Petrol ve jeotermal sahalarında kalsiyum karbonat çökelmesinin modellenmesi

Abstract

Mineral birikintileri rezervuarda, kuyuiçinde ve yüzey donanımlarında tıkanmaya ve üretimi engelleyici sonuçlara yol açarken, petrol ve jeotermal saha işlemlerinde teknik ve ekonomik yönden olumsuzluklara neden olmaktadır. Ülkemizde de Adıyaman bölgesindeki bazı petrol sahalarında ve Batı Anadolu bölgesindeki Kızıldere jeotermal sahasında kalsiyum karbonat çökelmesinin var olduğu bilinmektedir. Kalsiyum karbonat çökelmesi, CO2 içeren su çözeltilerindeki termodinamik dengenin bozulması sonucunda CaCÛ3 mineralinin katı madde olarak çökeltiden ayrılması ve çözeltinin yer aldığı ortam yüzeyine çökelmesi şeklinde açıklanabilir. Bu çalışmada, öncelikle kalsiyum karbonat çökeliminin oluştuğu su-C02 sisteminin tek fazlı ve ( sıvı ) iki fazlı (sıvı+gaz) durumunu da kapsayacak şekilde bir pVT (basınç-hacim-sıcaklık) modeli hazırlanmıştır. Bu model yardımıyla su-C02 sisteminin termodinamik davranışı belirlenebilmekte, tek fazlı ve iki fazlı sistemin kabarcık noktası basıncı, yoğunluk, entalpi, akmazlık ve sıkıştırılabilirlik gibi önemli termodinamik özellikleri basınç, sıcaklık ve CO2 derişimine bağlı olarak bulunabilmektedir. Kalsiyum karbonat çökelimine neden olan SU-CO2 sisteminin davranışı incelendikten ve modellendikten sonra, petrol ve jeotermal sahalarda kalsiyum karbonat çökelmesi konusu çalışıldı ve bu tür sahalarda CaCOa çökelmesini bulmaya yarayacak iki model geliştirildi. Petrol sahalarında çökelmeyi, tahminde kullanılan model geliştirilirken literatürde var olan ve çökelme eğilimini bulmaya yarayan Oddo-Tomson modeli dikatte alındı, ve bu model çökelme miktarını akış yolu üzerindeki koşullara bağlı olarak verecek şekilde geliştirildi. Ayrıca, akış sırasında oluşan çökelmeden dolayı akışkanın bileşimindeki değişikliği de göz önüne alacak şekilde model düzenlendi. Geliştirilen modelin doğruluğu literatürde verilen çalışmalarla karşılaştırılıp kanıtlandıktan sonra, Adıyaman bölgesindeki Karakuş sahasındaki koşullar incelendi, sahada farklı kuyulardan ve noktalardan alınan su örnekleri analiz edildi ve CaC03 çökelmesine neden olan parametreler ve ayrıca çökelmenin olabileceği koşullar model yardımıyla belirlendi. Model sonuçlarıyla saha sonuçlarının uyumluluğu gösterildi. Jeotermal sahalarda çökelmeyi tahminde kullanılan model geliştirilirken daha önce Satman tarafindan sunulan model, bu çalışmada verilen pVT modeli ile birleştirilerek geliştirildi. Modelle Kızıldere sahasındaki çökelme incelendi, özellikle üretim kuyuları içinde çökelen kalsiyum karbonat profilleri tartışılarak model ve gerçek saha sonuçlan arasındaki uyumluluk gösterildi ve çökelmeye etki eden parametreler belirtildi.

