PE 4521 Experiment 1: Measurements of Oil Density, API Gravity and Viscosity 1. Objectives. • To determine density and viscosity of three liquid hydrocarbons as a function of temperature and to examine if any correlation exists between the liquid density and viscosity • To determine viscosity of three inverse emulsions and to examine the effect of changing water/oil volume ratio on the emulsion rheology 2. Discussion . Detailed analysis of a crude oil using its complex chemical composition is very difficult if not impossible. Therefore, crude oils are classified according to their physical properties. Density (specific gravity or API gravity) and viscosity are the most important ones. Measurement of API gravity and viscosity is simple, yet essential in the petroleum industry. The specific gravity of a crude oil is defined as the ratio of the density of the liquid to the density of pure water, both measured at specified conditions of pressure and temperature. (Density of pure water is given in Table 3-28.) Dynamic viscosity of a crude oil can be loosely defined as the internal resistance of the oil to flow. Viscosity appears in the mobility coefficient of Darcy’s law during the description of flow of phases in porous medium. The latter is the characteristic fluid flow parameter that controls the rate at which fluid can be produced under an applied potential gradient. Density, on the other hand, is important when the flow takes place under the influence of gravity; hence it appears as the coefficient of depth gradient in Darcy’s equation. An emulsion is a fluid system containing two liquid phases, one of which is dispersed as droplets in the other. The liquid which is broken up into droplets is termed the dispersed phase, whilst the liquid surrounding the droplets is known as the continuous phase or dispersing medium. The two liquids, which must be immiscible or nearly so, are frequently referred to as the internal and external phases, respectively. There are two types of emulsions, direct emulsions and invert emulsions. In direct emulsions, oil droplets are dispersed in water, which were also called oil-in-water emulsion (o/w). In invert emulsions, the opposite is true, since the water droplets are dispersed in oil, which is also called water-in-oil emulsion (w/o). Generally invert emulsions are preferred when a large amount of oil is desired. Emulsions are formed using two phases (such as oil and water) in the presence of an emulsifying agent, i.e., emulsifier. The most common emulsifiers are surfactants. A surfactant, or surface active agent, is a macromolecule with a polar (hydrophilic) head and a long non-polar hydrocarbon (hydrophobic) tail. A good analogy for the surfactant molecules would be lollypops. These molecules locate themselves at the water- oil interface and give an elastic behavior to the dispersed droplets in the emulsion system and, hence, create a thermodynamically stable emulsion. Crude oil emulsions are generally of the water-in-oil type, which are more viscous than either of their constituents. On the other hand, oil-in-water emulsions have lower viscosity than that of the oil phase. Measuring the emulsion viscosity is one of the objectives of this experiment.
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PE 4521 Experiment 1: Measurements of Oil Density, API Gravity and Viscosity 1. Objectives.
• To determine density and viscosity of three liquid hydrocarbons as a function of
temperature and to examine if any correlation exists between the liquid density and viscosity
• To determine viscosity of three inverse emulsions and to examine the effect of changing water/oil volume ratio on the emulsion rheology
2. Discussion.
Detailed analysis of a crude oil using its complex chemical composition is very difficult if not impossible. Therefore, crude oils are classified according to their physical properties. Density (specific gravity or API gravity) and viscosity are the most important ones. Measurement of API gravity and viscosity is simple, yet essential in the petroleum industry. The specific gravity of a crude oil is defined as the ratio of the density of the liquid to the density of pure water, both measured at specified conditions of pressure and temperature. (Density of pure water is given in Table 3-28.) Dynamic viscosity of a crude oil can be loosely defined as the internal resistance of the oil to flow. Viscosity appears in the mobility coefficient of Darcy’s law during the description of flow of phases in porous medium. The latter is the characteristic fluid flow parameter that controls the rate at which fluid can be produced under an applied potential gradient. Density, on the other hand, is important when the flow takes place under the influence of gravity; hence it appears as the coefficient of depth gradient in Darcy’s equation. An emulsion is a fluid system containing two liquid phases, one of which is dispersed as droplets in the other. The liquid which is broken up into droplets is termed the dispersed phase, whilst the liquid surrounding the droplets is known as the continuous phase or dispersing medium. The two liquids, which must be immiscible or nearly so, are frequently referred to as the internal and external phases, respectively. There are two types of emulsions, direct emulsions and invert emulsions. In direct emulsions, oil droplets are dispersed in water, which were also called oil-in-water emulsion (o/w). In invert emulsions, the opposite is true, since the water droplets are dispersed in oil, which is also called water-in-oil emulsion (w/o). Generally invert emulsions are preferred when a large amount of oil is desired. Emulsions are formed using two phases (such as oil and water) in the presence of an emulsifying agent, i.e., emulsifier. The most common emulsifiers are surfactants. A surfactant, or surface active agent, is a macromolecule with a polar (hydrophilic) head and a long non-polar hydrocarbon (hydrophobic) tail. A good analogy for the surfactant molecules would be lollypops. These molecules locate themselves at the water-oil interface and give an elastic behavior to the dispersed droplets in the emulsion system and, hence, create a thermodynamically stable emulsion. Crude oil emulsions are generally of the water-in-oil type, which are more viscous than either of their constituents. On the other hand, oil-in-water emulsions have lower viscosity than that of the oil phase. Measuring the emulsion viscosity is one of the objectives of this experiment.
Figure 1 Dyed mineral oil mixed with water to produce a pink-colored emulsion.
Figure 2. Appearance of emulsion with its dispersed and continuous phases under the microscope.
Figure 3. A water-in-oil emulsion droplet shown at a microscopic level.
3. Equipment. 25 ml pycnometer, electronic balance, Cannon-Fenske viscometers, API hydrometers, graduated cylinders, electronic balance, stopwatch, latex gloves, lab coat and safety goggle
4. Materials.
Various crude oils, water and an emulsifying agent. 5. Procedure.
To measure the API gravity and density of oil at room temperature using hydrometer: a) Dip the API hydrometer in the graduated cylinder containing the liquid at room
temperature. Spin the hydrometer gently and allow it to come to rest. Note the API gravity reading on the stem of the hydrometer
b) Calculate the specific gravity γo=141.5/(131.5+oAPI) c) Calculate apparent molecular weight of the crude oil using MW=42.43 γo / (1.008-γo) d) Calculate the oil density ρoil = γo ρwater (g/cc) of the crude oil at room temperature.
