FLUID CONTENT EFFECT ON ACOUSTIC IMPEDANCE AND LIMITS OF DIRECT DETECTION CAPABILITY ILLUSTRATED ON AN OFFSHORE PROSPECT. APPROVED FLUID CONTENT EFFECT ON ACOUSTIC IMPEDANCE AND LIMITS OF DIRECT DETECTION CAPABILITY­ ILLUSTRATED ON AN OFFSHORE PROSPECT. by ANTONIO JOSE CATTO THESIS Presented to the Faculty of the Graduate School of The University of Texas at Austin in Partial Fullfilment of the Requirements for the Degree of MASTER OF ARTS The University of Texas at Austin December 1980 ACKNOWLEDGEMENTS The author wishes to express his appreciation to Dr. Milo M. Backus, the thesis advisor, for his valuable orientation and suggestions. Thanks are given to Dr. Frank Brown Jr, for the manuscript correction and initial helping in the U.S. life. Especial thanks are made to Petroleo Brasileiro S.A. -Petrobras for providing the opportunity to complete this work. ABSTRACT The presence of gas and oil in some sand formations decreases the seismic velocity and density to such an extent that anomalously large reflections coefficients are encountered at fluid contacts. Geerstma and Gassmann's theories are equivalent and provide a good way to study the physical properties that affect the elastic behavior of the porous rock. The fluid-contact reflectivity (gas-water, oil-water) can be well estimated based on the brine saturated velocity alone. A comparison between the estimated and observed fluid-contact reflectivities on seismic and well log data from an Offshore prospect showed a remarkable agreement. TABLE OF CONTENTS PAGE Chapter 1 -INTRODUCTION-BACKGROUND ................. 1 Chapter 2 -OBJECTIVES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Chapter 3 -FLUID-CONTACT REFLECTIVITY .............. 7 CONTACT REFLECTION COEFFICIENT .......... 7 Fluid-contact reflectivity and its significance on direct detection exploration. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 GEERSTMA AND GASSMANN'S EQUATIONS ....... 14 CONSTITUENT PROPERTIES. . . . . . . . . . . . . . . . . . 19 Rock-matrix properties. . . . . . . . . . . . . . . . . . 19 Fluid properties ........................ 20 VELOCITY AND DENSITY FOR BRINE-SATIJRATED ROCKS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 8 The time-average equation ............... 29 Pore-fluid effect on yelocity and density of the porous rock ...................... 32 Prime dependence of velocity on porosity 36 Dependence of velocity on type of porosity................................ 39 DEFINITION OF REALISTIC ZONE FOR RESERVOIRS ROCKS IN THE VELOCITY VERSUS DENSITY GRAPH ........................... 44 USE OF GASSMANN'S EQUATIONS TO PREDICT GENERAL MAGNITUDE OF THE FLUID-CONTACT REFLECTIVITY ................ 44 Importance of parameters controlling Fluid-contact reflectivity ................ 48 Effect of Poisson's ratio on the fluid-contact reflectivity ...................... 49 Brine-saturated rock velocity and porosity versus fluid-contact reflectivity. . 5 2 Effect of fluid properties on the fluid-contact reflectivity ...................... 53 Chapter 4 -PREDICTION OF FLUID-CONTACT REFLECTIVITY .. 60 FLUID-CONTACT REFLECTIVITY VERSUS RESERVOIR TYPE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 0 PREDICTION OF FLUID-CONTACT REFLECTIVITY ON VELOCITY VERSUS DENSITY GRAPH .......... 67 GENERALIZATIONS ON FLUID-CONTACT REFLECTIVITY IN RESERVOIR ROCKS IN GENERAL:-MAJOR CONCLUSIONS ............... 70 Chapter 5 -OFFSHORE AREA ONE -PREDICTION OF FLUID­CONTACT REFLECTIVITY ...................... 72 RESERVOIRS OF OFFSHORE AREA ONE ........... 78 Chapter 6 -SEISMIC DATA FROM OFFSHORE AREA ONE ....... 85 Chapter 7 -HYDROCARBON DETECTABILITY ON OFFSHORE AREA ONE. RECONCILIATION OF PREDICTION WITH OBSERVATIONS ........................ 101 RE SERVO IRS FROM WELL 1 . . . . . . . . . . . . . . . . . . 101 Reservoir 1-3 . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 2 Reservoirs 1-7, 1-8 and 1-9 .............. 106 Reservoir 1-11 ........................... 110 Reservoir 1-14 ........................... 111 Reservoir 1-16 -Oil effect .............. 116 Reservoir 1-2 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . 117 Reservoir 1-31 and 1-31 .................. 117 Reservoir 1-34 and 1-35 .................. 120 RESERVOIRS FROM WELL 4................... 124 Reservoir 4-2 -Oil effect in thin reservo1r . ............................... 12 7 Reservoir 4-8 and 4-9 .................... 129 Reservoir 4-11 and 4-12 .................. 132 Others reservoirs from well 4............ 134 Chapter 8 -CONCLUSIONS AND RECOMENDATIONS FOR FURTHER l\TORK ••.•....••.••..•••.•..•••..•••...•..• 137 REFERENCES ............................... 141 VITA..................................... 148 LIST OF FIGURES PAGE 3.1. Hypothetical geological model for oil and gas field..................................... 10 3.2. Gas reservoirs in different situations ........ 