts and also the pressure effect on the aqueous phase is explained along with the precipitation mechanism. And more importantly the identification of downhole salt precipitation is explained depending on the chemical composition of the water samples from different wells. The author has surveyed several publications including some of his own works in which they have discussed about the causes and the effects of halite scale on the production of gas. Dietzel (1998) had made some conclusions regarding the pressure and water mobilization decline from the reservoir to well surface. He owes that this process happens due to the improper stimulation techniques at decreased flowing pressure in gas wells. The author had also discussed about the halite scale modeling in which he considers the thermodynamic equilibria between reservoir water and gas. In this section he emphasizes on the proper stimulation measures that might give an early detection of salt deposition considerably of halite deposition. Also the dissolution behavior of halite is discussed that might give an idea of much rate of

13 4 halite is deposited under free convection conditions, primarily controlled by diffusion process. With this we can have the idea of how much scale is deposited at a given temperature condition. These tests are primarily done in laboratory conditions. The paper concludes that as the well head pressure decline due to the entrainment of reservoir water from gas reservoirs which ultimately results in the halite scale/salt deposition. A simulated model was developed in which the parameters are simulated which affect the deposition of salt for a well in Germany. I.R. Collins (2005) mentions about the barium sulfate formation and deposition in the oil industry. He has given a semi-quantitative kinetic approach for the prediction of the location of the barium sulfate in the reservoir through which the conclusions are such that the formation damage is negligible in near well bore region. Also the paper mentions about the three types of barium sulfate precipitations in the well depending on the scaling tendencies in the produced brine for which a method has been proposed for predicting the location at lower saturation ratios. The saturation ratios which are greater than 1000 would be entitled to precipitate instantly when the high barium brine formation water mixes with the high sulfate brine from sea water. This however would yield to reduced saturation ratio with large amount of mass being formed at the point of contact. This might be effectively showing in the tubing walls at the bottom on the well, resulting in the scale build up at the bottom of the tubing. Another scenario would be the saturation ratios ranging from 100 and 350 where the precipitation process would much depend on nucleation on the tubing walls at the bottom of the well. The author states that the kinetics of the scale growth would be rapid enough to build-up the scale process at the bottom of the tubing. The third case would be for the saturation ratios less than 100 where the nucleation process would be further delayed for a time period which would eventually allow the fluid to travel upwards. With the decrease in temperature and pressure as the brine travels upwards, the affect would be on the saturation ratio which will increase further for the barite scale to form. This would result in the build-up of the scale at the top of the tubing as the fluid approaches the surface.

14 5 Amer Badr BinMerdhah et al (2009) investigate about the permeability reduction caused by the deposition of barium sulfate in the sandstone cores from mixing of injected seawater and formation water that contains high concentration of barium ion at temperature range from and at pressure range of psig. The solubility changes are also discussed. And the particle size scaling was studied through Scanning Electron Microscopy (SEM). The result from the experiments confirms the solubility dependency for oil field scales at different temperatures. he conclude saying that the temperature increase from 40 to 0 causes in increase of barium sulfate solubility. lso the permeability decrease caused by this precipitation ranges from 5% to 19% of the initial permeability. This decrease is influenced by increasing temperatures, concentration of brine and differential pressure. Vetter (1975) gave some of the physical and chemical properties of barium sulfate based on observations from many oil and gas fields. This paper mentions about the initial works of other authors for the solubilities of barium sulfate in the brine solutions so as to understand the occurrence of this scale in actual fields. Since being an old method, it says the understanding and the sufficient information is not available to support some of the explanations. It also gives a improved method for predicting the barium sulfate precipitation. The author stresses the fact that the prediction of the barium sulfate scale must account for the thermodynamic, kinetic and hydrodynamic conditions. Due to insufficient data the pressure effects on the scaling tendencies are calculated in a few instances. To determine the kinetics of Barium sulfate precipitation, the level of supersaturation is the main parameter. Vetter states that the barium sulfate scale occurs frequently at the lower tubing orifice. This deposition is caused by the combination of thermodynamics (pressure drop), kinetics (long residence time), and hydrodynamics (flow separation). J. Moghadasi (2003) presents an experimental and theoretical study of permeability reduction of porous media caused by scaling. This paper concentrates on the kinetics of two incompatible solutions of calcium and sulfate/carbonate rich ions which by injection inside the reservoir generates within the porous medium by chemical reaction by whose mechanisms there is a permeability reduction on the pore walls due to attractive forces. All the major factors affecting the scaling discussed in this paper which includes the