The calcium carbonate scale is an important problem and one of the most common scales in oil and geothermal fields where large volumes of water are being produced or injected. Deposition of scale in producing and injection wells and also in surface facilities has been a costly problem in the petroleum and geothermal industries. Scale not only restricts fluid flow, but causes inefficiency and failure of production and injection equipment. The calcium carbonate scale may occur due to changes of temperature and/or pressure while a water flows from one location to the other. The deposition is the result of a supersaturated solution approaching equilibrium by precipitating some of its dissolved salts. The continuous flow of a supersaturated solution through the production or injection equipment results in the growth of a dense layer of calcium carbonate crystals. Precipitation continues until stability has been reached. Basic understanding of the scale deposition requires the knowledge of solubility of the minerals, and how their solubility are affected by changes in temperature, pressure and salinity. Many other variables including other ions, turbulence, rate of kinetics of precipitation, and seeding or nucleation all have an effect on the scale deposition. However, most of these variables are beyond the scope of definition in a field situation. Sufficient literature data do not exist to model the effects of these latter variables. As brine flows in the reservoir, up or down the well or in the surface equipment, changes in brine composition, pressure and temperature occur. For example, the pressure drops while water is flowing up the well. This causes dissolved CO2 to go out of the solution and thus the solution pH increases. The pH rise causes aqueous bicarbonate, HCOğ, to be converted to carbonate, COf", which tends to initiate precipitation of calcium carbonate, CaCÖ3, according to Ca2+ +2HCO3 -» CaC03 (solid) + H20 + C02 or Ca2+ +COf -> CaC03 (solid) Actually there are several parameters involved in the precipitation reactions of calcium carbonate. Major components are water (H2O), carbon dioxide (CO2), carbonic acid (H2C03), hydrogen ions(FT ), hydroxide(OH), calcium ions (Ca2+), carbonate (CO2") and bicarbonate (HCO3). Precipitation of calcium carbonate will occur when the product of Ca2+ and HCO3 concentration exceeds the solubility- product constant of calcium carbonate, according to the reactions given above. The scale forms as a direct result of flash boiling, flashing releases carbon dioxide from the brine, and decreases the solubility of calcium carbonate. Calcium carbonate then deposits almost immediately at any given location within field operations. Since the formation of the scale causes a considerable reduction of the well productivity/injectivity as well as inefficiency and failure of field equipment, it must be prevented or controlled. Predicting the conditions which the calcium carbonate scale occurs becomes an extremely critical step toward prevention and control of the scale that determines the technical and economical success of the field operations. Generally speaking, calcium carbonate scale increases with - decrease in pressure, - increase in temperature, and - increase in total dissolved total concentration. Therefore proper thermodynamic treatment of the CaC03 precipitation under actual flow conditions found in the field must include: 1) pressures(total and C02 partial pressure), 2) temperature, 3) precise water composition (measured and/or calculated) including the concentrations of all C02 species and pH value ( if possible). The purpose of this research was to study the calcium carbonate scale in oil and geothermal fields and to obtain reliable models valid for these fields that will give the amount of calcium carbonate scale that would be formed by a water. The first step of any prediction of CaC03 must include the mathematical treatment of the distribution and concentrations of C02 species as a function of the thermodynamic conditions within the aqueous solution. A pVT (pressure- Volume- Temperature) package was prepared to model the thermodynamic behavior of the brine-C02 system. Data for the solubility of C02 in pure water and sodium chloride solutions was obtained from the literature. Other relevant experimental data on density, enthalpy and viscosity of the brine-C02 systems was also collected. Data was correlated into the forms of simple expressions whenever necessary. The effects of pressure, temperature, brine composition and partial pressure of C02 were all incorporated in the pVT package. The effect of salt content on the thermodynamic properties of the H2O-CO2 system was added into the pVT package. The p VT package developed in this study calculates the thermodynamic properties of liquid water, steam and C02. The bubble point pressure (or flashing point pressure) curve and dew-point pressure curve of the two-phase envelope can be calculated. Effect of C02 on the elevation of the bubble point pressure is fully and accurately described. The isoenthalpic compressibility for a C02-water system at flashing point pressure is introduced and an expression giving this compressibility is discussed. Results in terms of figures giving the relationship between pressure, temperature, enthalpy, quality, C02 content, compressibility and viscosity are presented. The pVT package developed particularly is helpful in understanding of the two phase (liquid plus gas) behavior of brine and C02 system. Results obtained from the pVT package were compared with experimental data provided in the literature xvii and a very good fit was obtained. The observed and measured behavior of the Kızıldere geothermal water was also used to verify the accuracy of the pVT package. The agreement between actual results and those computed by model was excellent. The second and equally important step of CaCQ3 prediction is the proper calculation of CaC03 solubility product based upon the entire composition of aqueous liquid as a function of total pressure and temperature. If the measured ionic product exceeds the calculated solubility product of CaCÛ3 in solution at equilibrium, a precipitation of CaC03 can be expected Two models, one for oil and another for geothermal fields, were developed in this study to predict the calcium carbonate precipitation, Models take measured or preassigned data and calculate the equilibrium brine composition. The calculated brine composition data can then be used either to predict the CaCC>3 precipitation at any set of prescribed conditions or to predict the CaC03 precipitation at various locations within oilfield or geothermal operations. The oil model employs equilibrium constants given by Oddo-Tomson[42]. Similar to the