12 3.3. Density of pore fluids versus depth........... 23 3.4. Bulk modulus of brine as a function of temperature. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 3.5. Oil bulk modulus as a function of depth and specific gravity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 5 3.6. Gas bulk modulus as a function of depth and specific gravity.............................. 26 3.7. Specific gravity versus depth of Tertiary oils of the U.S. Gulf Coast ........................ 27 3.8. Velocities under differential pressures of water-saturated sandstone core ................ 30 3.9. Velocity versus porosity for water-saturated sandstone ..................................... 31 3.10. Velocity as a function of depth showing consolidation effect for in situ Tertiary sands ......................................... 33 3.11. Bulk density versus brine saturation for a sands tone at several porosities. . . . . . . . . . . . . . . 35 3.12. Interval velocity versus porosity............. 38 3.13. Rock-frame bulk modulus versus density or porosity...................................... 42 3.14. Rock-frame bulk modulus versus brine-saturated sand velocity................................. 43 3.lS. Sedimentary rocks on the porosity versus brine saturated P-wave velocity graph ......... 4S 3.16. Fluid-contact reflectivity versus Poisson's ratio for gas-saturated sand.................. SO 3.17. Fluid-contact reflectivity versus Poisson's ratio for oil-saturated sand.................. Sl 3.18. Brine-saturated sand velocity versus fluid-contact reflectivity.......................... S4 3.19. Bulk density versus fluid-contact reflectivity SS 3.20. Fluid-contact reflectivity as a function of brine-saturated velocity and hydrocarbon bulk modulus .................................. 58 3.21. Fluid-contact reflectivity against brine­saturated P-wave velocity for a reasonably range of hydrocarbon compressibility.......... S9 4.1. Bulk modulus of a sandstone as a function of brine saturation and depth .................... 64 4.2. P-wave velocity of a sandstone as a function of brine saturation and depth ................. 6S 4.3. Fluid-contact reflectivity as a function of bribe saturation and depth .................... 66 4.4. Fluid-contact reflectivity of a gas sand as a function of density and brine-saturated velocity...................................... 68 4.S. Fluid-contact reflectivity of a oil sand as a function of density, porosity and brine-saturated velocity ............................ 69 S.l. Seismic lines and well locations on Offshore Area One . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 3 S.2. Brine-saturated sandstone velocity plotted against depth for Offshore Area One ............ 7S S.3. Density values for brine-saturated sandstone plotted against depth for Offshore Area One .... 76 S.4. Offshore Area One reservoirs against the time­average curve on the velocity versus porosity graph .......................................... 77 S.S. Lithologic log of producing intervals from well 1 and well 4.............................. 82 S.6. Prediction of the fluid-contact reflectivity for producing gas reservoirs of Offshore Area One . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 3 S.7. Prediction of the fluid-contact reflectivity for producing oil reservoirs of Offshore Area One . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 4 6.1. Seismic section of strike line 2 ••••••••••••••• 89 6. 2 . Seismic section of strike line 4 ............... 90 6. 3. Seismic section of strike line 9 .........•..... 91 6. 4. Seismic section of dip line 12 ................. 92 6. s. Seismic section of dip line 1 5 • • • • • • • • . • • • • • • • • 93 6. 6. Seismic section of dip line 2 7 . . . . . . . . . . . . . . . . . 94 6. 7. Seismic line 4 showing "flat spots" ............ 9S 6 . 8 . Seismic line 9 -"tying" between hydrocarbon reservoirs and the enhancement of the reflected seismic signals ................................ 96 6.9. Gas reservoirs on line 12 ..................... 97 6.10. Well-1 reservoirs on line 15 .................. 98 6.11. Well-4 reservoirs on line 27 .................. 99 6.12. Seismic line 15, flattened by static corrections ...................................100 7.1. Reservoir 1-3 map .............................103 7.2. Logs from well 1 in the vicinity of reservoir 1-3 .... ...................................... . J.03 7.3. Reflection model for reservoir 1-3 ............105 7.4. Logs from well 1 in the vicinity of reservoirs 1-7 . 1-8 and 1-9..............................10 7 7.5. Reservoir 1-7 map .............................108 7. 