15 6 scaling in tubular which forms around the wellbore. This is due to the temperature and pressure changes in the wellbore and surface areas. As the experiments were conducted on the surface apparatus, the scaling formed in the reservoir may not be indicated in the surface apparatus. Thus the author comes up with a note saying that the reservoir water and the injection water should be mixed so as to check for the scaling changes in the surface apparatus. Also the corrosion which occurs in the equipment can be ignored when the scale deposition in the wellbore region is controllable. Bedrikovetsky, et al (2009) discusses the severity of sulfate scaling in the oil reservoirs. This paper extends the previous study of the method for determination of kinetics and formation damage coefficients from production well data which has barium concentrations in produced water and of well productivity decline. The coefficients were obtained from both laboratory and field data varying in same range intervals. Marshall (1964) has given a systematic investigation through various plots for the solubilities of calcium sulfate at higher temperatures for the NaCl-Water solutions. This study was based in an electrolytic medium as a function of ionic strength for testing Debye-Huckel theory at high temperature, basically to achieve solubility data above 25. ASTM (ASTM, Standard Practice for calculation of super saturation of barium sulfate, strontiul sulfate, calcium sulfate in brackish water, seawater, and brines) gives the explanation for the calculation of saturation indices and supersaturation for the three sulfate scales which is used as a standard practice for calculation. Q.T. van Dorp (2009) reports about the halite precipitation in gas reservoirs and also the productivity decline in the wells which reveals that the halite precipitation is most likely due to water evaporation with pressure drop in the vicinity of the well bore. Also the modification for the porosity and permeability calculations due to the halite precipitation were discussed along with the evaporation and salt precipitation kinetics. Some laboratory experiments were performed using a sand pack containing high saline water at irreducible water saturation along with CT scans and conductivity experiments. Place, et al (1984) have observed that the salt plugging takes place completely after 1 Bcf production and that it needs a water wash immediately so as to start the production at the normal rate. This is the process where the gas production takes place from high temperature/high pressure reservoir (HPHT) containing brine

16 7 and as a result of which plugging takes place after some amount of specifications of gas is produced. But this paper does not inform about what type of salt is being deposited in the reservoir. Also in other papers like in that of Jasinski (1997) where a similar case of HPHT reservoir is discussed, which tells about the instances of salt deposition. The entire conclusion from these papers is that the scale deposition is due to rapid reduction in pressure which causes evaporation and ultimately the precipitation of salt. Duc Le, et al (2010) has come up with dimensionless conservation equations for solid salt saturation using numerical methods under radial flow conditions. They have basically tried to investigate on the effect of capillarity on the salt deposition process in reservoir. The major conclusions after their study include: The salt deposition occurs close to the wellbore when the wicking effect is strong and it leads to decreased permeability zone and also results in the increase of damage zone radius. In the capillary dominated conditions salt deposition leads to decrease in porosity, permeability and increase in skin factor with time Scale Control Measures Scaling control techniques can be implemented once there is decline in production from the gas wells which is bound to happen after a while due to the reservoir formation. The various methods can be used to solve the scaling are listed below Coiled Tubing Coiled tubing (CT) could be used to jet out the solid scales which are accumulated during the production. The latest CT technology can be used at elevated temperatures, pressures, and sour conditions. The industry people claim that this technology is proven to be cost-effective and are at lower risk than with the conventional methods (Shuler, 2000) such as in the High Pressure High Temperature