Here the water density is read from the attached pure water table
To measure the density of oil at room temperature using pycnometer: a) Wash the pycnometer by water, clean it, and let it dried using oven b) Measure the weight of the empty pycnometer using electronic balance c) Fill the pycnometer with one of the oils used in hydrometer experiments above, put
the cover, and allow the excessive liquid to come out through the capillary tube in the cover
d) Weight the filled pycnometer, using electronic balance e) Record the difference in the weight of the pycnometer between the filled and
the empty. f) The density of the liquid is the ratio of the difference in the weight of
pycnometer to the volume of pycnometer. g) Repeat the measurement of density for the other oil samples used in hydrometer
experiments above
To measure oil viscosity: a) See the attached instructions for Cannon-Fenske viscometer. Fill the viscometer as
indicated in step 4. It will turn out that when the viscometer is inverted the liquid will fill about half of the bulb in the bigger arm. Apply suction to draw the liquid from the big arm so that it is in the bulb above the upper etched mark. Allow the liquid to fall freely down past the lower etched mark. Note the time required for the liquid meniscus to pass from the upper to the lower mark. You will want to replicate this step at least one more time to find the average flow time
b) Repeat at several temperatures c) Calculate the kinematic viscosity from the average time and the viscometer constant. d) Repeat the measurements at three other temperatures. Make sure that the viscometer is
kept in the temperature bath for sufficient long time for the liquid to come to the temperature of the bath
e) Use density values obtained from step ‘b’ to find the dynamic viscosity values at three temperatures
f) Clean all equipment and the work area
To measure w/o emulsion viscosity: a) Prepare the invert emulsions at varying emulsifying agent concentration. Place a
suitable volume of diesel oil into a mixer. Add the required volume of emulsifying agent to diesel oil in the mixer slowly and mix the mixture. Finally, add the suitable volume of distilled water and mix it about 20-30 minutes
b) Measure the emulsion viscosity using the Cannon-Fenske viscometer as explained above for the oil
c) Repeat the steps using emulsions with two changing water/oil volume ratios and hence two different volumes of continuous phase
6. Report
a) In the introduction part of your report discuss the significance and practical applications of density, API gravity and viscosity measurements in oils and oil field emulsions
In the discussion part of your report: b) Compare the values of oil density and API gravity estimated using hydrometer and
pycnometer. c) Examine and comment on the temperature dependence of viscosity for the various
fluids you considered d) Compare the emulsion viscosity with the viscosity of the oil phase. Discuss the impact
of water/oil volume ratio on the viscosity e) Comment on controllable measurement error and its impact on calculated results
DENSITY OF PURE WATER (FROM PERRY’S CHEMICAL ENGINEERING HANDBOOK, ON PAGES 375 AND 376)
continue next page…
Unit Conversion: To convert kilogram per cubic meter to pounds per cubic foot, multiply by 0.06243 oF=9oC/5+32
PE 4521 Experiment 2 Measurement of Gas Viscosity using Molecular Dynamics Simulation 1. Objective. To predict the viscosity of a mixture of gas with known composition using molecular dynamics (MD) simulation along with Einstein’s equation 2. Discussion. Accurate prediction of gas viscosity using instrumentation is difficult and often not reliable. Here we learn to use molecular simulation as the method of predicting gas viscosity at a particular pressure and temperature. Einstein’s equation to predict the viscosity (Pa-s) of any fluid is given as:
( ) ( )[ ]230
02
10=−
∆×
=−
tGtGtTk
VB
gasµ ……………………………………………………eqn (1)
where V is the volume of a cubic computational cell with a 40 Å length, kB the Boltzmann constant equal to1.3806E-23 J/K, T the temperature (273.0K) and ∆t the time step for the simulation, which is 10sec in this case. The term in the bracket is known as the “canonical ensemble” average square mean displacement of the molecules with G(t) described as:
( ) ( )tmrV
tGN
iii∑
=
=1
1βα
Here, N is the number of gas molecules in the computational cell, riα is the position of molecule i in the α-direction, and miβ the momentum of the same molecule in the β-direction at time t. 3. Equipment. DL-POLY, parallel computing using LINUX cluster at the OU Supercomputing Center for Education & Research.
Figure 1. A snap shot from the MD simulation showing the location of gas molecules in a slit-shape pore.
4. Procedure. Below, the square mean displacement of the molecules is given at 10 second intervals for a number of gas molecules at 273.0K temperature and 1.028MPa pressure.
Take the average value of these and use it in equation (1) to estimate the gas viscosity 5. Report Report the estimated viscosity in centipoises (cp) 6. Bibliography.
1. Allen, M.P. and Tildesley, D.J. (2007) “Computer Simulation of Liquids,” Oxford University Press, London
2. Frenkel, D. and Smit B. (2002) “Understanding Molecular Simulation – From Algorithms to Applications,” Academic Press, Computational Science Series, San Diego
PE 4521 Experiment 3: Statistical Analyses of Core Data 1. Objective: The goal of this study is to use data that can be obtained from core analyses and/or well logs to determine statistical measures for distributions of reservoir properties (e.g., porosity, water saturation and permeability) and determine whether the properties can be spatially correlated. 2. Discussion: The volumetric estimation of original oil in-place is conceptually simple; see Craft et al. (1990), and Tiab and Donaldson (1996). The fundamental estimate is the reservoir bulk volume occupied by the liquid and/or vapor hydrocarbon phases. However, there are other parameters in the equation shown below. These include porosity, net to gross and phase saturation. In this exercise you will examine the character of these properties measured on cores believed to be from the same reservoir.
( ) ( )STB 7758 1bulk wi G oN V S N Bϕ= −
In practice engineers normally use average quantities for porosity, φ and water saturation, Swi. Unfortunately, they usually just calculate the averages without subjecting them to statistical analyses. The confidence with which the averages could be used would be much greater if the engineer understood how much statistical confidence could be placed in them. The goal of this lab experience is for you to develop insight into the use of statistics to understand core data. In addition, current trends in reservoir engineering are to use simulators for reservoir analysis and management. For some problems, it is important to examine the effects of reservoir heterogeneity, namely the values of reservoir parameters such as porosity and permeability are developed as functions of position within the reservoir. Consequently, it is convenient to identify if relationships exist between the parameters or if they are independent distributions. It seems appropriate to consider this experiment in two parts. First, examine core reports to identify correlated sections for all wells. Then check those sections, see if the porosity and water saturation frequency distributions appear to be from the same population. You will also check to see if they follow a normal distribution. Many people believe that they do (e.g. Amyx et al.1960). If the two cores are drawn from the same population, the sample frequency diagrams should be quite similar. Similarity would indicate that the two cores are from parts of the same reservoir that were formed by the same geologic processes. If the frequency diagrams are different you might conclude that they might be formed by different processes or at different times. If the frequency diagrams are the same, calculating average porosity and water saturation for the reservoir should be done using the combined frequency distributions, particularly since you will have proven that they are from the same population. If the distributions follow the normal or standard distribution (bell shaped curve), there are specific tests, such as the t-test; you can use to establish confidence limits that the measures of
central tendency and dispersion for the two cores were drawn from the same population. If they do not follow a normal distribution, you will need to use more words and more complicated analysis (thinking) to show how you determined the average values. The second part of the experiment does not directly impact on estimating the quantity of hydrocarbons originally in the reservoir. Rather it has to do with identifying relationships between reservoir parameters that can be used for scaling or assigning parameter (permeability) values to parts of the reservoir in a reservoir simulator. In this section, you will look for relationships between the parameters. It is reasonable to hypothesize that porosity is the fundamental parameter and connate water saturation and permeability could be functions of porosity. It would be reasonable to plot water saturation versus porosity to see if there is an identifiable relationship. (See Chapra and Canale, chapter 17 Regression.) Many people believe that permeability is log normally distributed. That means that the logarithm of permeability is normally distributed. Check your data to see if it confirms this belief. Plot permeability (and log-permeability) versus porosity and saturation to identify any relationship. You should report the results of your regression analysis with measures of quality. 3. Equipment: Core reports for two wells. These core sections are thought to be from the same unit. Use porosity, measured water saturation and maximum K [md] as data for your statistical analysis. 4. Procedure: Use the data, to estimate representative values of porosity and permeability. Also identify relationships that may exist between porosity, water saturation and permeability. This will “go more easily” in a spreadsheet since they have sort functions, graphical capability and some statistical analysis capability. (Make sure you know what the Excel functions mean and do.) 5. Report: Be sure to include your porosity and permeability histograms. It would be useful to have the histograms for all wells on the same figure (also the combined histogram if the data warrant it). Also include the cross-plots of water saturation and permeability versus porosity. Put the statistical calculations in the appendix. 6. References: Amyx, J.W., D.M. Bass, Jr and R.L. Whiting, Petroleum Reservoir Engineering, Physical Properties, McGraw-Hill, Inc., pp 536—560, 1960. Chapra, S.C. and R.P. Canale, Numerical Methods for Engineers, 3rd Edition, McGraw-Hill Publishing Company, Part 5 and Chapter 17, 1998. Craft, B.C., M. Hawkins and R.E. Terry, Applied Petroleum Reservoir Engineering, 2nd Edition, Prentice-Hall, pp. 69-76, 148-150, 1991. Tiab, D. and E.C. Donaldson, Petrophysics, Gulf Publishing Co., pp. 118-122, 1996. i.y.a. 2012
PE 4521 Experiment 4 Volumetric estimation of OOIP 1. Objective. The goal of this project is to determine the original oil in place using volumetric method. 2. Discussion. The volumetric estimation of original oil in place is conceptually simple; see Craft et al. (1990). The basic estimate is the estimate of the reservoir bulk volume occupied by the liquid and/or vapor hydrocarbon phases. Petroleum reservoirs are irregularly shaped bodies. To properly determine the volume one should integrate the irregular functions between the limits that bound the reservoir and its separation into distinct phase regions.