6. Reservoir 1-9 map .............................108 7.7. Reservoir 1-11 map ............................113 7.8. Logs from well 1 in the vicinity of reservoir 1-11 ..........................................113 7.9. Reservoir 1-14 map ............................114 7.10. Logs from well 1 in the vicinity of reservoir 1-14 ...... ................................... . 114 7.11. Seismic line 15 -displayed with reversed polarity......................................115 7.12. Reservoir 1-16 map ............................118 7.13. Logs from well 1 in the vicinity of reservoir 1-16 ........ ..................................118 7.14. Reservoir 1-22 map ............................119 7.15. Logs from well 1 in the vicinity of reservoir 1-22 ..........................................119 7 . 16 . Reservoir 1-31 map .............................12 2 7.17. Logs from well 1 in the vicinity of reservoir 1-31 ................. ......................... . 122 7.18. Reservoir 1-34 map .............................123 7.20. Logs from well 1 in the vicinity of reservoirs 1-34 and 1-35 ..................................123 7.20. Acoustic impedance against depth at the well 4 location................................125 7.21. Log data for reservoir 2.......................130 7.22. Well 4 log data for reservoirs 4-8 and 4-9 .....133 7.23. Reservoir 4-8 map ..............................133 7.24. Reservoir 4-11 map .............................136 7.25. Well 4 log data for reservoir 4-11 and 4-12 ....136 APPENDIXES PAGE Appendix A -Time-structural map from the upper seismic horizon, presented on Figures 6.1 to 6.6 .... ................... 145 Appendix B -Time-structural map from the medium seismic horizon, presented on Figures 6.1 to 6 .6. . . . . . . . . . . . . . . . . . . . . . . 146 Appendix C -Time-structural map from the lower seismic horizon, presented on Figures 6.1 to 6.6 ........•.•..•......... 147 CHAPTER 1 -INTRODUCTION -BACKGROUND It is knoW1that the presence of gas in sand formations commonly decreases the seismic velocity and density to such an extent that anomalous large reflection coefficients are encoutered at gas-water contacts. Although a more moderate effect is encountered for an oil-water contact, the discovery of the correspondence between seismic reflectivity and the presence of hydrocarbons in reservoirs added a new geophysical dimension for subsequent geologic interpretations, and led to a profound effect in petroleum exploration (Domenico, 1976). Prior to 1970, geophysicists used the seismic method primarily for structural mapping of sedimentary layers, only attempting to use reflection time. Other seismic reflection characteristics, such as amplitude and frequency spectrum, that could lead to a better knowledge of the lithology and porosity in subsurface layers, were disregarded in recording and computer processing of seismic data. Precise measurements of the amplitude of the reflected signals are allowed today by modern digital seismic recording instruments. It could be expected that this information may increase the knowledge of the physical properties of the reflecting earth. Nevertheless, the task is not so simple because a simple one-to-one relationship between amplitude and some other significant parameter should not be expected. Amplitude is related to a series of parameters. Sheriff (1973) lists and discusses a series of effects that can affect the amplitude of seismic waves. These factors can be divided into three categories: those that do not relate to the subsurface information, those indirectly related to the subsurface information and those that are directly related to the characteristics of the subsurface. Source strength and coupling, attenuation in the near surface, geophone sensitivity and coupling, and instrument response can be listed in the first category. In marine work variations from these causes are normally small compared to land work. For the second category, examples include spher:ical divergence and ray-path curvature, absorption, and peg-leg multiples. Spherical divergence is related to the geometrical dilution of the energy density. In a constant velocity medium, the energy density decreases inversely as the sauare of the travel time. Absorption is still very poorly understood in terms of the mechanism by which seismic energy gets converted into heat but there is universal agreement that high frequen::ies are attenuated faster than low frequencies and absorption acts essentially as a low pass filter. Peg-leg multiples from thin reflectors delay part of the energy, changing the wave shape and the effect is again similar to a low pass filter. Spherical divergence, absorption, scattering by inhomogeneities, transmissivity losses, and peg-leg multiples all produce a general decrease of amplitude with time. They produce similar effects and it is difficult to tell how much of the observed dependence is attributable to each mechanism. Reflection from interfaces, reflection curvature, and incident angle