Oddo-Tomson model it can determine the calcium carbonate scaling tendency of the oil field waters. Furthermore, an extension of the model was developed to determine the maximum amount of precipitation and to calculate the composition of the remaining solution which is the superiority of the developed model to the Oddo- Tomson model. After developing the model, its validity was tested, The match between the model results and the results of the case studies available in the literature was satisfactory. The Karakuş oil field in the southeastern region of Turkey is one of the fields with calcium carbonate scale problems. The calcium carbonate scale was observed in the surface pipes and equipment. The production and fluid data of this field was used to study model. Brine samples from the wells where scale has been observed were collected and analyzed to determine the variation of brine composition throughout the field. Scale analysis was performed to find the cause of scale buildup. Results of the model indicate scaling conditions and the parameters such as pressure, temperature, brine composition and mole fraction of CO2 contributing to the potential to produce scale were studied. It is not surprising from the scale analysis that some wells produce scale continuously, some intermittently, and some not at all, based on the saturation index and amount of the scale calculated for the wells. It is difficult to know the actual temperatures, pressures and mole fraction of CO2 in flow paths and hence the true scaling potentials of the individual wells. Nevertheless, the comparison of the results of the analysis with field observations was found to be satisfactory. The oil model developed in this study has broader application ranges as compared to the ranges of traditional Stiff-Davis [37] index, and also has the capability of predicting the amount of calcium carbonate precipitation and change in brine composition which Oddo-Tomson model can not predict. The geothermal model is based on equilibrium thermodynamics, and uses the experimentally measured solubility and related parameters. It consists of a set of equilibrium constants given by Plummer-Busenberg[77]. Data for the solubility of CO2 in sodium chloride solutions were obtained from Ellis-Golding[78]. Data given by Helgeson[73] and Plummer-Busenberg were used to calculate individual ion activity coefficients. The structure of the model is similar to the original Satman's model [33]. Improvement to the original Satman's model includes algorithms related XVlll to the pVT package developed in this study. The geothermai model considers the flow of brine and CO2 whereas the oil model considers the flow of brine, CO2 and as well as oil. The other fundamental difference between the geothermai and oil models is that the geothermai model employs the thermodynamic equilibrium constants and the activity coefficients whereas the oil model employs the conditional constants including activity coefficients. The temperature, total pressure, CO2 partial pressure and water composition determine the type and concentration of CO2 species(C02, HCOğ, and COg") in the aqueous solution under any given set of conditions. A change of any of these conditions may lead to a change of distribution of the CO2 species in this aqueous solution. If the COl~ concentration increases due to removal of CO2 from the solution, the solubility product of CaC03 can be reached and precipitation of CaCCb can start. Thus, a simple removal of CO2 from aqueous solution can start the precipitation of CaC(>3 The temperature and pressure profile to which the brine is subjected in the wellbore is required for the prediction. The model either takes the measured data as input or calculates the temperature-pressure-quality profile in the wellbore by incorporating the pVT package and a subprogram formatted to employ Orkiszewski method[106] and the method presented by Chierici et al [121] to determine two-phase pressure drops. The geothermai model first determines the initial conditions of calcium in the solution at equilibrium conditions unless it is given as an input. In order to estimate the amount of calcium precipitation at any point in the system with known pressure, temperature, partial pressure of CO2 and brine composition, the new equilibrium value of the molality of calcium is subtracted from the initial calcium concentration at this point. The calcium carbonate scale has been a continuous problem since the beginning of the energy production from the Kızıldere geothermai field. Several wells in the field produce about 1000 ton/hr brine and brine contains between 1-2 % (by weight) CO2 in solution under reservoir conditions. However due to severe scale problems, the production from the field is interrupted periodically and wells are mechanically cleaned or acidized to remove the deposits. Scale analysis using geothermai model was performed to understand the cause of scale buildup in wells and surface facilities such as separators and surface pipes. Actual field data from the producing wells in Kızıldere were used as input data. Several samples from the effluent brine and streamline were collected. The samples were analyzed for their chemical constituents; especially for the total CO2. The capability of the model was demonstrated by the scale analysis performed. Model results giving the precipitation profiles in the selected wellbores resemble the actual profiles observed in the producing wells. Results indicate that the flashing pressure is the most critical parameter for the beginning of precipitation. As soon as the pressure drops below the flashing pressure, C02 starts to flash and precipitation take place. Main accomplishments of the study are summarized below: -A new pVT package was prepared to model the thermodynamic behavior of the brine-C02 system. It determines the main thermodynamic properties of liquid water, steam and CO2. ?xix -A new oil model that yields the saturation index and the amount of calcium carbonate precipitation was developed. It considers the effects of temperature, pressure, brine composition and the solubility of C02 in oil and gas phase. The model can be used to analyze any production/injection well or surface flow path where calcium carbonate scale occurs. - An updated version of Salman's geothermal model was developed by incorporating the pVT package given in this study. The model was verified to be particularly valuable for geothermal operations. It can be used for simulating calcium carbonate deposition mechanism and obtaining information related to the effects of various parameters on deposition. Results of the model can be utilized in choosing the optimum production or injection conditions to minimize the calcite deposition.