bVoo dzdydxzyxBSN ),,(/
That means determining the bounding top and bottom surface functions and the horizontal limits of the formation. Since these are not simple functions, integration must be approximate rather than analytic, Chapra and Canale (1998). Historically, geoscientists have determined structure maps from seismic imaging. They have then converted those maps to isopachous maps of the oil and gas zones using oil-water and gas-oil contact data where available. Graphical methods are generally used to contour areas of constant saturated thickness and a numerical method is used to integrate the volume, Vb, contained in the reservoir as mapped. The actual formula used is simple, Craft et al. (1991). N = C Vb (1-Sw) / Bo In oilfield units for liquid hydrocarbon saturated reservoirs, C is 7758 rb/ac-ft, Vb is in ac-ft, and Bo is in rb/stb and N is in stb. Porosity and water saturation is expressed in fraction. Even though the formula is simple there are several sources of errors. An excellent discussion on uncertainty estimation in volumetrics determination is given by Floris and Peersmann (1998). 3. Equipment. Planimeter or another graphical integration device. 4. Procedure. Use the data in Attachment 1, particularly the structural map and the isopach map of the pay zone thickness, excerpted from Andrews, et al. (1995 or 1996), to prepare a net oil sand isopachous map. Integrate the areas within contours using a planimeter and using
an appropriate numerical method to find the volume of the reservoir filled with hydrocarbons. There are three ways to calculate the volume: trapezoidal rule, Simpson’s rule and equation for the volume of the frustum of a pyramid. Trapezoidal rule: h is fixed = 10 ft
nnnn ataaaaahVolume )2...........22(21
1210 Simpson rule:
nnnnn ataaaaaaahVolume )42.......424(31
123210
where h = contour interval (ft) ao = area enclosed by zero contour ( at oil water contact) (acres) a1 = area enclosed by first contour an = area enclosed by nth contour tn = average formation thickness above the top contour Simpson rule is the more accurate of the two for irregular curves. However, either will usually give satisfactory results. Simpson’s rule is slightly more tedious and has the limitation that an even number of contour intervals (odd number of contours) must be used. The equation for the frustum of a pyramid can be expressed by:
)(31
00 nn aaaahVolume Do the calculation of the bulk volume associated with this reservoir Find the OOIP and compare with the one from the Booch Play where a0 = area enclosed by the lower contour in section (acres) an = area enclosed by upper contour in section (acres) Use the volume described by your map and other data from the table of reservoir engineering data to estimate the original oil in place by all three methods. (For the Booch reservoir, you will notice that a fault is mapped between the Hall #1 discovery well and other wells in the reservoir. The results of the reservoir simulation study suggest that the fault is a seal. Compare your estimate of original oil in place with the value reported in Attachment 1. 5. Report: Be sure to include your isopach map of the oil zone. Include calculations as part of the appendix material. Performing calculations in a spreadsheet would be helpful.
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6. Questions: a) One of the figures in Attachment 1 is the type log for the field; it shows the information used to determine the top and bottom of the pay zone interval. How precise do you think the thickness can be measured? What impact can that have on the estimate of original oil and gas in place? b) What are the various sources of errors in volumetric calculations? How will you minimize them? 7. References: Andrews, R.D., Northcutt, R. A., Knapp, R. M. and Yang, X. H. 1995. Fluvial-Dominated Deltaic (FDD) Oil Reservoirs in Oklahoma: The Booch Play, Oklahoma Geological Survey, Special Publication 95-3, 67 pp. Andrews, R.D., Rottman, K., Knapp, R. M., Bhatti, Z. N. and Yang, X. H. 1996. Fluvial-Dominated Deltaic (FDD) Oil Reservoirs in Oklahoma: The Skinner and Prue Plays, Oklahoma Geological Survey, Special Publication 96- 2, 106 pp. Chapra, S.C. and Canale, R. P. Numerical Methods for Engineers, 1998. 3rd Edition, McGraw-Hill Publishing Company, Chapter 21. Craft, B.C., Hawkins, M. and Terry. R. E. 1991, Applied Petroleum Reservoir Engineering, 2nd Edition, Prentice-Hall, pp. 69-76, 148-150. Floris, F. J. T., and Peersmann, M. R. H. E. 1998. Uncertainty estimation in volumetrics for supporting hydrocarbon exploration and production decision-making, Petroleum Geosciences, 4, pp. 33-40. iya2012
PE 4521 Experiment 5 Hydrocarbon Phase Behavior 1. Objective Study the pressure-volume behavior of hydrocarbon fluids and CO2–water mixture to determine experimental values for i) bubble point, ii) gas solubility, iii) formation volume factor, and iv) isothermal compressibility. 2. Discussion Crude oil physical properties such as gas solubility Rso, and formation volume factor Bo are function of pressure, temperature and composition (McCain, 1990). For a given hydrocarbon, the reservoir depletion can be approximated as an isothermal process and as such the above properties can be considered to be a function of pressure alone. In this experiment you will be determining bubble point, Rso, Bo and compressibility of a selected number of hydrocarbon fluids and CO2–water mixture at room temperature. Bubble point is the pressure Pb at which the bubbles of free gas first appear. Gas solubility, Rso, is the number of standard cubic feet of gas that will dissolve in one stock-tank barrel of oil at reservoir temperature and pressure, [scf/stb]. Henry’s law states that the solution of gas within a liquid is directly proportional to the pressure exerted by the gas above the liquid. However, this is an ideal law that only applies in limited circumstances. Standing’s correlation, equation 1.26 in Craft et al. 1991, corrects for the real nature of reservoir fluids by using an exponent of 1.204 rather than 1.000. Standing’s correlation is an approximation and may not be appropriate for specific oils and gas systems. When gas is forced into solution in crude oil by pressure there is an increase in the total liquid volume. This increase in liquid volume is described by the oil formation volume factor, Bo, and is based on stock tank volume. The formation volume factor may be defined as the volume in barrels at reservoir conditions occupied by one stock-tank barrel of oil plus the dissolved gas, [rb/stb]. Isothermal compressibility is a measure of change in volume as the pressure is changed. It can be calculated experimentally using the following equation:
−−−
=21
211PPVV
Vco
where V1 and V2 are volumes at pressures P1 and P2. V is the reference volume generally assumed to be average of the two volumes. 3. Equipment PVT cells, hydrocarbons, water and CO2, latex gloves, and safety goggles.