are factors which are controlled predominantly by the subsurface of interest and are placed in the third category. The reflection from interfaces involves directly the lithology, porosity and fluid content of the rocks on either side of the interface. The reflection amplitude is also controlled by the geometry of the interfaces. If the reflector is curved, it will act as a curved mirror converging the seismic energy.A concave curvature causes an amplitude increase and a convex curvature, an amplitude decrease. Considering the oblique incidence of the ray path, the amplitude begins to decrease slightly as the angle of :incidence increases from zero, but subsequently near the vicinity of the critical angle it increases with the incident angle. The fluid that fills the pores of the rocks has an important effect on the value of the reflection coefficient. Particularly, in the case of some lIDConsolidated sands, anomalous increases in the amplitude of the reflected waves can be attributed to hydrocarbon content. On a seismic section, the effect of hydrocarbons sometimes appears as conspicuous and localized strong amplitude reflections knownas "bright spots". The correspondence between "bright spots" on the seismic sections and the presence of hydrocarbon fluids led to the direct-detection technology, giving a new and revolutionary capability to the seismic reflection exploration method. This paper deals with the effect of hydrocarbon content on the acoustic impedance of the rocks (mainly sands), and attempts to establish the limits of the direct detection capability. A prediction of the fluid-contact reflectivity on porous rock will be estimated based on the interval P-wave velocity of the brine-saturated rock that can be easily read from sonic-well logs. In Chapter 2 the objectives of the study are explained while in Chapter 3 a broad discussion of the fluid-contact reflectivity is developed , including observations from related literature. Chapter 4 deals with predictions for fluid-contact reflectivity in general reservoirs and in Chapter 5 we develop the predictions in a particular area where the intent is to test the results. Chapter 6 explains the seismic and geologic features from this area while Chapter 7 reconciliates predictions with observations. CHAPTER 2 -OBJECTIVES Three major objectives motived this work: characterization of the fluid.contact reflectivity, prediction of fluid-contact reflectivity, and assessment of reservoir detectability in a knownarea. The first goal is to integrate most of the related theory and the available information to characterize the fluid-contact reflectivity. Knowing all the possible aspects of the fluid­contact reflectivity, the second goal is to predict its value for some area where seismic work and drilled wells are available. The third goal is to study the seismic detectability of know reservoirs from the predictions. The validity of the predictions is tested against actual seismic data. CHAPTER 3 -FLUID-CONTACT REFLECTIVITY 3.1 CONTACT REFLECTION COEFFICIENT Reflection coefficient of an interface is defined as the ratio between the amplitude of the reflected wave Ar to the amplitude of the incident wave Ai, that is: R Ar --­ = PzVz -P1V1 (3-1) Ai PzVz + P1V1 where P2 and P1 are the bulk densities of the lower and upper layer, respectively. V2 and V1 are the respective p-wave velocities. The reflection coefficient varies with the angle of incidence of the wave at the reflecting interface. The variation depends upon the velocity and density of each of the two layers, as well as their Poisson's ratio. In the present study, only the normal incidence for which equation 3-1 is applicable, is taken into account. The bulk density p2 and p1 is simply the weighted-by-volt.nne average of the constituent densities given by the equation below. p = 4 Sw pw + 4 (1-Sw) pf + ( 1-~) Pm ( 3-2) where: ~ = fractional porosity of the rock Sw = water saturation PW = density of the water pf = density of the fluid (oil or gas) pm = density of the rock matrix The reflection coefficient is a measure of the acoustic impedance between two layers. In order to get a strong reflection, either a large velocity contrast, or a large density contrast, or both, are required. Some values for the reflection coefficient shown on Table 3.1, illustrate the range of variation that the reflection seismic system must comprehend. 