17 (HPH ) wells using coiled tubing conveyed fracturing and new packer technology in 8 lgeria. he reservoir conditions allow low-rate, high-pressure hydraulic fracturing treatments, which significantly increase productivity and prolong the economic life of these wells. But these require remedial cement squeeze system or tubing replacement to address the tubular problems before stimulation operations can begin. In the past, problems with conventional packers limited fracturing success because of differential pressures in excess of 9000 psi across the isolation packer. (Ali Chareuf Afghoul, 2004) Figure 1: Scales build up in wellbore tubulars (Ali Chareuf Afghoul, 2004) he igure 2 represents the mechanical scale removal technique using the technology. he Jet blaster tool consists of a rotating head with opposing tangentially offset nozzles and a drift ring. The jet nozzles remove the scale from the tubular walls while the drift ring allows the tool to advance only after the internal tubular diameter is clean. Blaster services include three mechanical scale-removal techniques: The Jet blaster method uses nonabrasive fluids for removal of soft scales The Scale blaster method adds the abrasive Sterling beads system hard scales The Bridge blaster method uses abrasive jetting and a powered milling head when tubulars are completely plugged. (Ali Chareuf Afghoul, 2004)

18 9 Figure 2: Mechanical Scale Removal Adding Fresh Water The other option to control scaling can be to add fresh water if the scaling mineral is halite. According to the calculations carried out so as to see how much amount of fresh water needs to be added to the bottom of the well, it suggests that a very small volume of fresh water can be added to prevent sodium chloride salt to drop out. This option could be useful as it also reduces the scaling tendency for the other minerals that might form during the process besides reducing the risk of halite formation. (Shuler, 2000)

19 Seawater Injection 10 Besides the fresh water option, there is also seawater injection option. But the only problem with this is that it might contain high concentrations of barium sulfate which itself is a threat for the mineral precipitation. So for that the seawater should be treated before injecting into the reservoir. One of the treatment techniques may be using the membrane process to reduce sulfate concentrations but this process would not reduce the barium concentration which makes this process to be insufficient. Hence to this a scaling inhibitor can be added to meet the challenge of reducing the barium concentrations and then select an effective treatment chemical which can withstand the reservoir conditions and the formation. (Shuler, 2000) 2.3. Types of Formation water Scale formation in the reservoir also depends on the formation water inside the reservoir. ormation water is considered to be a collective term for many different types of subsurface water that may be produced with oil & gas. (Webb, 2004) The various types of formation water include: Aquifer water This water is associated with the permeable rock strata where the movement of the aqueous phase is unhindered (Webb, 2004). Aquifer water movement could be a driving mechanism for the recovery of the oil and gas as it might help the oil or gas to come in line of the well bore. If at all the drilling goes through the aquifer water region there is high possible chance that the aquifer water may be co-produced with the oil or gas. (Webb, 2004)

20 Transition zone 11 The transition zone is the place in between the aqueous water phase and the hydrocarbon accumulation region where the pore fluids in the rock strata will travel from all water to high oil saturation. This depends on the capillary pressures and the height above the free-water level. The production of hydrocarbon and water depends on the size of the transition zone where it may be large for low permeability reservoirs. (Webb, 2004) Connate water he pore space of a reservoir charged with hydrocarbon (oil or gas) normally has a proportion of the space occupied by connate water. The volume of connate water approximates to the irreducible water saturation, S w, of the rock stratum. However, petroleum engineering defines irreducible water saturation as referring to water that is not mobile. Field experience has demonstrated that connate water can be mobile and has caused scale deposition. (Webb, 2004) Water dissolved in hydrocarbon phase As to different reservoir conditions like changing temperatures and pressures, the water present is soluble in both oil and gas. During hydrocarbon production, water can condense or evaporate at changing pressure and temperature. At this time the concentrations of different salts tends to change for a produced water sample taken at different times and as a result the whole composition water in the reservoir changes.