4. Procedure Briefly, the experiment consists of measuring pressure and volume of hydrocarbon and gas mixture in a PVT cell at room temperature. You will be using three PVT cells. Detailed instructions on how to operate the two cells will be provided to you in the laboratory. As you decrease the pump pressure in 500 psig increments down to the bubble point, read the pump displacement corresponding to each pressure stage. Check the cell inspection window during each pressure reduction. The appearance of small bubbles indicates that the saturation (bubble point) pressure has been reached. Expand the system below the bubble point in several increments (3-5) using the remaining pump displacement. Agitate the cell after each expansion to establish equilibrium before reading exact system pressure and volume. Use the data collected to determine the bubble point pressure by plotting system volume versus pressure. Above the bubble point all gas is in solution and you are directly measuring volume changes with pressure. Below the bubble point you are measuring the volume occupied by the liquid (oil plus dissolved gas) and the vapor phase volume occupied by the gas that has come out of solution. This is often referred to as the two phase or total formation volume factor, Bt. The liquid has volume N*Bo and the vapor has volume N*Bg (Rsoi – Rso). Use the ‘form’ of the correlations listed in Craft et al. 1991, along with your data to develop the PVT suite of Bo and Bg, Bt and Rso. You will need to make some assumptions. You can make good use of equations (1.26), p. 33, (1.28), p. 35, (1.29), p 37 and (1.1, 1.31), p. 38 in Craft et al. 1991. Note- you do not use them exactly as they are written but rather use their forms and use values at the bubble point pressure to solve for coefficients so that you preserve the forms while adjusting the correlations for your experimental results. 5. Report
a) Graphs (experimental points clearly indicated) for all the liquids and gas combinations: i. Cell pressure versus sample volume. ii. Two phase formation volume factor, Bt and Bo, versus cell pressure. iii. Solution gas, Rso, versus cell pressure. iv. Compressibility of liquids vs. pressure.
b) Report bubble point for the studied hydrocarbons. c) Show sample calculation for all the above parameters for one hydrocarbon.
7. References 1. Craft, B.C., Hawkins, M., and Terry, R. E.1991. Applied Petroleum Reservoir Engineering, 2nd Edition, Prentice-Hall, pp.31-44. 2. McCain, Jr., W. 1990. The Properties of Petroleum Fluids, 2nd edition, PennWell Books, Tulsa, OK.
IYA 2012
PE 4521 Experiment 6 Interfacial Tension, Contact Angle & Capillary Pressure Measurements 1. Objectives. To perform high pressure mercury injection experiment on three samples – two sandstones and one limestone; from the collected data, to calculate air-brine capillary pressure curve, pore throat size distribution, permeability and J-function. To measure solid-air-brine (with and without surfactant) interfacial tensions (IFTs), contact angles using Du Nuoy tensiometer and contact angle meter. 2. Discussion. Several techniques such as porous plate method, centrifuge method, and high-pressure mercury intrusion are used to obtain capillary pressure (see Amyx et al. 1960; Tiab and Donaldson 1996 etc.). Of all these methods, high pressure mercury injection is the most common one. Capillary pressure, IFT and contact angle data is very important to reservoir engineers as it is used to predict water saturation, calculate free water level, evaluate rock quality (e.g., wettability), calculate and interpret relative permeability curves, predict pore size distribution, develop residual hydrocarbon saturations etc. 3. Equipment. Rock samples, electronic scale, mercury injection high pressure porosimeter, DuNouy tensiometer (to measure interfacial tension) and contact angle measurement apparatus. See the attached supplementary notes for the equipment. Detailed directions on how to use the porosimeter, tensiometer and contact angle meter will be handed out in the laboratory. Caution: In this experiment you will be using mercury. Be very careful; at all times wear gloves. As in the other laboratory sessions, no eating and drinking is allowed in this lab. 4. Data and report. The basic data that you will be using consist of pressure and mercury intrusion volume. From the data do the following: 1) plot intrusion pressure versus Hg saturation, 2) calculate and plot pore throat size histogram, 3) convert and plot Hg-air data to air-brine capillary pressure, 4) estimate R35 and calculate permeability using Windland equation, and weighted geometric mean approach, 5) plot J-function versus wetting phase saturation and 6) discuss which of the three samples will be a better reservoir and why? 5. Bibliography: Amyx, J. W., Bass, D. M., and Whiting R. L.1960. Petroleum Reservoir Engineering: Physical Properties, McGraw Hill Book Co., NY, 610pp. Tiab, J. and Donaldson E. 1996. Petrophysics-Theory and Practice of Measuring Reservoir Rock and Fluid Transport Properties, Gulf Publishing Co. Houston, 706pp. Vavra, C. L., Kaldi, J. G., and Sneider, R. M. 1992. Geological Applications of Capillary Pressure: A review, AAPG Bull. 76, 840-850. Dastidar, R, Sondergeld, C. H. and Rai, C. S. 2007 An Improved Permeability Estimator from Mercury Injection for Tight Clastic Rocks, Petrophysics, 48, 186-190. iya2012
where Pc: capillary pressure in psi θ : contact angle (130o for air-Hg, take 0o for air-brine)
γ : interfacial tension in dynes/cm (485 for air-Hg; you will determine in the lab for air-brine using tensiometer)
r : capillary radius in microns C : conversion constant (0.145) K : permeability in millidarcy φ : porosity (%) R35 :pore radius in microns at 35 percentile non wetting phase saturation Rwgm: weighted geometric mean radius
Supplementary Notes for Du Nouy Tensiometer
Du Nouy Tensiometer No 70545
Correction factor for surface and interfacial tension
Supplementary Notes for CAM-PLUS MICRO Contact Angle Meter
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The AutoPore offers various options forobtaining important sample information asquickly as possible and for presenting thedata in a format which you can design.Analysis options include choice of analysisvariables, equilibration techniques, and pressure points at which data are collected.After operating conditions for the instrumenthave been chosen, they can be stored as atemplate and then reapplied to other samples,saving time and reducing the potential forhuman error.
A selection of report options lets you cus-tomize many aspects of the data pages. Youcan select a specific range of data to be usedin calculations; arrange columns of tabulardata; select cumulative, incremental, or differential plots; scale the X-axis to displayin either logarithmic or linear format for pore size; report actual or interpolated data;and select data presentation units such aspsia or MPa, diameter or radius, and micrometers or Angstroms.
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Data Reduction
The AutoPore IV generates tabular andgraphical reports of percentage pore volumevs. diameter, and a summary report of per-centage porosity in user-defined size ranges.The user has the ability to average severalanalyses and to use the ‘resulting average’analysis as a reference with which to comparesubsequent analyses. A standard, single,user-defined analysis may also be enteredand used for subsequent comparisons. SPCreports are available with collected data oruser-defined parameters. In addition to thestandard data reduction methods, theAutoPore IV Series also provides the following:
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The pore size distribution of two alumina
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The extensive report
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structure calculations
including Cavity-to-
Throat Size Ratio,
Fractal Dimension,
Material Compressibility,
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Control reporting.
The material compressibility is easily calculated and
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using the AutoPore report system.
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Additional pore structure
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in the AutoPore software.
• The computer will not accept keyboardinstructions to overpressurize the system.
• The high-pressure system is mechanicallyunable to generate unsafe pressures.
• A circuit stops the generation of pressurein the event of a failure in the computer.
• The operating specifications of the pressure systems (low = 50 psia, high = 60,000 psia) are well below theactual designed safety limits.
WATERFLOODING AND ENHANCED OIL RECOVERY PE 4521 Experiments 7, 8 and 9 Fall 2011 1. Objectives A) To become familiar with the application of core (sand pack) evaluation tests to predict
recovery factors from waterflooding, surfactant flooding and gas flooding. B) To determine petrophysical and multi-phase flow properties of the sand pack such as
porosity, permeability, irreducible water saturation, residual oil saturation and ‘end-point’ relative permeability for each recovery system.
2. Discussion
Primary production seldom depletes an oil reservoir. Common practice has been to water flood partially depleted reservoir after an initial primary production. The series of experiments you are scheduled to perform will help you to create a porous medium using mixtures of sands, to saturate a sand pack to establish oil saturation at connate water saturation and to flood. The latter stage also involves determination of the efficiency values of imbibition during water displacement, surfactant flooding and gas drive.