3.1-1 Fluid-contact reflectivity and its significance on direct-detection explcration. Let us consider in Figure 3.1 a theoretical model of a structural oil field with associated gas. The sand layers overlain by shales have constant porosity but are filled by three different kinds of fluids.Fluid-contact reflectivity is the absolute value of the reflection coefficient at the interfaces between these different fluids. TABLE 3.1 SOME COMMON VALUES OF REFLECTION COEFFICIENT AFTER SHERIFF (1973) Velocity Density Reflection Types of Reflection Contrast Contrast Coefficient 1. Very strong 3050 None .20 reflector 4680 2. Good reflector 4200 None .03 4500 3. Weak reflector 2440 None .006 "'Z4iO 4. Soft ocean None 1.0 .33 bottom 2.0 5. Hard ocean 1500 1.0 .67 bottom 3000 2.5 6. Base of weathering 450 1.5 .68 mm 7:0 7. Gas sand at 1850 1.85 .30 5000 ft 2750 2.35 30% porosity Normal pressure v 0 2 4 6Km. EF3 E5+I Aprox. Scale Figure 3.1. Hypothetical geological model for oil and gas field. Fluid-contact reflectivity is the absolute value of the reflection coefficient at the interfaces between these different fluids. However, when oil is lacking, the interface will be between brine sand and gas sand, and this is the most favorable situation for direct hydrocarbon detection exploration. Most of this study is based on calculations and predictions of the fluid-contact reflectivity. One can argue that a more logical interface should have been chosen. For example, the interface between oil or gas sand against the shale layers. Several papers dealing with this kind of contact reflectivities have been published in the last five years (Domenico, 1975;Gregory et al, 1975; etc.). The importance of the fluid-contact reflectivity studies are shown on Figure 3.2, were the same kind of reservoir in different situations is presented. In case A and C pay thickness is large enough to prevent a tuning between the reflected signals from the interfaces: shale­gas sand, and gas sand-brine sand. The interface shale-gas sand, on case A, will not produce a "bright spot". Instead, what is produced is a ''dim spot" since it passes from a reflectivity of .06 to -.02. Although the interface gas-brine does not produce a "bright" reflection either, the value of .08 is a good one 0 2 Km. Figure 3.2. Gas reservoirs in different situations (obs: values for density and velocity were taken from Backus and Chen, 1975). and will produce a very strong and consistent reflector. From the point of view of seismic interpretation the result is the same because an interpretation based on hydrocarbon accumulation can be supported by a flat reflector unconformable with surrounding lithologic reflection. (Backus and Chen, 1975). For case C, a very high reflectivity for both interfaces is shown and they will appear as very strong reflectors. The target modeled on case B is the most difficult situations where the only good reflector is the gas-brine interface but without sufficient areal extent to produce good seismic resolution. In the last case if the two way travel time within the gas sand is equal to the half period of the average seismic wave, constructive interference of the top and base of the reservoir will result, and a very strong reflector will be produced. Consequently, in all three cases, the most consistent reflection interface will occur between brine sand and gas sand. The lateral change of the seismic character, which is the most important clue for direct detection, will be also controlled by the strength of the fluid-contact reflectivity. 3.2 GEERSTMA AND GASSMANN'S EQUATIONS The velocity of compressional waves in non-porous rock is given by: V = (K + 4/3 ΅ p p (3-3) where K is the bulk modulus or the reciprocal of the compressibility, J.1 is the shear modulus and p is the density. For porous rock, the equation 3.3 becomes more complicated because the effect of the presence of fluid in the pores must be added. Among several theoretical formulations, specifically oriented toward estimation of seismic velocities as a function of fluid saturation, two are used in this study: one from Geerstma (1957) and other from Gassmann (1951). From basic equations developed by Biot (1956), Geerstma obtained a general equation for elastic waves of infinite frequency: 0 ~ + (1-B)(l-B-~) v ={[(-1 + _i_ ΅) +~ F p Cr 3 (3.4) (1-~ -B)Cm + ~ Cf where: B = the ratio Cm/Cr Cm = compressibility or the reciprocal of bulk modulus for the rock matrix. Cr = compressibility of the reservoir rock devoid fluid content or the rock-frame compressibility l1 = shear or rigidity modulus = fractional porosity ~ p = bulk density of the rock pm = density of the rock matrix pf = density of the pore fluid F = coupling factor -describes the degree of coupling between pore fluid and rock matrix. For F = 1 no coupling 00 exists and for F = a perfect coupling exists. When coupling between fluid and grain matrix is perfect, equation 3.4 is reduced to the zero frequency case and the compressional wave velocity is independent of frequency. 