21 Aquitard water 12 n aquitard is a layer that has low permeability and in the terms of hydrocarbon production hinders or prevents fluid flow. e.g. shale. An aquitard is normally saturated with water because hydrocarbons unable to charge the low-permeability stratum. The slow movement of water over geological time between an aquitard and aquifer can be significant in determining the evolution of formation water associated with oil and gas production. (Webb, 2004) Chemically bound water As a result of a geological period several minerals are associated with rock strata which incorporate molecular water. These minerals can transform by either release or uptake of water. For example calcium sulfate can be deposited as gypsum initially and can transform into anhydrite. (Webb, 2004)

22 Chapter 3 13 PROBLEM STATEMENT The scaling potential for the Marcellus Region has not been studied extensively taking various scaling minerals in consideration. Some of them have come up with the scaling potentials based on the Langelier s Saturation Index which is based only on the alcium arbonate scale study. Sulfate scales are considered to be a major threat which might result in the abandonment of wells due to the precipitation of the sulfate scales near the surface. Hence there is a need to quantify the scaling potential for the sulfate as well as the carbonate scales which hinders the production process. The primary objective of this thesis is to quantify the scaling potentials of various types of scales in a shale gas reservoir at specific temperature and pressure by building a Excel model to obtain the profiles for the same. The following would be studied during the course of this thesis study: 1. The saturation indices for each of the specified scale forming compound. 2. The trend behavior for four different scales which are calcium carbonate, calcium sulfate, barium sulfate and strontium sulfate at different volumes of flowback water.

23 14 Chapter 4 THEORETICAL CONSIDERATIONS The basis of the calculations that is being looked at is the saturation ratio. yzner (1 44) had first proposed a saturation index definition for the a 3 scale prevention for the fluid waters at temperatures above 200 and low total dissolved solids. { Where SI is the saturation index, ph a is the actual ph and ph s is the saturation ph determined by measuring the methyl orange alkalinity, the calcium hardness, total solids and temperature. (Yeboah, 1991) Langelier (1946) proposed a method for calculating the saturation index of waters relative to the precipitation of calcium carbonate. This was the most basic method which was used for many years until new developments came in. This saturation index was particularly called as the Langelier Saturation Index. { This method is only useful for low concentrations of solids in fresh waters in the ph range of 6.5 to 9.5. (Yeboah, 1991) The detailed explanation of the calculation is presented in the next segment. The saturation indices proposed since 1980 were an attempt to extend the limits of applicability of the stability to higher temperatures, pressures and total dissolved solids. With this aim, Oddo & Tomson (1981) proposed a method to calculate the saturation ratio. It is defined as the ratio of the product

24 15 of the activity coefficients of the respective ions to the solubility product of the mineral in consideration. For example, Saturation Ratio = ( ) ( ) ( ) > 0 Scaling tendency < 0 No Scaling Tendency The logarithmic value of the saturation ratio is defined as the saturation index which will be calculated for the minerals in consideration. The details are explained later in the following section Calcium Carbonate (CaCO3) The calcium carbonate is a major scale in oil/gas reservoirs which have caused many wells to abandon or impair production. Carbonate scales appear mostly in the wellbore region especially near the wellhead where there is the effect of pressure drop which results in the escape of carbon dioxide from produced water which causes increase in ph of the solution inside and eventually the saturation index of the carbonate minerals which serves as the basis for the severity of the scale precipitation. (Farquhar, 2001) Its solubility equilibrium is rigorously studied to comprehend the mechanism and how severely it causes the precipitation inside the reservoir. The scaling consequences would be hugely associated with the tubes, pipes, perforations, near wellbore regions, which are the most sensitive places where the scaling can cause precipitation which can result in the abrupt closure of wells without any major production profits.

