SPE 161478 Experimental Investigation of Wet Gas Dew Point Pressure Change with Carbon Dioxide Concentration Odi, U. Texas A&M University, El Hajj, H. Texas A&M University at Qatar, Gupta, A. Texas A&M University at Qatar Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the Abu Dhabi International Petroleum Exhibition & Conference held in Abu Dhabi, UAE, 11–14 November 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Dew point pressure is a critical measurement for any wet gas reservoir. Condensate blockage is likely when the reservoir pressure decreases below the dew point pressure and this can result in a reduction of gas productivity. Errors in measuring dew point pressure can lead to errors in the estimation of the onset of condensate blockage and thus be detrimental to the management of wet gas fields. This work presents experimental verification of a new method of determining dew point pressures for wet gas fluids. Results obtained from this method are compared to calculated values based on Peng Robinson equation of state. Dew point pressure determination is important when devising solutions on how to prevent condensate blockage. One possible treatment fluid, carbon dioxide, has the ability to lower dew point pressures and thus delay the onset of condensate blockage. The novel method presented in this work was applied to determine the experimental dew point pressure of several wet gas mixtures as a function of carbon dioxide concentration. These experiments also show the potential of using carbon dioxide to lower dew point pressures in wet gas fields. Experimental results show close match between the experimental estimates of dew point pressure and the Peng Robinson calculations. Experimental results also support the general observation that carbon dioxide has the ability to lower the dew point pressure of wet gas fields. The results of this work are useful in Enhanced Oil/Gas Recovery processes that utilize carbon dioxide and for Huff and Puff which uses carbon dioxide to remove and prevent further build-up of condensate banks in wet gas reservoirs. This work investigates experimental conditions showing the change in dew point pressure as a function of carbon dioxide concentration. This dynamic relationship can be used to tune equation of state models which, in turn, allows more accurate reservoir modeling of hydrocarbon recovery process. Introduction Condensation is a critical factor in determining the performance of wet gas fields. Condensation in the near wellbore region can lead to a dramatic reduction in gas flow due to the reduction of effective permeability to gas. Gas relative permeability reduction in the near wellbore region is primarily caused by an increase in liquid saturation due to condensation. This can be observed by studying a typical gas relative permeability relationship as illustrated in Figure 1. In a gas condensate system, a small reduction of gas phase saturation can correspond to an exponential decrease in gas relative permeability. Figure 1 illustrates that as the liquid saturation increases, and the gas phase decreases from the maximum saturation value, there is a dramatic decrease in a relative permeability. 2 SPE 161478 Figure 1: Relative Permeability Relationship between Gas and Condensate Phase In wet gas reservoirs, increase in liquid saturation, which is the primary reason for reduction of gas relative permeability, is caused when the bottom hole pressure drops below the dew point pressure. Gas reservoir operators often allow this in absence of accurate values for dew point pressure or in order to maintain economic gas production rates from the wells. In order to accurately identify minimum pressure level that must be maintained in a gas reservoir, dew point pressure measurements can be conducted using a representative sample of the reservoir fluid in a PVT apparatus. For a wet gas reservoir, PVT experiments and analysis are needed to measure the dew point pressure at the known reservoir temperature. The simplest conventional method of determining the dew point pressure of a hydrocarbon gas mixture is a visual test that requires collection of a representative wet gas sample at reservoir conditions and testing it in a PVT cell chamber with a glass window. During the dew-point experiment, the sample is first equilibrated at the initial reservoir conditions of pressure and temperature and then, starting from a high pressure gas phase, it is gradually depressurized in the PVT cell to