Surface tension at the oil-water interface of a reservoir system has a major influence upon residual oil saturation in the immiscible flooding of a porous medium. The displacement efficiency of a flood system increases as the interfacial tension decreases. Part of this net effect from a change in surface tension can be attributed to a change in wettability that also influences the residual oil saturation (see Craft et al. 1991, Figure 9.19, p. 381). One method of decreasing the interfacial tension between the displacing fluid and crude oil is by adding surfactant to the displacing fluid. When interfacial tension is sufficiently reduced, oil recovery can approach 100 per cent of the oil remaining after water flooding. Performance of a surfactant flood depends on several factors such as 1) pore geometry, 2) interfacial tension, 3) wettability or contact angle, and 4) pressure gradient. A number of factors, including brine composition, have major effect on interfacial tension. Many parameters must be considered in the design of a surfactant flood process. Gas drive is one of the techniques used to recover additional oil when recovery from primary energy becomes uneconomic. A gas flood is applicable in reservoirs with high permeability and high relief. Gravity segregation may occur in a gas drive system. Under some conditions segregation can result in high recovery factors. In other cases, low recovery may occur when gas overrides a zone of high oil saturation. Gas may also be used for pressure maintenance. In this case the recovery process is more complex. As a pressure maintenance agent it can also be useful for reservoirs with low permeabilities (see Craft et al. 1991, section 9.3.2, pp. 353—360).
3. Equipment Flow experiment assembly, Lucite sand pack tube, graduated cylinders, electronic balance, pycnometer, stopwatch, latex gloves and safety goggles. You will be working with dyed brine that may stain clothes. In general keep the pressure difference across the sand pack relatively low; a few psi (never more than 10 psi); this will give you enough time to watch what happens and to record data.
4. Materials
Mineral oil, NaCl brine, sand, sulfonate surfactant mixture (10% by volume in deionized water) and laboratory compressed air.
5. Procedure Waterflooding a) Build sand pack using 100 mesh quartz sand (grain density = 2.65 gm/cc). Prior to
making the sand pack weigh all empty tube and all other necessary parts those are needed to make full sand pack assembly. Start preparing the sand pack. Tap the side of the Lucite tube while filling to ensure a tight pack with minimum voids. After filling, put the tube in the metallic holder. Measure dimensions of the sand pack. Obtain the dry weight of the sand pack. Calculate pore volume and dry porosity of the pack. The porosity should not be more than 27%. If it is more, repeat the packing till you get porosity <27%. This is to ensure that the pack has reasonable permeability for you to do flow through experiments.
b) Install sand pack on the waterflood apparatus. Evacuate the sand pack to remove all the air and any moisture, then saturate with brine. Recover at least one pore volume of brine to ensure that the pack is fully brine saturated with no air left inside the tube. Disconnect and weigh. Calculate the saturated porosity. The difference between dry and saturated porosity should not be more than 3 porosity units.
c) Establish a flow rate with brine and determine absolute permeability. (Use brine viscosity and density measured earlier in the semester)
d) Flood the sand pack with oil until no water is produced. Measure displaced water. Determine irreducible water saturation and initial oil saturation. Determine effective (relative) oil permeability at irreducible water saturation [Craft et al. 1991]. Weigh the sand pack at this point to confirm saturations using a mass balance.
e) Waterflood sand pack with 2-3 pore volumes of water. Catch oil displaced in graduated cylinder. (If you do this slowly enough, you may be able to plot cumulative oil production (Np) versus amount of water injected (Wi). This is the fundamental ‘performance plot’ for waterflooding. You can record Np+Wp (water produced), Np (or Wp), versus time. Determine residual oil saturation to waterflood. Establish steady flow rate of brine and measure effective (relative) permeability to water at residual oil saturation. Weigh core at residual oil saturation to confirm water and oil saturations using a mass balance.
Surfactant Flooding a) Flood the sand pack with oil until no more water is produced. Measure displaced water.
Calculate starting oil and water saturation. Then flood the sand pack with surfactant solution. Catch effluent in graduated cylinders. 250 cc graduated cylinders are provided in the lab. Break through of the surfactant solution should occur between 50 and 100 cc. You will be able to see this by color of the effluent. You may take the density of the surfactant 1g/cc and the viscosity 0.96cst.
b) During the last 1-2 pore volumes, determine the effective permeability to the surfactant solution.
c) Allow the cylinders to set so that the oil and water will separate. Measure the oil and water recovered. It is useful to do this in a plot of Np versus Wi. You can also determine WORs for the separate cylinders and on a cumulative basis.
d) Clean all equipment including the sand packs and the work area. Gas Flooding a) For this experiment you will have to prepare a new sand pack, measure its properties, flow brine and oil to bring the sand pack to irreducible water saturation. (Plan to prepare the sand pack while other members of your team are doing the surfactant expt.) b) Flow oil through the sand pack so as to reach original hydrocarbon saturation. Check this by weight measurements. c) Displace oil from the sand pack with compressed air at constant pressure. Measure oil
production as a function of time. Record gas injection rate at the same times you measure oil production. You can use this data to determine injected gas. Continue flooding until oil production is zero.
6. Report results: a) Pore volume, porosity and absolute permeability of sand pack. b) Initial oil saturation, connate water saturation and Kro (Swc). c) Residual oil saturation and Krw (Sor). d) Recovery factor at the end of the water flood, surfactant flood and gas flood. See
displacement efficiency, Ed[Craft et al. 1991]. e) Mobility ratio for the water flood. f) Determine oil saturation, water saturation after the surfactant flood and Krw (Sor) g) Efficiency of the surfactant flood in terms of the oil in the core at the beginning of the
surfactant flood. h) The final oil saturation for the sand pack after surfactant flooding. i) Oil recovery factor for the gas flooding experiment. j) The final oil saturation for the sand pack after surfactant flooding. k) Np versus injected gas. 7. Things to keep in mind when writing the report (You may want to address these points in your report) a) What special safety concerns are there about these experiments? b) What factors might reduce the water flood recovery factor? Why? c) What properties of the reservoir rock or fluids could cause those factors to change? Why? d) Does the water flooding process seem efficient? Why? f) What factors might reduce the surfactant flood recovery factor? Why?
g) Does the surfactant flooding process seem efficient? Why? h) What are special economic concerns to monitor / overcome in surfactant flooding? j) Does the gas flooding process seem efficient? Why? (You might want to compare to your
water flooding results.) 8. References and Bibliography Craft, B.C., M. Hawkins and R.E. Terry, 1991. Applied Petroleum Reservoir Engineering, 2nd Edition, Prentice-Hall, pp.148—153 and 335-360, and 380-386. iya2012
Page 1 of 11
Experiment 1 & 2
Measurements of Oil Density, API Gravity and Viscosity
Measurement of Gas Viscosity using Molecular Dynamics Simulation
PE 4521 002—Reservoir Fluid Mechanics Laboratory
Team 002E
Role Name Performance Score Signature
Manager Axel Hannenberg 1.0
Researcher Lemmy Oshenye 1.0
Technician Lucas Gurgel De Carvalho 1.0
Analyst Nor Ashraf Norazman 1.0
Academic Integrity Statement
On my honor, I affirm that I have neither given nor received inappropriate aid in the completion of
It is important to determine the pressure-volume relationship of reservoir fluids because it helps to obtain
the bubblepoint pressure. Knowing the bubblepoint pressure is significant in understanding the phase
behavior of reservoir fluids by calculating integral parameters such as gas solubility, formation volume
factor (FVF), and coefficient of isothermal compressibility.
The evaluation and proper production of oil and gas reserves depends heavily on the knowledge of
reservoir fluid properties. These properties can either be obtained from laboratory experiments or
empirical correlations.
In this study, experimental measurements and empirical correlations are incorporated to determine values
of bubblepoint, gas solubility, FVF, and coefficient of isothermal compressibility. The gas solubility,
FVF, and coefficient of isothermal compressibility are plotted as function of pressure at a constant
temperature to observe the changes of each parameter with respect to pressure change. Data analysis
shows that:
1. The bubblepoint pressures for the 32°API oil, 38°API oil, and CO2-water mixture are 807.2-,
597.6-, and 874.6-psi respectively.
2. At pressures below the bubblepoint, the coefficient of isothermal compressibility is higher due to
the presence of the free gas. Once the gas is in solution, coefficient of isothermal compressibility
varies only slightly with increasing pressure because liquids are slightly compressible.