25 Mechanism of Calcium Carbonate Scaling 16 The following are the major equilibrium reactions which tend to take place when there is scale formation: CO 2(aq) + H 2 O HCO H HCO 3 - CO H CO Ca 2+ CaCO 3 (s) Langelier s Saturation Index The saturation index of this particular scale is calculated by many methods. One such method was suggested by Langelier which is employed by some companies in Marcellus to calculate the saturation index and determine the severity of the scale on the reservoir by samples of formation water taken at different volumes of different days. The formula for calculating the Langelier saturation index is given as: LSI = ph phs where, ph is the ph value of the solution that is examined. phs is the saturation ph. When the equations 2 & 3 are added, the final reaction would be looking like, Ca 2+ + HCO 3 - CaCO 3 (s) + H +.4 The equilibrium constant (Ka) can written as, Ka = H H * CO32 * CO 2 * 3 HCO3 *[ HCO3 ].5

26 17 where, γ H+... Activity coefficient for hydrogen ion γ CO32 - Activity coefficient for carbonate γ HCO3-... Activity coefficient for bicarbonate [H + ] Concentration of hydrogen ion [CO 3 2- ]... Concentration of carbonate [HCO 3 - ]. Concentration of bicarbonate The equilibrium constant, the solubility product constant (Ksp) for equation 3 is written as, Ksp = γ CO32 -. [CO 3 2- ]. γ Ca2+. [ Ca 2+ ].6 The equilibrium constant for equation 4 is written as, K = Ksp/Ka. When the simplification is done, K = Ca2 *[ Ca2 ]* HCO3 *[ HCO3 ] H *[ H ] log K = log Ca2 *[ Ca2 ]* HCO3 *[ HCO3 ] H *[ H ] By doing the logarithmic simplification, -log (H+) = -log

27 Substituting the formula for K, 18 phs = -log The activity coefficients can be calculated as, Log γ = (0.5. Zi 2. I) / (1+ I) Where, I is the Ionic Strength. Zi is the charge of the ion. Ionic Strength is calculated as, I = 2.5 * 10^-5. TDS Where TDS is the Total Dissolved Solids in mg/l. As we have temperature profile inside the reservoir, we can correlate the equilibrium constants with the temperatures as shown below: Ksp= 9.237*e *T Ka= 9.2*10-13 *T + 2.3* After substituting all the values we can calculate the Langelier Saturation Index as, LSI = ph phs. (3) Oddo & Tomson Method for Saturation Index Calculation Initially, the Langelier s method of calculating saturation index was extensively used and later on the Stiff and Davis method was extensively used in predicting CaCO3 scale in oil industry. But these methods do not deal with the estimation of scaling potential in downhole producing wells. This can be done only by

28 19 taking the downhole water samples and tested under reservoir bottomhole conditions of temperature and pressure without loss of gases or changes in chemical composition, which is considered to be a major challenge. In order to consider these conditions and calculate the saturation indices at higher temperatures, pressures, and total dissolved solids, Oddo and Tomson proposed a rather simple method for calculating the same. This method takes ph as well as varying carbon dioxide partial pressure into consideration. The saturation index can be defined as: SI = log 10 [ia p / K sp ] > 0 Scaling Tendency < 0 No Scaling Tendency Where ia p is the ionic activity product of Ca++ and CO 3 K sp is the solubility product of calcite (CaCO 3 ) The simplified expression derived by Oddo and Tomson would be as follows, One is obtained for an unknown ph as SI = log 10 {[Ca] [Alk] / PY CO2 } + A +BT +CT 2 + DP + E.I F.I When ph is known, the expression would be, SI = log 10 {[Ca] [Alk]} + ph + A +BT +CT 2 + DP + E.I F.I Where, A = B = *10-3 C = *10-6 D = *10-5 E = F = I = Ionic Strength T = Temperature (F)