observe physical changes through the glass window into the cell. The first instant of condensation, seen as slight clouding of the window, is referred to as the dew point pressure for the sample. The limitation of this method is that the observation of condensation can be subjective and contribute to erroneous estimation of dew point pressure leading to inaccurate wet gas characterization. Another method of dew point measurement involves using the acoustic signature of the sample fluid. The acoustic method relies on acoustic theory which states that the acoustic response is proportional to the velocity of signal through the fluid (Sivaraman et al, 1997). To determine the dew point using the acoustic method requires using an apparatus that is capable of transmitting an acoustic signal through a reservoir fluid and receiving and analyzing the signal that transmits through the reservoir fluid. The travel time and alteration in signal during transit through the reservoir fluid is used to characterize the physical phase of the reservoir fluid. Determination of the dew point pressure using this method requires performing a constant composition expansion test similar to the visual method. The first instance of a liquid signature in the vibrational response during this test is defined as the dew point pressure. The limitation of this method is that it still requires the visual method to validate the estimated dew point. Thus, any PVT apparatus that is designed to implement the acoustic method must have a window cell to ensure accuracy, in addition to the equipment that can transmit and receive the acoustic signal. The capital investment needed for the acoustic method can be significantly higher than for the standard PVT cell used for the visual method. Potsch et al. (1996) presented a method to determine the dew point pressure graphically. Their method involved using the real gas equation of state to calculate the total moles in the reservoir fluid sample for several measurements of pressure above the dew point pressure. They proposed that below the dew point pressure, condensation will cause calculated moles in the gas phase to be different from the actual number of moles. They proposed that the first instance from the deviation from the true amount of moles indicates dew point pressure. Their work may be in error because the real gas equation of state is not valid for fluids near the saturation pressure as indicated by their plots of the calculated molar quantity changing with pressure above dew point pressure. For a valid method, the calculated amount of moles would have remained constant because of the conservation of mass in the PVT cell (no mass exits or leaves the PVT cell). Potsch et al.’s attempt to characterize the dew point pressure appears to be theoretically inaccurate. The method proposed in this paper is based on tracking changes in compressibility to pinpoint dew point pressure measurements in wet gas fluid samples. Using this method, this work demonstrates the potential of using CO2 to lower the dew point pressure as a solution to condensate blockage. Comparisons with Peng Robinson equation of state are used to validate the approach illustrated in this work. SPE 161478 3 Saturation Pressure Theory Dew point pressure can be described as the pressure at which a gas starts condensing into a liquid phase. Pressure and temperature phase diagrams are generally used to describe bubble points and dew points as functions of pressure and temperature. For example, Figure 2 illustrates a pressure and temperature phase diagram for a wet gas that exhibits retrograde condensation. The dew-point line, the line that is to the right of the critical point can be used to describe variation of dew point pressure with temperatures. Figure 2: Pressure and Temperature Diagram for Wet Gas/Condensate with CCE Isotherm When analyzing the results of constant composition expansion (CCE) experiment, a general test used to estimate bubble and dew points using the visual method, it is important to understand the thermodynamic changes that occur to the reservoir fluid during phase change. Determination of bubble points using the graphical method based on CCE tests is made possible by the large differences between the compressibility of liquid phase less dense gas phase. Determination of phase changes involved in the transition from the gas phase to the liquid phase is much more difficult due to indistinguishable slope changes. Such is the case when looking