1 I 2 2 (3.5) 1 4 (1 -B) ] 1 } v p = {[( er + ~΅)+Cl -~ -S)Cm + ~Cf ~P~ Substituting the compressibility values by its reciprocal and making some arithmetical operations: Km -Kr 2 VP = {[ (Kr + ( ) 1 (3.6) p Thus, the equation 3.6 for porous rock is the same equation (3.3) for non-porous rock, with the correction for the effect of pore fluid. Gassmann (1951) showed that in a closed system with grossly isotropic and homogenous rock, and making assumptions that the pore size is small compared to the wave length, the use of elementary elastic theory yields the following interrelationship between the rock parameters: K = Km (Kr + Q)/(Km + Q) ( 3. 7) where: K =bulk modulus of the whole rock Km= bulk modulus of the rock matrix Kr= bulk modulus of the rock devoid fluid content or the rock-frame bulk modulus. Q is given by the formula: Q = Kf (Km -Kr)/0 (Km -Kf) (3.8) where Kf is the bulk modulus for a fluid mixture. Gassmann also noted that: 2 ΅ =΅r =V p (3.9) s /2 VP = [ (K + +΅) /p] l (3.10) where p is given by: p = (1 -q) pm + qpf (3.11) It is easily proved that the sum of the first and third term in the inner brackets of the equation 3.6 is replaced by the bulk modulus Kin equation 3.10: 2 (1 -Kr/Km) K = --"'------"------+ Kr (1 -q -Kr)_l_ + q /Kf (3.12) Km with some mathematical operations: K = _1_c_1_ _ _1_) + q/Krc.J_ __1_) Km Kr Km KI Km (3.13) Equation 3.13 is the same Gassmann's equation for bulk incompressibility (195la, p.15, equation 59). + Kf Km -Kf Kr Km(Kr (Km -Kf) ~ K = (3.14) Km+ Kf Km -Kf Kr (Km -Kf) ~ Making use of the equation 3.8 we reach again to the equation 3.7 given by Gassmann. Thus, Geerstma and Gassmann's equation are identical when we consider the zero frequency case or when a perfect coupling between fluids and grain matrix (F =00 ) exists. White (1965) gives these relationships in the form: M = Mr + c1 -~);c ~+Cl~~) -~2) (3.15) where M and Mr are the P-wave modulus for the porous rock when filled and empty of fluid content, respectively. Knowing the characteristics of the rock matrix and fluids, and the P-wave velocities of the brine-saturated rock, the velo~ity on the ga~ o~ above theo~ie~. 3.3 CONSTITUENT PROPERTIES Before going through the calculations a discussion of constituent properties should be worthwhile, because they control the elastic properties of the rocks. The three components that come into the formulation are: 1. The solid matter of which the skeleton or frame is built, i.e., mineral grains 2. The frame or skeleton of the rocks 3. The fluid occupying the pore space of therocks 3.3.1 Rock-matrix properties The parametersof the solid matter that enter the above equations are the density, the bulk modulus of the grain matrix, and the effective rock-frame modulus that would refer to the rock-frame bulk modulus plus four­thirds times the rock-frame shear modulus. Some typical values for density and bulk modulus of principal minerals of common rocks are listooand Table 3. 2. For practical purposes the effect of temperature and overburden pressure on these parameters is not considered since the depth range of petroleum exploration is insufficient to cause significant change. The bulk modulus of the skeletal frame is the reciprocal of the compressibility of the rocks if the pores are empty. The magnitude of the rock frame modulus depends on how the grains are interconnected with each other. Strong interconnection means a strong frame and a high rock-frame bulk modulus value. 3.3.2 Fluid properties The densities of gas, oil and brine and their bulk moduli are the relevant fluid parameters for the closed system or perfect grain-fluid coupling approximation. The temperature, overburden pressure, chemical composition and quantities of dissolved salt have crucial importance on the values of the fluid properties. Values of density of the brine, oil and gas assuming a variation with depth, are shown in Figure 3.3. Figure 3.4 shows the bulk modulus variation for brine as a function of temperature TABLE 3.2 BULK MODULUS AND DENSITY OF SOME MINERALS AFTER GREGORY (1976) Solid Bulk Modulus Density dyne s I cm2 x 1010 gr/cm3 Calcite Anhydrite Dolomite Halite Gypsum Quartz 67 54 82 23 40 38 2. 71 2.9 2.87 2.16 2.32 2.65 and pressure, and Figures 3.5 and 3.6 shows the bulk modulus variation for oil and gas, respectively, as a function of depth and specific gravity. Figure 3.4 was modified from Dorsey (1940) and Figures 3.5 and 3.6 were calculated based on method given by Schechter (1977), assuming some medium value for the bubble-point pressure of oil. Higher values for bubble-point pressure result lower values for bulk modulus. On Figure 3.7, specific gravity is plotted against depth based on the average of a large number of gravity determinations of tertiary oils of the Gulf Coast. The wide range of values for these fluids will have important effects on the value of the predicted fluid-contact reflectivity, as shown in subsequent discussion of the effect of fluid properties over fluid­contact reflectivity. Figure 3.3. Density of pore fluid versus depth after Taylor, et al. (1977). TEMPERATURE °F 80 100 120 140 160 180 200 220 240 260 280 TEMPERATURE °C Figure 3.4. Bulk modulus of brine as a function of temperature. After Dorsey (1940). 