29 P = Pressure (psia) 20 [Ca] = Calcium Concentration [Alk] = Bicarbonate Alkalinity (Yeboah, 1991) The above method of calculation of saturation index is employed here in this project as this takes both temperature and pressure into consideration and these are commonly used for field parameters. This method enables both ph and varying CO2 partial pressure in the calculations according to the availability of data Barium Sulfate (BaSO4) Many times in a reservoir, the seawater is injected to maintain the reservoir pressure and stimulate production. During this process the degree of risk is increased by the formation of barium sulfate scales. This has been studied very widely to understand the mechanism and to check where this particular scale is causing problem inside the reservoir. The salt precipitation is generally caused by the incompatible mixing of brine waters and the pressure, temperature changes. This precipitation of solids also occurs due to the ionic composition, ph of the solution. Barium Sulfate and the calcium sulfate scales are primarily formed by the incompatible mixing of the brines, commonly in the formation water which are rich in cations and anions like barium, calcium, strontium, sodium, chlorides, sulfates, etc. Ba 2+ (or Ca 2+, Sr 2+ ) + SO 2-4 BaSO 4 ( or CaSO 4 or SrSO 4 )

30 4.2.1 Calculation of Saturation Index 21 For the estimation of the amount of scale formed, the need to assume is that the system is in equilibrium. If a solution is supersaturated with a salt (such as CaCO3, CaSO4, BaSO4), precipitation can be expected. For a bivalent sulfate like barium sulfate, the reaction for the equilibrium solubility product constant (Ksp) is given as, MX. nh2o(s) = M ++ (aq) + X Ksp = [M ++ ] [X ] γ2 αn H 2 O where M = cation X = anion α H 2 O = Activity of water γ = Mean activity coefficient of MX defined by mixing rule as (γ+ γ-), which are activity coefficients of cation and anion. The scaling potential (SP) and the saturation index (SI) are determined by the following equations, SP = [M ++ ] [X ] γ2 αn H 2 O Ksp If the above value is > 0, it implies scaling is there and if <0 there is no scaling. SI = log (SR) SR is the saturation ratio defined as, SR = [M ++ ] [X ] γ2 αn H 2 O Ksp There is also a supersaturation ratio (SS) which gives us the maximum amount of a particular scale that can potentially deposit which is given by,

31 SS = [ M ] [ X ] {([ M ] [ X ])2 4([ M ][ X ] Ksp)} Strontium Sulfate (SrSO4) The strontium sulfate scale is considered to be another type of sulfate scale which is capable of plugging the flow of fluids or gas through the reservoir. This scale may not be that severe than that of barium sulfate but when it occurs it shows the similar kind of behavior as shown by the other barium sulfate scale. or the calculation of Strontium Sulfate scale, the solubility product data is available in the literature at 104 and 160. But with the experimental solubility data being reduced to the following regression equation the solubility product constant, K can be calculated at various solution ionic strengths over a temperature of 100 to 300 and pressures up to 3000 psig. (ASTM, Standard Practice for calculation of supersaturation of barium sulfate, strontium sulfate and calcium sulfate in brackish water, seawater and brines) Log K SrSO4 = X/R (ASTM, Standard Practice for calculation of supersaturation of barium sulfate, strontium sulfate and calcium sulfate in brackish water, seawater and brines) Where, X= 1/T, R = A+BX+Cµ 1/2 +Dµ+EZ 2 +FXZ+Gµ 1/2 Z Z= Pressure µ = Ionic Strength T = Temperature A = *10-3 B = *10-3

32 C = * D = *10-6 E = *10-12 F = *10-6 G = * Calcium Sulfate The works on the calculation of saturation index of calcium sulfate (CaSO 4.nH 2 O) or anhydrite (n=1) and its other forms like gypsum (n=2) have been achieved at different set of conditions so as to achieve an accurate calculation of the same at a given temperature which will be discussed in this section. A standard practice is employed by ASTM for calculating the supersaturation and the saturation index of calcium sulfate in brackish water, seawater and brines. But this practice is not applicable for high temperature conditions of saline waters like in the range of above 203. t the temperature above 203 F, hemianhydrate and anhydrite would be major insoluble forms. (ASTM, Standard Practice for calculation of super saturation of barium sulfate, strontiul sulfate, calcium sulfate in brackish water, seawater, and brines) But in 1964, Marshall et al, have come up with solubility data for calcium sulfate and its two other forms after a systematic investigation. he temperature range in consideration is he solution in consideration here is a NaCl-H2O solution which comes under brines category. (Marshall, 1964)