at dew points of gas condensates. This can be illustrated by considering an isotherm in the pressure and temperature phase diagram of an example wet gas/condensate as illustrated by Figure 2. Starting from the super critical gas region, as the pressure drops isothermally, there is an expansion of the system volume as the wet gas/condensate transitions from the supercritical gas region to the gas region and finally past the dew line. When the reservoir fluid undergoes decompression there is a gradual change in the total compressibility of the reservoir fluid. This can be understood by considering the total isothermal compressibility of the reservoir fluid inside the PVT cell described by the following equation. CT 1 V t ………………………………………………………………………………………………………...…(1) V t P Where CT is the total isothermal compressibility, Vt is the total volume of the fluid mixture in the PVT cell, and P is the pressure of the fluid. Above the dew point line the total isothermal compressibility represents the compressibility of the supercritical gas phase. Below the dew point the total compressibility can be derived using material balance between the gas and liquid phases. The final derived form of the total compressibility for all stages of compression is represented in the following expression for the PVT cell. CT C G S G C L S L 1 Vt 1 1 m g G P L ………………………………………………………………………......(2) Where CG is the gas compressibility, SG is the gas saturation in the PVT cell, CL is the liquid compressibility, SL is the liquid saturation in the PVT cell, ρL is liquid density in the PVT cell, ρG is the gas density in the PVT cell, mg is the mass of the gas phase of the PVT cell. This expression has important implications at saturation pressure and in the two phase region. For example, at the dew point of the solution, the first drop of liquid (SL>0) results in a reduction of the gas phase (SG<1). In addition, the third term in Equation 2 is positive at the dew point since the density of the gas phase is less than the liquid phase density and the change in gas mass with respect to pressure is negative as a result of the mass transfer of the gas phase into the liquid phase. This results in a subsequent increase in the total apparent compressibility at the onset of condensation. At the onset of condensation the liquid volume is extremely small when compared to the gas volume. This can be seen in the Peng Robinson simulated typical wet gas/condensate (Figure 3). 4 SPE 161478 0.3 0.25 Liquid Saturation 0.2 0.15 0.1 0.05 0 0 1000 2000 3000 4000 Pressure, psia 5000 6000 7000 8000 Figure 3: Liquid Saturation for Wet Gas/Condensate system during CCE In this figure the liquid saturation represents the liquid volume fraction of the total sample volume. A small liquid saturation corresponds to a small liquid volume. At approximately 5000 psia the liquid saturation is initially 0%. It subsequently increases to a value of 27% indicating the onset of condensation. During this pressure range, the rate of mass increase in the liquid phase is negative with pressure and, based on material balance, the rate of mass increase in the gas phase is positive with pressure. Thereforel, the total compressibility increases according to equation 2. Determining the increase/decrease in the total compressibility with pressure is the main premise of the method used in this work. When the total compressibility deviates from the linear compressibility behavior during the CCE process, it is the theorized that this is the dew point pressure. The general procedure to use the compressibility involves completing the following tasks. 1. Use the CCE experimental data (pressure and volume data) to calculate the central difference approximation of the compressibility as indicted in Equation 1. 2. Create a plot of the calculated compressibility versus the experimental pressure of the CCE experiment. 