3. The solution GOR above and at the bubblepoint for the 32°API oil, 38°API oil, and CO2-water
mixture are 144.53-, 125.47-, 203.08-scf/STB. Solution GOR is constant at pressures above the
bubblepoint because all gas is in solution. At pressures below the bubblepoint, solution GOR
decreases because there is now free gas that has evolved out from the solution.
4. At pressures above the bubblepoint, the total FVF and FVF of liquid have the same value. The
FVF of liquid decreases at pressures below the bubblepoint but the total FVF increases
significantly.
It is recommended to perform hydrocarbon analysis on both crude oils to have a better understanding of
the compositional changes during the phase transition at pressures below the bubblepoint.
Page 3 of 16
Introduction
Phase behavior is the behavior of vapor, liquid, and solids as a function of pressure, temperature, and
composition (Whitson and and Brule 2000).
As oil and gas are produced from the subsurface, they undergo changes of temperature, pressure and
composition. Such changes affect the volumetric and transport behavior of the fluids directly impacting
the surface volumes and quality of produced oil and gas (Devegowda 2011).
Some physical properties such as gas solubility, formation volume factor, bubblepoint and coefficient of
isothermal compressibility exist to help the study of hydrocarbon phase behavior. To determine these
properties, experiments are usually performed on fluid samples using PVT cells and data is collected.
PVT cells basically consist of a cylinder containing mercury in which the liquid sample to be studied is
placed.
The change from single-phase to two-phase affects the physical properties. There are two basic types of
gas liberation: flash and differential (Rosa 2011).
Flash liberation is when the gas that comes out of solution due to reduction in pressure is kept in contact
with the liquid. Likewise, gas is said to be differentially liberated when the gas coming out of solution is
removed from contact with the liquid. In this experiment, flash liberation is conducted for two different
samples of oils and for a mixture of water and CO2.
PVT analysis is integral in the calculation of reserves, production forecasts, and the efficiency of
enhanced oil recovery methods. It is also useful for surface separator design and to calculate flow in pipe
(Whitson and Brule 2000).
Experimental Procedure
The temperature is set to 60°F. Set the pressure at approximately 2,000 psig for all samples. Reduce the
pressure in 200 psig increments before reaching the bubblepoint and in 100 psig increments or lower
when the pressure is close to the anticipated bubblepoint. For each reading, the pressure is allowed to
stabilize for 3 minutes before recording the pressure and volume. Pressure is plotted against volume and
the pressure at which the slope changes is the bubblepoint pressure. This experiment is performed using
CO2-water mixture, 32°API crude oil, and 38°API crude oil. The bubblepoint pressure and the
corresponding volume are observed and recorded and used as a reference volume (Ahmed 2001).
Page 4 of 16
Results
Fig. 1—The bubblepoint for 32°API oil is 807.2 psi at 148.5 mL at 60°F temperature.
Fig. 2—The bubblepoint for water with dissolve carbon dioxide is 874.6 psi at 140.3 mL at 60°F temperature.
y = -284.96x + 43132
y = -4.6454x + 1497.2
0
500
1,000
1,500
2,000
2,500
142 144 146 148 150 152 154 156
Pre
ssu
re, p
sig
Volume, mL
Pressure-Volume for 32°API Oil
y = -282.85x + 40564
y = -3.3361x + 1342.7
0
500
1,000
1,500
2,000
2,500
136 137 138 139 140 141 142 143 144 145 146
Pre
ssu
re, p
sig
Volume, mL
Pressure-Volume for CO2-Water Mixture
Page 5 of 16
Fig. 3—The bubblepoint for 38°API oil is 597.6 psi at 140.2 mL at 60°F temperature.
TABLE 1— BUBBLEPOINTS FOR THREE FLUIDS
Fluid Type 32°API Oil CO2-Water
Mixture 38°API Oil
Bubblepoint, psig 807.2 874.6 597.6
Fig. 4—The coefficient of isothermal compressibility of 32°API oil is relatively constant above the bubblepoint and increases significantly below the bubblepoint at constant temperature.
y = -386.58x + 54778
y = -90.975x + 13348
0
500
1,000
1,500
2,000
2,500
136 137 138 139 140 141 142
Pre
ssu
re, p
sig
Volume, mL
Pressure-Volume for 38°API Oil
0
0.0001
0.0002
0.0003
0.0004
0.0005
0.0006
700 900 1,100 1,300 1,500 1,700
c o, p
si-1
P, psig
Coefficient of Isothermal Compressibility of 32°API Oil
pb
Page 6 of 16
Fig. 5—The coefficient of isothermal compressibility of water is relatively constant above the bubblepoint and increases significantly below the bubblepoint at constant temperature.
Fig. 6—The coefficient of isothermal compressibility of 38°API oil is relatively constant above the bubblepoint and increases significantly below the bubblepoint at constant temperature.
0
0.00005
0.0001
0.00015
0.0002
0.00025
0.0003
0.00035
800 900 1,000 1,100 1,200 1,300 1,400 1,500
c w, p
si-1
P, psig
Coefficient of Isothermal Compressibility of CO2-Water Mixture
pb
0.00E+00
2.00E-04
4.00E-04
6.00E-04
8.00E-04
1.00E-03
1.20E-03
400 600 800 1,000 1,200 1,400 1,600 1,800
c o, p
si-1
P, psig
Coefficient of Isothermal Compressibility of 38°API Oil
pb
Page 7 of 16
Fig. 7—The solution gas/oil ratio of 32°API oil is constant above the bubblepoint and decreases significantly below the bubblepoint at constant temperature.
Fig. 8—The solution gas/liquid ratio of water is constant above the bubblepoint and decreases significantly below the bubblepoint at constant temperature.
138
139
140
141
142
143
144
145
700 900 1,100 1,300 1,500 1,700 1,900 2,100
Rs,
scf
/STB
P, psig
Solution Gas/Oil Ratio for 32°API Oil
pb
198198.5
199199.5
200200.5
201201.5
202202.5
203203.5
800 1,000 1,200 1,400 1,600 1,800 2,000
Rs,
scf
/STB
P, psig
Solution Gas/Liquid Ratio for CO2-Water Mixture
pb
Page 8 of 16
Fig. 9—The solution gas/oil ratio of 38°API oil is constant above the bubblepoint and decreases significantly below the bubblepoint at constant temperature.
Fig. 10—The total formation volume factor of 32°API oil increases significantly below the bubblepoint at constant temperature.
80
85
90
95
100
105
110
115
120
125
130
400 600 800 1,000 1,200 1,400 1,600 1,800 2,000
Rs,
scf
/STB
P, psig
Solution Gas/Oil Ratio for 38°API Oil
pb
1.02
1.025
1.03
1.035
1.04
1.045
1.05
1.055
1.06
700 900 1,100 1,300 1,500 1,700
Form
atio
n V
olu
me
Fac
tor,
re
s b
bl/
STB
P, psig
Formation Volume Factor for 32°API Oil
Bt
Bo
pb
Page 9 of 16
Fig. 11—The total formation volume factor of water increases as pressure decreases at constant temperature.
Fig. 12—The total formation volume factor of 38°API oil increases significantly below the bubblepoint at constant temperature.