33 Mechanism 24 As similar to other sulfates calcium sulfate can form in solid form by the following reaction of ions, Ca 2+ + SO XH 2 O CaSO 4 (s) The solubility of CaSO4 and its hydrates in NaCl. H2O solutions in the temperature range of 25 to 200 are listed in the following table: Table 1: Solubility data for Calcium Sulfate Temperature (F) Solubility (Ksp) 77 63* * * * * * * * *10-6 The above are the thermodynamic values for the equilibrium of the reaction mentioned above. These values are obtained from the best fit of experimental data at each temperature. (Marshall, 1964)

34 4.4. Marcellus Shale 25 As Marcellus is considered to be the next big thing in the Natural gas industry, it becomes highly important to keep a check on the scale precipitation in this particular area of interest. In the recent studies it has been learnt that the most unexplained phenomena to be taking place in the Marcellus shale plays is the concentration of dissolved salts in the formation waters after hydraulic stimulation (M.E. Blauch, 2009). There might be many reasons behind this as this needs to answer many questions regarding shale rock characteristics, and to look if the precipitation of salt is formed near the well bore area or formation. In this research study we have considered formation water samples from the West and the East Marcellus regions of shale play. These data comprises of the cation and anion water analyses. These analyses are taken from different volumes of flowback water at different volumes taken at different times. The waters were also analyzed for the ph of the flowback water and other physical properties. Finally the report reports the values of Langelier s Saturation Index on the basis of which the severity of the scale precipitation is reported. The flowback waters from the Marcellus carries high levels of total dissolved solids in the form of soluble chloride salts (M.E. Blauch, 2009). The injected water for the fracturing job is usually fresh. The source of the produced water in the Marcellus shale is not clearly documented anywhere. As the Marcellus shale lies in between the Onundaga and Tulle formation, there is a high possibility of seepage of water from any of these formations to the Marcellus when there is some kind of injection or fracturing due to which there might be some puncture in the any of the surrounding formations. 4.5 Joule Thomson Effect When a gas expands through a restriction form high pressure to low pressure it changes its temperature. This process occurs under conditions of constant enthalpy and is known as Joule Thomson (JT) Expansion (D.P Shoemaker, 1996). Here in these conditions the JT expansion is applied to check for

35 26 the temperature changes when it passes through a restriction which is the perforation from the formation to the well bore. A numerical procedure was developed to calculate the Joule-Thomson coefficient of a natural gas. The temperature drop increases with the increase in pressure drop which is proportional to the JT coefficient. The JT coefficient can be expressed as µ JT = T p H where µ JT is the JT coefficient and H is the constant enthalpy. The temperature change can be calculated using T = µ JT where denotes the pressure loss across the perforation (Maric, 2005)

36 Chapter 5 27 MODEL DEVELOPMENT AND VALIDATION In the model development, it is tried to find out the values of saturation index values for various mineral scales, depending on which the severity of precipitation is known at different points in the reservoir and also at different temperature and pressure. The model has been developed in an Excel Sheet where input of the concentrations of various anions and cations are given. The current area of interest on which the formation water analysis is done is based on the East and the West Marcellus areas. The calculations are done based on the formation water composition in the form of cations and anions. The compositions are classified at various flowback volumes taken at different volumes and different time periods. Depending on the value of this SI, the scaling potential has been specified. Depending on the literature reviews done till now, there are much more theories or co relations to calculate the saturation index values which are more accurate or more reliable as they might consider both temperature and pressure as the basis for calculation as unlike the Langelier s saturation index (LSI) which depends only on temperatures, atleast for the Calcium Carbonate scale SI calculation. However, in our calculations for the Barium Sulfate, only temperature is used in the calculations as per the available data which does not take pressure into consideration. The requirements for the calculations are as follows: 1. The composition values for all the ions are shown in milligrams/liter (mg/l). For the calculations it is converted to molal, which is the base for calculating the saturation index value. 2. The solubility product value (Ksp) for different minerals are taken from the literature available. But these values differ for each mineral as they have been tested under laboratory conditions and