3. Starting from the highest pressure of the compressibility versus pressure plot locate the first linear line and draw a line through it. 4. Find the nearest linear line next to the first linear line and draw a line through it. 5. The intersection between the first and second linear line is the observed dew point. Experimental Design To test the new dew point determination method several condensate mixtures were created. These condensate mixtures include a base condensate mixture with a 1% molar composition of CO2. The other condensate mixtures contained 5%, 10%, and 15% molar concentrations of CO2. The base condensate mixture components can be seen in Table 1. Critical properties were based on values reported in literature. Acentric factor values were obtained from Winnick (1997) and Poling et al (2001). Density values were obtained from the API data book. The purpose of using these condensate mixtures was to understand the effect of adding CO2 to the base concentration and to also illustrate the methodology of the new dew point determination method. SPE 161478 5 Table 1: Base Composition for Experimental Studies Component Composition, mol % Molecular Weight Critical Temperature, oR Critical Pressure, psia Acentric factor Methane 83 16.04 343 667 .007 Liquid Density (60 o F), lb/gal 2.5 Carbon Dioxide 1 44.01 547.4 1069.5 .225 6.82 Ethane 4 30.07 549.6 706.6 .099 2.97 Propane 3 44.1 665.7 616.1 .153 4.227 Octane 3 114.23 1043.9 422.8 .398 5.894 Dodecane 6 170.34 1215.6 315.3 .576 6.276 To load, mix, and observe the hydrocarbon phase transitions of the proposed condensate mixtures, a pressure, volume, and temperature (PVT) system (illustrated in Figure 4) was used. As an example of the process used to create and transfer a mixed condensate, consider the base condensate in Table 1. To calculate the necessary molar amounts of each component requires determination of the volumetric amount of each component at ambient conditions. At atmospheric pressure and room temperature the only components that are in the liquid phase are octane and dodecane. The volumetric amount of these liquid components can be found by using the following equation. Vi MWi y i nt i ………………………………………………….……………………………………………………...…(3) Where Vi is the ith liquid component’s feed liquid volume, ρi is the ith liquid component’s density at standard conditions, MWi is the ith liquid component’s molecular weight, and yi is the ith component’s mole fraction in the gas condensate mixture. c b d a e b Figure 4: PVT System for Dew Point Measurement (a) Oven (b) Computer Gathering Equipment (c) Top Pump B (d) PVT Visual Cell (e) Bottom Pump A The remaining components in the condensate mixture are gases at standard conditions. To feed the required number of moles of each gas component into the PVT system requires loading the gas components at a target pressure and corresponding volume. Setting the volume of each gas is much easier to control than pressure, therefore the loading pressure of each gas component was determined using the Virial equation of state. The following steps can be used to determine the feed pressure of a component using the Virial equation of state. 1. 2. Guess a working pressure of the component, Pi, and loading volume of the component, Vi. For the component, determine the reduced pressure, Pr, and reduced temperature, Tr. Tr T ………………………………………………………………………………………………...………...…(4) Tc 6 SPE 161478 Pr 3. P ……………………………………………………………………………………………...………...…(5) Pc Where Tc and Pc are the critical temperature and critical pressure of the component. Calculate the Virial coefficients (Winnick, 1997) using the following equations. B ( 0 ) 0.083 0.422Tr 1.6 B (1) 0.139 0.172Tr 4.2 zi 1 5. (1) Br Pr …………………………………………………………………………..……….....……..........…(9) Tr Recalculate the working pressure, Pi, using the real gas law. Pi 6. ………………………………………………………………..………...…….......…(7) Br B B …………………………………………………………………………..………......…….....…(8) Where ω is the acentric factor of the component. Calculate the compressibility factor of the component, zi. ( 0) 4. ………………………………………………………………..………...………...…(6) z i y i nt RT ………………………………………………………………………………………………...…(10) Vi Repeat steps 2-5 using the calculated Pi from step 5. Iterate until the value of Pi converges. The procedure to calculate the feed pressure of each component is based on the Virial equation state and assumes that the reduced pressure and reduced temperature are within the low density region. This region corresponds to a reduced temperature and reduced pressure relationship that results in reduced temperatures greater than approximately Tr = .436Pr + 0.6 (Winnick, 1997). Once the feed liquid quantities and feed gas components are calculated it is important to ensure that the total mixture can reach system pressures larger than the expected dew point pressure of the condensate system. This is important because the CCE experiments are begun at pressures much larger than the dew point pressure. Using this assumption, values of the compressibility factor were calculated using an empirical version of the Standing correlation described by Cronquist (2001) which is dependent on the pseudo critical properties of the mixed condensate. The pseudo critical temperature and pressure were calculated using a correlation by Piper et al (1993) which accounts for reservoir impurities such as nitrogen, hydrogen sulfide, and carbon dioxide. As an example of this process, consider the base condensate listed in Table 1. The phase diagram of this condensate is illustrated in Figure 5. Figure 5: Pressure-Temperature Phase Diagram for Base Condensate From the phase diagram, it can be seen that for a CCE experiment at 200oF, the dew point pressure is approximately 5000 psia. Therefore, at 200oF the initial pressure of the system is set to 6000 psia which is greater than the dew point pressure. Using this and the volume of the PVT cell it is possible to calculate the total amount of moles that will ensure that the PVT cell reaches the initial starting pressure. These steps are listed here. 1. Calculate the gas specific gravity, γg, of the gas condensate sample. SPE 161478 7 6 y MW i g 2. i 29 i ………………………………………………....................................................…….....…(11) Calculate the pseudo critical temperature, Tpc, and pseudo critical pressure, Ppc, using Piper et al. (1993) correlation. Assume a pressure larger than the dew point pressure, Pt, and a temperature, Tt, used for the CCE experiments. 3 T 2 J 0 f y f c 4 g 5 g …………………………………………………...……...….…(12) f 1 Pc f 3 T 2 K 0 f y f c 4 g 5 g ………………………………………………...……….…(13) f 1 Pc f T pc Ppc K2 ……………………………………………………………………………………………......……(14) J T pc J ……………………………………………………………………………………………...…...…(15) The parameter, f, corresponds to the reservoir fluid impurities in the following order H2S, CO2, and N2. Values for ηf and βf are shown in the following table. Table 2: Piper et al (1993) Parameters for Pseudo Critical Temperature Pressure Calculation f ηf βf 0 1.1582E-01 3.8216E+00 1 -4.5820E-01 -6.5340E-02 2 -9.0348E-01 -4.2113E-01 3 -6.6026E-01 -9.1249E-01 4 7.0729E-01 1.7438E+01 5 -9.9397E-02 -3.2191E+00 3. Calculate the compressibility factor, zt, of the condensate sample at the expected experimental conditions above the dew point pressure using the Standing correlation (Cronquist, 2001). Tt ………………………………………………………………………………………...………...…(16) Tpc P Ppr t ………………………………………………………………………………………...………...…(17) Ppc Tpr A 1.39T pr 0.92 0.36T pr 0.101 …………………………………………………...………..…(18) 0. 5 6 0.066 2 0.32 Ppr B 0.62 0.23T pr Ppr 0.037 Ppr 9 ……...……………...…….....…(19) 10 T pr 1 T pr 0.86 C 0.132 .32 log T pr …………………………………………………...………………………….….…(20) 0.3106 .49T 0.1824 T 2 pr pr D 10 ……………………………………………...………………………….….......(21) D B z t A 1 Ae CPpr ……………………………………………………………………...……….....(22) 4. Recalculate the pressure of the cell at the CCE conditions using the expanded volume of the cell, Vt, and the real gas law. Pt 5. zt nt RTt …………………...………………………………………………………………………….…(23) Vt Repeat steps 3-4 using the calculated Pt from step 4. Keep doing this until the difference between each iterative Pt is minimized. 8 SPE 161478 The preceding procedure is dependent on the total amount of moles, nt, in the PVT cell which is also a necessary component in the calculation of the volumetric amount of liquid needed and the calculation of the loading pressure for the gas components. Therefore, any changes made to the total amount of moles in the preceding procedure have to be followed by recalculations of liquid volumes and gas component loading pressures (at specified loading volumes). As example of these considerations, consider the base condensate mixture in Table 1. For a CCE experiment at 200 oF (660 oR) for a PVT cell with 18 cm3 volume (with a value of 100 cm3 out of a possible 200 cm3 of additional adjustable volume used for compression and expansion) the calculation of the necessary parameters are listed in Table 3 and Table 4. Table 3: Calculated Liquid Volumes for Base Case Component Feed State Vi, cc Methane gas n/a Carbon Dioxide gas n/a Ethane gas n/a Propane gas n/a Octane liquid 6.64 Dodecane liquid 18.6 Table 4: Gas Calculations for Loading Pressures, Pi, Using Specified Loading Volumes, Vi, for Base Case Pi Pi Component Feed State guess, Tr Pr B(0) B(1) Br zi Vi, cc calculated, psia psia Methane gas 2698 1.55 0.718 -0.13 0.111 -0.13 0.6687 100 2698 Carbon gas 48 0.968 0.144 -0.36 -0.0580 -0.37 0.983 100 48 Dioxide Ethane gas 176 0.964 0.202 -0.36 -0.0613 -0.37 0.9044 100 176 Propane gas 125 0.796 0.124 -0.52 -0.309 -0.57 0.8547 100 125 Octane liquid n/a n/a