1.085
1.09
1.095
1.1
1.105
1.11
800 900 1,000 1,100 1,200 1,300 1,400 1,500
Form
atio
n V
olu
me
Fac
tor,
re
s b
bl/
STB
P, psig
Formation Volume Factor for CO2-Water Mixture
Bt
Bw
pb
1.00000
1.02000
1.04000
1.06000
1.08000
1.10000
1.12000
1.14000
1.16000
1.18000
1.20000
400 600 800 1,000 1,200 1,400 1,600 1,800
Form
atio
n V
olu
me
Fac
tor,
re
s b
bl/
STB
P, psig
Formation Volume Factor for 38°API Oil
Bt
Bo
pb
Page 10 of 16
Discussion of Results
At 60°F temperature, the bubblepoint is the highest for CO2-water mixture followed by the 32°API oil
and 38°API oil. The 32°API oil has higher bubblepoint pressure compared to 38°API oil due to higher
amount of heavy hydrocarbon components within the oil. It is assumed that methane gas is evolved when
the oils reach the bubblepoint. It is also assumed that the pressure, temperature and z-factor at standard
conditions are 14.65 psia, 520°R and 1.0 respectively. It is assumed that the correlations used for
hydrocarbons can be applied to CO2-water mixture. However, the values should be used with caution
because CO2-water mixture has different properties than hydrocarbons. It is assumed that the fluids in the
PVT cells mimic the behavior of the reservoir fluids. The liquid is said to be undersaturated (single-
phase) at pressures above the bubblepoint and saturated (two-phase) when the pressure is at and below the
bubblepoint.
The evolution of gas from the oil has a significant impact on the FVF. This causes a large decrease in
volume of the oil when there is a lot of gas. As pressure decreases, the oil expands slightly at constant
temperature. When pressure decreases below the bubblepoint, gas evolve within the cell and the
remaining oil has less gas in solution, thus resulting in a lower FVF. The laboratory analysis indicates the
FVF of both oils are below 2.0 res bbl/STB, which is consistent with a typical black oil.
At pressures above the bubblepoint pressure, the solution GOR is constant due to no gas evolved inside
the cell. When pressure is reduced below the bubblepoint pressure, gas evolves in the cell making less gas
dissolve in the liquid thus decreasing the solution GOR (McCain 1990). Similar gas solubility behavior is
shown for CO2-water mixture.
The total FVF and the FVF of oil are identical at pressures above the bubblepoint because no gas evolves
from the solution inside the cell. At pressures below the bubblepoint, the total FVF is more than the FVF
of oil because of the evolution of gas. The evolved gas is called free gas. The difference between the total
FVF and the FVF of liquid at pressures below the bubblepoint represent the volume of gas released in the
cell.
The coefficient of isothermal compressibility of liquid at pressures above the bubblepoint is virtually
constant except at pressures near the bubblepoint. This finding is supported by McCain (1990). Below the
bubblepoint pressure, the volume of liquid decreases as pressure is reduced. There is a large shift in the
compressibility because of the evolution of gas.
It is important to determine the pressure-volume relationship of reservoir fluids because it helps to obtain
the bubblepoint pressure. Knowing the bubblepoint pressure is significant in understanding the phase
behavior of reservoir fluids by calculating integral parameters such as gas solubility, FVF, and coefficient
of isothermal compressibility. The bubblepoint and relative volumes can be used as inputs in tuning
equation of state which is useful in reservoir modeling or simulation. The team recommends performing
hydrocarbon analysis on both crude oils to have a better understanding of the compositional changes
during the phase transition at pressures below the bubblepoint.
Page 11 of 16
Conclusion
The bubblepoint of a fluid can be determined by the significant change in slopes on a pressure vs. volume
plot.
The evolution of gas at bubblepoint has a significant impact on gas solubility, FVF, and coefficient of
isothermal compressibility values for liquid.
The team recommends performing hydrocarbon analysis on both crude oils to have a better understanding
of the compositional changes during the phase transition at pressures below the bubblepoint.
Page 12 of 16
References
Ahmed, T. 2001. Reservoir Engineering Handbook, second edition. Houston, Texas: Gulf Professional
Publishing/Elsevier.
Devegowda, D. 2011. Phase behavior. Lecture notes on phase behavior. The University of Oklahoma,
Oklahoma, United States.
McCain, W.D. Jr. 1990. The Properties of Petroleum Fluids, second edition, Tulsa, Oklahoma: PennWell.
Rosa, Adalberto Jose. 2011. Engenharia de Reservatorios de Petroleo, Rio de Janeiro, RJ, Brazil.
As production from oil reservoirs matures, improving the recovery factor will play a decisive role in
offsetting the decline in production. Many methods exist to improve the recovery factor. In this
experiment, waterflooding, surfactant flooding, and gas flooding were conducted. Significant findings
include:
1. The mobility ratios of waterflooding, surfactant flooding, and gas flooding are 1.79, 0.63, and 2.5
respectively. Oil recovery decreases as mobility ratio increases.
2. The microscopic displacement efficiency of waterflooding, surfactant flooding, and gas flooding
are 57.7, 49.2, and 33.9 respectively. High microscopic displacement efficiency results in low
residual oil saturation after flooding.
3. Surfactant flooding has the highest recovery factor followed by waterflooding and gas flooding.
Page 3 of 12
Introduction
Recovering oil from a petroleum reservoir can be achieved by primary recovery, secondary recovery and
tertiary recovery. Primary oil recovery normally refers to the production of hydrocarbons using the
natural driving mechanisms in the reservoir. Secondary oil recovery describes the additional recovery that
results from water injection or immiscible gas injection. Waterflooding is the most common method of
secondary recovery. Tertiary (enhanced) oil recovery refers to the additional recovery that is beyond what
could be recovered by primary and secondary recovery methods (Ahmed 2001). Tertiary recovery
includes chemical, thermal and miscible processes. In this experiment, waterflooding, surfactant flooding
and gas flooding are conducted.
Waterflooding
Waterflooding is the use of water injection to increase the production from oil reservoirs. This is
accomplished by the injection of water to increase the reservoir pressure to its initial pressure and
maintain it near that pressure (Warner Jr. 2007). The water displaces oil from pore spaces but the
microscopic displacement efficiency is affected by the interfacial tension in porous medium, rock
wettability, water-/oil-relative permeability, and capillary pressure, which in turn affect waterflood
recovery factor. Waterflood recovery factor is also influenced by intrinsic factors such as mobility ratio,
reservoir heterogeneity, pore geometry, and initial water-/oil-saturation distribution. The grain shape, size,
and sorting determine the pore-geometry heterogeneity. The wettability affects the capillary pressure and
relative permeability. The viscosity and relative permeability of the fluids contribute to the mobility ratio.
The initial water-oil-saturation distribution is important because it controls the efficiency of the
waterflood in portions of the reservoir and also relates directly to the residual oil saturation that can be
achieved at the end of a waterflood (Warner Jr. 2007). Higher oil saturation at the beginning of flood
operations increases the oil mobility and hence gives higher recovery factor (Ahmed 2001). Connate-
water saturation and residual oil saturation after waterflood are the most important numbers in
waterflooding because they are used to determine the displacement efficiency.
Surfactant Flooding
Surfactant flooding is a method where surfactant is injected into the reservoir either for wettability
alteration or to reduce the water-/oil-interfacial tension (Zitha et al. 2011). When a surfactant is added to
the sand pack that consists of oil and brine, the surfactant molecules adsorb at the interface, displacing
some of the water and oil molecules. Accumulation of surfactant at the interfacial zone disrupts the fluid
structure and decreases interfacial tension (Akkutlu 2012). Surfactant flooding recovery factor is affected
by the same factors that affect waterflooding recovery factor. The front-end cost of surfactant is very
high. To overcome this, the surfactant should be injected in a small volume for mobility control.
Retention of surfactants, which involves adsorption, precipitation, and phase trapping, is one of the main
factors for the unfavorable economics in chemical flooding (Austad & Milter 2000). A proper amount of
electrolyte is essential to maintain low interfacial tension with the oil globules trapped in the sand pack. In
the industry, the surfactant flooding process requires a pre-flush to condition reservoir, followed by
surfactant solution for releasing oil, followed by polymer solution for mobility control, and water to drive
the chemicals and oil bank towards the production well.