37 28 for the requirement of the values at different temperatures and pressures, they are interpolated graphically and whose values are also available from the literature Conversion from mg/l to Molal: As per the basic chemistry formula, to convert mg/l to molal, firstly it is converted to moles/liter, for which the formula is below: Moles/liter = mg/l / (1000 * Ionic Weight) Molal = Moles/liter * Specific gravity of the solution This molal value is the required activity coefficient of the ion in consideration while calculating the saturation index Calculation of Ionic Strength: Ionic strength of water under investigation: µ = 0.5 i * Zi 2 where: µ = Ionic Strength Ci = Molal Concentration of each ion in solution Zi = Charge number of ion, i Value of Solubility Product (Ksp): The Solubility product for different minerals is obtained from the literature. This value depends on the Ionic strength value for the Barium Sulfate.

38 5.4. Validation of the Model: 29 The validation used in this thesis study is that with the wells in Saudi Aramco where (Yeboah, 1991) have analyzed samples to test for the scales of calcium sulfate, calcium carbonate, barium sulfate and strontium sulfate in various wells. Table 2: Input for calculation of SI Well ph T (F) P (psia) Na + Ca ++ Mg ++ Ba ++ Sr ++ HCO 3 - Cl - SO 4 ANDR ANDR ANDR ANDR SDGM UTMN UTMN UTMN UTMN (Yeboah, 1991) Table 2 shows the input for calculation of saturation index for the four minerals in consideration. These values are applied in the model developed in this thesis and compared with the values obtained from the model developed by Yeboah (1991).

39 Table 3: Comparison of SI's with the model and the Saudi Aramco Wells 30 Validated Well SI of CaCO 3 by Yeboah SI of CaCO 3 by % of difference Phani ANDR % ANDR % ANDR % ANDR % SDGM % UTMN % UTMN % UTMN % UTMN % Table 3 shows the values from both the models which are in the percentage difference of around 0-35 %. The value of SI in the model is slightly higher than the one in the model calculated by Yeboah (1993). The difference could have been the use of the parameter of partial pressure of carbon dioxide in the Yeboah s model whereas ph was used in the thesis model. Similarly examination of the difference in SI values for the other three minerals of barium sulfate, strontium sulfate and calcium sulfate in similar conditions in the Saudi Aramco wells and the existing model is done. The values from the reference model are based on the other correlations developed whereas the values in the present model are based on the solubility data. The input values are the same as in table 2.

40 31 Table 4: Comparison of SI's with the model and the Saudi Aramco Wells for sulfate scales Well SI for SI for % Difference SI for SI for % Difference BaSO4 by BaSO4 SrSO4 by SrSO4 by Yeboah by Phani Yeboah Phani ANDR ANDR ANDR ANDR SDGM UTMN UTMN UTMN UTMN Table 4 shows the values for the Saturation indices of the two models in consideration at 220 ºF and 3000 psia. The values when compared from the SI values of Saudi Aramco wells, there is a similar trend in terms of behavior of scaling at the same temperature and pressure but the values differ for the sulfate scales of Strontium. The conditions here are near the well bore region. In the case of the saturation index values of calcium sulfate as calculated by Yeboah are for anhydrite (CaSO 4.2H 2 O) which is one form of calcium sulfate solid scale and the values calculated in the model are for calcium sulfate (CaSO 4 ). The difference comes in the values of solubility product values (K sp ) of both anhydrite and calcium sulfate. But one of the limitations for calculating the saturation index of anhydrite is the non-availability of solubility product data above 140ºF. The temperature range available is between ºF for anhydrite whereas for the calcium sulfate the range is between ºF. The values calculated in Yeboah s model are in the range of -0.5 to -0.3 whereas the thesis model