n/a n/a n/a n/a n/a n/a n/a Dodecane liquid n/a n/a n/a n/a n/a n/a n/a n/a n/a Table 5: Parameters used to calculate .003 total lbmols needed to reach 6000 psig at 200oF (Volume used for calculation is 118 cc) ɣg 1.03 J 0.736 K 18.3 o Tpc, R 457 Ppc, psi 621 Tpr 1.16 Ppr 9.67 A 0.163 B 20.5 C 0.111 D 0.972 zt 1.17 Pt, psig 6000 The total amount of moles needed to bring the system to 6000 psig was found to be 0.003 lbmol. This quantity is verified because it can be used to calculate the 6000 psig desired pressure at 200 oF and 118 cc of available volume (Table 5). This quantity was also found to satisfy the procedure of determining the gas loading pressures (Table 4) and the required liquid volumes (Table 3). SPE 161478 9 Experimental Results Dew points were determined for the synthetically designed condensate mixtures by observing changes in compressibility from constant composition expansion experiments and verified by equation of state models such as Peng Robinson equation of state. As an example of the process of using the compressibility to determine the dew point pressure, consider the 15% CO2 case at 200 oF. Its CCE isotherm (Figure 6) illustrates the pressure volume relationship for this fluid. The total compressibility of this fluid was calculated for each pressure point (Figure 7) using a central finite difference version of Equation 1. 15% CO2 in Base: Pressure versus Volume at 200 oF 7000 6000 Pressure, psia 5000 4000 3000 2000 1000 0 50 55 60 65 70 75 Volume, cc 80 85 90 Figure 6: CCE isotherm for 15% CO2 in Base Case at 200 oF 95 100 10 SPE 161478 15% CO2 in Base: Compressibility versus Pressure at 200oF 0.0006 Compressibility, 1/psi 0.0005 0.0004 0.0003 0.0002 3116.7 psia 0.0001 0 0 1000 2000 3000 4000 Pressure, psia 5000 6000 7000 Figure 7: Dew Points Determination using compressibility versus pressure plot for 15% CO2 in Base Case at 200 oF Figure 7 illustrates a substantial increase in the compressibility at approximately 3117 psia. This large increase is attributed to the first instance of liquid saturation in the PVT cell. According to Equation 2, the first appearance of liquid saturation and volume can cause substantial increases in the total compressibility. Using this large rise in compressibility, the dew point for the 15% CO2 case is approximately 3117 psia. The compressibility methodology was applied to the Base case, 5% CO2 case, 10% CO2 case, and the15% CO2 case. Results of the dew point measurement of each case can be seen in Table 6 and Figure 8. Table 6: Comparison of Dew Point Measurements at 200oF New Method, psia Peng Robinson, psia Absolute Error, % Base Case 5627 5000 13 5% CO2 in Base 3548 4800 26 10% CO2 in Base 3530 4600 23 15% CO2 in Base 3117 4400 29 SPE 161478 11 6000 5500 Pressure, psia 5000 4500 4000 3500 3000 2500 2000 0 2 4 6 Peng Robinson 8 10 CO2 mol% 12 14 16 Compressibility Method Figure 8: Dew Point Comparison as Function of CO2 Concentration in Base Composition at 200oF When comparing the dew point measurement among each case at 200 oF it can be seen that CO2 has the unique ability in reducing the dew point pressures. This is observed experimentally in Figure 8 and Figure 9 which is a plot of the relative volume (PVT volume divided by the volume at the dew point). 7000 6000 Pressure, psia 5000 4000 3000 2000 1000 0 0 0.2 0.4 Base Case 0.6 0.8 1 1.2 Relative Volume, 5% CO2 in Base 10% CO2 in Base 1.4 1.6 1.8 15% CO2 in Base Figure 9: Experimental Relative Volume of Base Condensate as function of CO2 at 200oF 2 12 SPE 161478 The relative volume plot in Figure 9 indicates that CO2 decreases the corresponding pressures observed during CCE. The Peng Robinson approximation of the relative volume, as illustrated by Figure 11, indicates the same relationship. In addition to this, the overall phase diagram of the gas condensate illustrates that the phase envelope decreases as a function of CO2 concentration. This is conveyed in Figure 10. These results can be explained by analyzing previous studies of CO2 with hydrocarbon systems. Monger et al. (1981) were able to illustrate in their Appalachian crude oil system that the crude oil aromaticity correlated with improved hydrocarbon extraction into a CO2 rich phase. In addition to this, Monger et al. observed that CO2 has the ability to lower miscible pressures for paraffin fluids that do not contain large amount of aromatic content. In terms of gas condensate systems, this means that CO2 forces the lighter end hydrocarbons into the CO2 rich phase. This is beneficial because the CO2 rich phase is a supercritical gas in typical reservoir conditions which implies that CO2 is lowering the hydrocarbon’s dew point pressure. 