Gas Flooding
There are two different types of gas flooding: miscible gas injection and immiscible gas injection. In the
miscible gas injection, the injected gas mixes with oil, makes the oil lighter and reduces the oil viscosity
and surface tension of oil and rock. Consequently it becomes easier to produce the oil. In the immiscible
Page 4 of 12
gas injection the injected gas does not mix with oil. It only provides formation energy via incremental
pressure. Typically it yields only about half the recovery of miscible floods. Each technique has
advantages and disadvantages and is applicable to different types of reservoirs and conditions. CO2
miscible gas flooding is a major source of oil production in the U.S., particularly in West Texas,
Wyoming and Mississippi where natural sources of CO2 can be obtained at reasonable cost. CO2
applications are increasingly popular due to the increasing desire to sequestrate manufactured CO2.
Besides the miscible CO2 injection, there is also the enriched gas injection and the high pressure dry gas
injection (Rosa 2011).
Experimental Procedure
Initial Preparation
Before conducting the experiment, special safety requirements should be met. The use of safety goggles
and gloves is required. A sand pack is built using a pre-weighed 300 ml Lucite tube and various sized
(coarse, medium, and fine) sand grains. The relationship of coarse to medium to fine grains in the tube
was approximately 1:1:2. In an attempt to obtain 27% or less porosity, the sand grains are packed tightly
by pounding and continuously shaking the Lucite tube as it is being filled with the sand mixture. For
additional packing, the container is connected to a vacuum to pack the sand as tightly as possible. The
container is weighed again to calculate the pore volume and dry porosity. Next, the sand pack is
completely saturated with brine at a constant flow rate and then weighed. The wet porosity and absolute
permeability were computed.
Fig. 1—Weighing tubing assembly.
Waterflooding
The sand pack is flooded with mineral oil at a constant flow rate to determine the irreducible water
saturation and relative permeability of the fluids. A waterflood is conducted by injecting water at a
constant flow rate to displace the mineral oil. The volume of mineral oil displaced is collected to
determine the residual oil saturation and the effective permeability. The sand pack is weighed again after
waterflooding.
Surfactant Flooding
The sand pack is flooded with mineral oil until no water (or only fine oil bubbles) is produced to prepare
it for surfactant flooding. The displaced water is measured to determine the irreducible water saturation,
Swir, initial oil saturation, and relative permeabilities. The sand pack is weighed again. Surfactant is
injected into the sand pack at a constant rate to displace the mineral oil. The effective permeability to the
surfactant solution was determined during the last 1-2 pore volumes. The cylinders are allowed to set so
that the oil and water will separate so that the oil and water recovered can be measured. All equipment
and work area is cleaned as a safety precaution.
Page 5 of 12
Figure 2—Injection of surfactant and volume of mineral oil and surfactant.
Gas Flooding
A second sand pack is prepared with the same process as the initial preparation. The sand pack is flooded
with oil so as to reach original hydrocarbon saturation. This is checked by weight measurements. Oil is
then displaced from the sand pack with compressed air at constant pressure. Oil production is measured as
a function of time and gas injection is recorded at the same times. Flooding is continued until oil
production is zero.
Page 6 of 12
Results
Fig. 3—The cumulative oil production vs. amount of water injected for waterflooding.
Fig. 4—The cumulative fluids produced vs. time.
15
20
25
30
35
40
0 20 40 60 80 100 120 140
Np, c
m3
Wi, cm3
Np vs. Wi for Waterflooding
20
40
60
80
100
120
140
160
180
0 20 40 60 80 100 120 140 160 180
Np
+ W
i, cm
3
t, s
Np + Wi vs. t for Waterflooding
Page 7 of 12
Fig. 5—The cumulative oil production vs. amount of surfactant injected for surfactant flooding.
Fig. 6—Comparison of the performance plots for waterflooding and surfactant flooding.
15
20
25
30
35
40
45
0 20 40 60 80 100 120 140 160 180
Np, c
m3
Wi, cm3
Np vs. Wi for Surfactant Flooding
15
20
25
30
35
40
45
0 20 40 60 80 100 120 140 160 180
Np, c
m3
Wi, cm3
Np vs. Wi for Waterflooding and Surfactant Flooding
Waterflooding
Surfactant flooding
Page 8 of 12
Fig. 7—The cumulative oil production vs. amount of gas injected for gas flooding.
Fig. 8—Comparison of RF, Ed, and M. Surfactant flooding has the highest RF and Ed, followed by waterflooding and gas flooding. The figure also shows a reverse trend for mobility ratio.
5
10
15
20
25
30
0 50 100 150 200 250 300 350 400 450
Np, c
m3
Gi, cm3
Np vs. Gi for Gas Flooding
0.0
0.5
1.0
1.5
2.0
2.5
3.0
0
10
20
30
40
50
60
70
Surfactant Flooding Waterflooding Gas Flooding
Mo
bili
ty R
atio
Re
cove
ry F
acto
r, %
Dis
pla
cem
en
t Ef
fici
en
cy,
%
Recovery Factor
Displacement Efficiency
Mobility Ratio
Page 9 of 12
TABLE 1—COMPARISON OF SAND PACKS 1 AND 2
Sand pack Pore volume φdry φsaturated kabs Soi Swi kro
cm3 % % darcy % % fraction
1 73.09 26.91 25.24 3.84 97.14 2.86 0.24
2 75.29 27.34 26.00 3.74 92.97 7.03 0.23
TABLE 2—COMPARISON OF THREE ENHANCED RECOVERY METHODS
RF M Ed
% fraction %
Surfactant flooding 57.7 0.63 57.7
Waterflooding 52.1 1.79 49.2
Gas flooding 38.6 2.50 33.9
TABLE 3—WATERFLOODING AT RESIDUAL OIL
kw at Sor krw at Sor Sor Sw
darcy fraction fraction fraction
3.4330 0.8935 0.4938 0.5062
TABLE 4—SURFACTANT FLOODING AT RESIDUAL OIL
ksurfactant at
Sor krsurfactant at
Sor Sor Sw Ssurfactant
darcy fraction fraction fraction fraction
3.4482 0.8975 0.4104 0.0286 0.5609
The efficiency of the surfactant flood in terms of the oil in the sand pack at the beginning of the surfactant flood is 0.2033.
Page 10 of 12
Discussion of Results
The mobility ratio is lowest for surfactant flooding, and increasing from waterflooding to gas flooding. A
low mobility ratio is favorable for flooding operations because it will be easier for the injected fluid to
displace the recoverable oil. The recorded relative permeability after surfactant flooding is higher than
that of waterflooding. The microscopic displacement efficiency is highest for surfactant flooding followed
by waterflooding and gas flooding. High relative permeability and high displacement efficiency are
favorable for flooding operations because they result in low residual oil saturation after flooding.
The surfactant flooding method is the most efficient with the highest recovery factor, microscopic
displacement efficiency, and lowest mobility ratio. The waterflooding method also seems efficient and
can be a viable alternative if surfactant flooding is unavailable or too costly. The gas flooding process is
least efficient with the lowest recovery factor because it has poor sweep efficiency. Also, the mobility
ratio is highest for gas flooding and there is tendency for viscous fingering to occur. The oil recovery after
breakthrough is lower than other processes. However, it must be acknowledged that gas flooding is more
efficient in volatile oil reservoirs.
Conclusion
It can be concluded that the mobility ratio, relative permeability after flooding, microscopic displacement
efficiency, and the initial water-/oil-saturation distributions for flooding operations have significant effect
on the recovery factor.
Based on the analysis of the three methods, without the consideration of cost of operation and type of
reservoir, surfactant flooding is most favorable for oil recovery.
Page 11 of 12
References
Ahmed, T. 2001. Reservoir Engineering Handbook, second edition. Houston, Texas: Gulf Professional
Publishing/Elsevier.
Austad, T. and Milter, J. 2000. Surfactants: Fundamentals and Applications in the Petroleum Industry.
RF Vbrine t q kw at Sor krw at Sor Sor Sw Weight Relative error M Ed fraction cm3 s cm3/s darcy fraction fraction fraction g fraction fraction fraction