1. Ow =1.0 At : t.5° F/ 100ft 2. 3. 4. II> 5. - "' 0-.:JI(. 6. ::r 7 . ..... a. w e. 0 9. 10. 11. 6.0 7.0 8.0 9.0 10.0 11.0 t2.0 13.0 14.0 BULK MODULUS (x109 dynes/cm.2) Figure 3.5. Oil bulk modulusasa function of depth and specific gravity. Based on method given by Schechter (1977). .5 2.0 3.0 Ooir =t.O ~T : l.5° F/100 ft ~P = 47 ps i/ft TS = 50° F 4.0 -Cl> Cl>-0 ""' 5.0 6.0 :c I-Cl. 7.0 w s.o 0 9.0 10. 11. 12. 1.0 t.5 2.0 0 f'Tl "O -I = 2.5 ,.; 3 3.0 3.5 .03 .10 .20 .50 1.0 2.0 3.0 BULK MODULUS ( x109 dynes/cm~) Figure 3.6. Gas bulk modulus as a function of depth and s pecific gravity . Based on method given by Schechter (1977). D E P T H Km ) . 5 1.0 1.5 2 .0 2.5 3.0 3.5 1.00 r-~~~.--~~-..~~~--..~~~.........~~~--~~~.......~~~...-... 10 Owoter = · >­ .... .90 > ct a: (!) .80 (.) ..... (.) w .70 a.. (/) 0 2 4 6 8 10 12 D E P T H kilo feet ~igure 3.7. Specific gravity versus depth based on the average of a large determination in the Tertiary oils of the Gulf Cost. After Gregory (1976) . 3.4 VELOCITY AND DENSITY FOR BRINE SATURATED ROCKS Compressional velocity in porous media is treated extensively in the literature. Examples include the work of Voigt (1928) and Reuss (1929) on lithology; Wyllie et al (1956, 1958) on differential pressure and porosity; Gregory (1974, 1977), Tokzoz (1976), Domenico (1974,1976) on pore fluid; and Faust (1953) on geologic age and depth. Consolidated rocks are submitted to laboratory measurements and unconsolidated rocks have been simulated l:y synthetic materials. These studies have shown that the primary factors affecting velocity are: lithology,differential pressure, porosity, pore fluid, burial depth, cementation, and geologic age. These parameters are not independent of each other. For example, differential pressure and porosity are both related to burial depth, and cementation is largely a function of burial depth and geologic age. Furthermore, these primary factors are not directly related to velocity but they do modify directly the elastic moduli of the rocks, which in turn determine the velocity. 3.4.1 The time-average equation Wyllie et al (1956, 1958) have shown by laboratory measurements that velocity increases with increasing differential pressure, asymptotically approaching a terminal value, as shown on Figure 3.8. The influence of pressure on velocity becomes small at pressure corresponding to in situ deeper sediments. Under this condition velocity is determined primarily by porosity and mineral composition. The time-average equation given by Wyllie et al empirically relates velocity and rock parameters for a fairly wide range of porosities: 1 1 -­ I-u 0 _J UJ 10000 > WATER SATURATED SANDSTONE 6P=DIFFERENTIAL PRESSURE= EXTERNAL FRAME PRESSURE LESS INTERNAL FLUID PRESSURE -*---*-----* ~P=2000 ---)E---~---*----* AP• 1000 -* --*-~-9*----*---~~P= 0 0 2000 4000 6000 8000 10000 EXTERNAL PRESSURE, PSI 30 I-25 z UJ u a:: UJ a..~ 20 r 1­ Ui 0 a:: ~ 15 10 5 0 1· VELOCITY, KILO FEET PER SECOND 9 10 II 12 13 15 17 19 TIME AVERAGE ~ MATRIX 19500 FL~D 5000 : '= 2-=o--~~--~::----::-':-----::L:-------1----1.--~ RECIPROCAL VELOCITY, MICRO SEC/FT. Figure 3.9. Velocity versus porosity data determined in the laboratory for water saturated sandstone. From Gardner et al. (1 97 4) . representative velocity versus depth for brine-saturated sand based on sonic log data. The dotted curve is based on laboratory data for fresh unconsolidated packings of quartz sand grains saturated with water at pressures correspondirg to the depth, and the dashed curve shows the time-average velocity calculated from well log porosities. In this basin, the shallow layers are unconsolidated and the velocity is slightly greater than that of sea water.With increasing depth the velocity increases because of the increasing pressure and cementation and resultant change in the nature and magnitude of porosity. The rapid increase of velocity continues until the time-average velocity is approached. Beyond this depth, the layers behave like other well-consolidated rock and the velocity of the sands depends mainly on magnitude of the porosity. Any deviation to the left on this curve at those depths should be credited to the influence of abnormal pressure or effect of hydrocarbon saturation. 3.4.2 Pore-fluid effects on velocity and density of the porous rock Figure 3.11 shows the variations in the bulk density of a sandstone as a function of brine saturation at three different porosities using the equation 3.2. IN-SITU SAND BRINE SATURATED / TIME AVERAGE MATRIX 18000 4000 \BRINE 5260 \/ 1­ w w u... EXPERIMENTAL :r 8000 SAND PACK l­ a.. UNCONSOLIDATED w BRINE-SATURATED P 0 R 0 SIT Y = 35 __., '. 