6000 5000 Pressure, psia 4000 3000 2000 1000 0 300 400 500 600 700 Temperature, oR 800 900 Base Condensate 5% CO2 10% CO2 15% CO2 Base Condensate Critical Point 5% CO2 Critical Point 10% CO2 Critical Point 15% CO2 Critical Point 1000 660oR (200oF) Isotherm Figure 10: Peng Robinson Phase envelope of gas condensate as function of CO2 concentration SPE 161478 13 8000 7000 Pressure, psia 6000 5000 4000 3000 2000 0.6 0.8 Base 1 1.2 1.4 Relative Volume, 5% CO2 in Base 1.6 10% CO2 in Base 1.8 2 15% CO2 in Base Figure 11: Peng Robinson Relative Volume of Base Condensate as function of CO2 at 200oF In terms of liquid compressibility, the Peng Robinson approximation of the liquid saturation during CCE (Figure 12) gives an indication that there is less liquid dropout occurring as the amount of CO2 increases. In regards to production from gas condensate reservoirs, this is beneficial because this shows that increasing the CO2 concentration can decrease the maximum amount of liquid saturation that can occur in the reservoir. 0.3 0.25 Liquid Saturation 0.2 0.15 0.1 0.05 0 0 1000 Base 2000 3000 5% CO2 in Base 4000 Pressure, psia 5000 10% CO2 in Base 6000 7000 8000 15% CO2 in Base Figure 12: Peng Robinson Liquid Saturation of Base Condensate as function of CO2 at 200oF 14 SPE 161478 Retrograde Behavior In determining dew points using compressibility it is important to also consider the possibility of lower dew points which are indicative of retrograde reservoir fluid behavior. The lower dew point can be found using the compressibility method by noticing sharp deviations in the compressibility slope after determination of the upper dew point. Understanding the reason that this happens can be understood by first considering the empirical definition of compressibility as indicated by Equation 2. At the lower dew point the liquid saturation disappears (SL = 0) leaving room for the more compressible fluid which is gas to define the total compressibility. Gases respond to small decreases in pressure with sudden increases in compressibility. In the case of retrograde fluids this means that the second change in slope is the sharp rise in compressibility representative of single phase gas behavior. An example of this can be seen for the 10% CO2 in the Base case as illustrated by Figure 13. 10% CO2 in Base: Compressibility versus Pressure at 200 oF 0.0007 0.0006 Compressibility, 1/psi 0.0005 0.0004 0.0003 Lower Dew Point = 2344.7 psia 0.0002 Upper Dew Point = 3529.7 psia 0.0001 0 0 1000 2000 3000 4000 Pressure, psia 5000 6000 7000 Figure 13: Lower Dew Point Determination using compressibility plot for 10% CO2 in Base Case at 200 oF From the plot there is a clear distinction between different slopes. The first change in slope represents the transition from the super critical region to the two phase region. The second change in slope represents the transition from the two phase region to the gas region which is indicative of retrograde behavior. This retrograde behavior represents possible errors associated with preparing the 10% CO2 wet gas sample but provides valuable information regarding compressibility behavior of retrograde systems. Conclusions The general conclusions are the following: 1. The compressibility method can be used to discern the onset of liquid saturation. This method relies on distinguishing between changes in slope in compressibility versus pressure plots. The compressibility method is dependent on the assumption that small amounts of liquid at the onset of condensation can cause increases in liquid compressibility which conversely increases the total compressibility. 2. CO2 has the unique ability of reducing the dew point of gas condensates. This is evident when observing the experimental and Peng Robinson approximation of the relative volume. This is also evident when analyzing the Peng Robinson approximation of the pressure temperature diagram which illustrates that CO2 reduces the phase envelope. 3. CO2 can reduce liquid dropout. This is beneficial because it can reduce liquid blockage in the near well bore region for wet gas wells that have significant liquid drop out. SPE 161478 15 Nomenclature CT = total isothermal compressibility Vt = total volume of the PVT cell P = pressure of the PVT cell CG = gas compressibility SG = gas saturation CL = liquid compressibility SL = liquid saturation VL = liquid volume Vi = ith liquid component’s feed liquid volume ρi = ith liquid component’s density at standard conditions MWi = ith liquid component’s molecular weight yi = ith component’s mole fraction in the gas condensate mixture Pi = loading or working pressure of the ith component Vi = loading volume of the ith component Pr = reduced pressure Tr = reduced temperature B(0) = virial equation coefficient B(1) = virial equation coefficient Br = virial equation parameter ω = acentric factor of the component zi = compressibility factor of the ith component γg, = specific gravity of the gas condensate sample Tpc = pseudo critical temperature Pt = pressure larger than the dew point pressure Tt = temperature used for the CCE experiments Ppc = pseudo critical temperature J = parameter in Piper et al correlation K = parameter in Piper et al correlation ηf = parameter in Piper et al correlation βf = parameter in Pier et al correlation A = parameter in Standing correlation B = parameter in Standing correlation C = parameter in Standing correlation D = parameter in Standing correlation zt = total compressibility factor for condensate mixture ρL = liquid density in the PVT cell ρG = gas density in the PVT cell mg = mass of the gas phase of the PVT cell Acknowledgement This paper was made possible by NPRP grant # 4-007-2-002 from the Qatar National Research Fund (a member of Qatar Foundation). The statements made herein are solely the responsibility of the author. References 1. Winnick, Jack. 1997. Chemical Engineering Thermodynamics. John Wiley & Sons, Inc. pp 86-95 and pp 554-556. 2. Cronquist, Chapman. 2001. Estimation and Classification of Reserves of Crude Oil, Natural Gas, and Condensate. Society of Petroleum Engineers. pp 311-312. 3. Piper, L.D., McCain, W.D., and Holditch, S.A. 1993. Compressibility Factors for Naturally Occurring Petroleum Gases. Paper SPE 26668 presented at the 68th Annual Technical Conference and Exhibition of the Society of Petroleum Engineers, Houston, TX, 3-6 October. 4. Firoozabadi, Abbas. 1999. Thermodynamics of Hydrocarbon Reservoirs. McGraw-Hill. pp 165-169. 5. Whitson, C.H. and Kuntadi, A. 2005. Khuff Gas Condensate Development. Paper IPTC 10692 presented at the International Petroleum Technology Conference. Doha, Qatar, 21-23 November 2005. 6. Poling, B., Prausnitz, J., and Oconnell, J. 2001. The Properties of Gases and Liquids Fifth Edition. McGraw-Hill. pp. A.17 7. API Technical Data Book. new.api.org 8. Potsch, K.T. and Braeuer, L. 1996. A Novel Graphical Method for Determining Dewpoint Pressures of Gas Condensates. Paper SPE 36919 presented at the European Petroleum Conference. Milan, Italy, 22-24 October 1996. 16 SPE 161478 9. Monger. T.G. and Khakoo, A. 1981. The Phase Behavior of CO2- Appalachian Oil Systems. Paper SPE 10269 presented at the 56th Annual Fall Technical Conference and Exhibition. San Antonio, TX, 5-7 October. Appendix Base Case: Pressure versus Volume at 200 oF 7000 6000 Pressure, psia 5000 4000 3000 2000 1000 0 20 22 24 26 Volume, cc 28 Figure 14: CCE isotherm for Base Case at 200 oF 30 32 SPE 161478 17 Base Case: Compressibility versus Pressure at 200 oF 0.00035 0.0003 Compressibility, 1/psi 0.00025 0.0002 0.00015 0.0001 5626.7 psia 0.00005 0 0 1000 2000 3000 4000 Pressure, psia 5000 6000 7000 Figure 15: Dew Points Determination using compressibility versus pressure plot for Base Case at 200 oF 5% CO2 in Base: Pressure versus Volume at 200 oF 4000 3500 3000 Pressure, psia 2500 2000 1500 1000 500 0 0 20 40 60 80 100 Volume, cc Figure 16: CCE isotherm for 5% CO2 in Base Case at 200 oF 120 140 18 SPE 161478 5% CO2 in Base: Compressibility versus Pressure at 200 oF 0.002 0.0018 0.0016 Compressibility,1/psi 0.0014 0.0012 0.001 0.0008 0.0006 3547.7 psia 0.0004 0.0002 0 0 500 1000 1500 2000 Pressure, psia 2500 3000 3500 4000 Figure 17: Dew Points Determination using compressibility versus pressure plot for 5% CO2 in Base Case at 200 oF 10% CO2 in Base: Pressure versus Volume at 200 oF 7000 6000 Pressure, psia 5000 4000 3000 2000 1000 0 60 70 80 90 Volume, cc 100 110 Figure 18: CCE isotherm for 10% CO2 in Base Case at 200 oF 120 SPE 161478 19 10% CO2 in Base: Compressibility versus Pressure at 200 oF 0.0007 0.0006 Compressibility, 1/psi 0.0005 0.0004 0.0003 0.0002 3529.7 psia 0.0001 0 0 1000 2000 3000 4000 Pressure, psia 5000 6000 7000 Figure 19: Dew Points Determination using compressibility versus pressure plot for 10% CO2 in Base Case at 200 oF