12000 \ \ \ \ \ 16000 \ 0 2000 6000 10000 14000 VELOCITY, FEET PER SECOND Figure 3.10. Velocity as a function of depth showing consolidation effect for in situ Tertiary sands. Velocity of experimental sand packs at pressures corresponding to these depths are also shown. From Ga rdner e t al (19 74). The density varies linearly with the difference between density and gas or oil density,providing that porosity is the same for a given depth. The variation for a gas sand is significantly greater because the difference between brine density and gas density is larger than between brine density and oil density. For the velocity variation due to pore fluid effect, we quote some of the main conclusions given by reseachers,particularly from Domenico (1975, 1977) and Gregory (1976, 1977): "The velocity in a sand reservoir decreases with increasing bulk density and increases with decreasing fluid compressibility as water saturation increases." (Domenico, 1975). "With increasing depth the velocity increases partly because the pressures increase and partly because cementation occurs. Cementation is the most important factor." (Gregory, 1977). "Measured velocities are nearly constant from complete gas saturation to a brine saturation of approximately .85 above which the velocity increases abruptly to the velocity for complete brine saturation." (Domenico, 1977). 2..30 2.. 2.0 2..10 "' E 0 ....... Cl 2..00 >­ I­(/) 1.90 z UJ 0 1.80 ___ 01 L SAND --GAS SAND 1.70 5matrix = 2 .65 or /cm~ Jwater = 1.00 gr/cm~ 1.60 ...______..__....______________,_____ 0 .2 .4 .6 .e 1.0 B R I N E SATURATION Figure 3.11. Bulk density versus brine saturation for a sandstone at several porosities typically found at the depths indicated. "Velocity variation agrees qualitatively with the variation obtained from a general theoretical e21pression derived by Geerstma (1961) ." (Domenico, 1977). "Gassmann's theory is typically valid for sedimentary rocks in interrelating elastic components, densities and P-wave velocities for different rock components and for the consolidated whole rock." (Gregory, 1977). "For unconsolidated shallow gas sand, some computations using Gassmann's theory indicate a substantial difference in P-wave velocity from that of the same sand filled with brine. Some possibility of recognizing this effect in seismic reflections exists." (Gregory, 1977). "For a given concentration of pores, the flatter pores have a relatively greater effect on velocities than the rounder or spherical pores." (Tokzoz et al, 1976). "The properties of the saturating fluids generally have greater effects on compressional velocities than on shear velocities." (Tokzoz et al, 1976). 3.4.3 Prime dependence of velocity on porosity Several experimentalists have agreed that 37 compressional and shear wave velocity varies inversely with variation in porosity. For example, Wyllie et al (1956) have attempted to determine the relationship between velocity and porosity from sonic logs and direct measurements of cores taken from the logged intervals. A plot of the measured porosities versus logged transit time in microseconds per 5.92 ft (Figure 3.12), shows considerable scattering of points but a general trend of decreasing velocity with increasing porosity is evident. The linear curve on this plot is obtained from the time-average equation (3.16) rewritten as: 6t = ~6tf + (1 -~) 6tm ( 3 .1 7) where 6t, 6tm and 6tf are the travel times or the inverse of velocities for the total rock, rock-matrix and fluid respectively. It is well known that porosity decreases with depth as a result of increase on overburden pressure. The age of the formation has great effects on cementation and, therefore, on porosity. Furthemore, velocity indirectly ends up affected by these parameters through effects on porosity. Faust (1953) shows this empirical relationship where velocity is given dependent on age and depth. (3.18) where K=l25.3, Z=depth (feet), t=age (years) and V=velocity (ft/sec). 600 500 400 300 TRANSIT TIME MICRO-SEC. P(R 592 FT Figure 3.12. Interval velocity and transit time versus porosity. From Wyllie et al. (1956). >­I­ VI 0 er 0 Cl. INTERVAL VROCITY-FEET PER SEC . 8 § N 00 .p 10 .. ' °t~ ••• 0 .."..~·. 5 • 0 • .~• • • •I 39 3.4.4 Dependence of velocity on type of porosity. In any graph of velocity versus porosity the carbonate rocks (Wyllie et al, 1956, Figure 18; Sarmiento, 1961) show wide scattering of values, Because of this, some authors come to the conclusion that the relationship between velocity and porosity, such as that for consolidated elastic sediments, cannot be established for carbonate rocks. The reason for this is that vugular and frature porosities affect bulk compressibility of the rocks in a different way than does intergranular porosity. In addition to the magnitude value of the porosity, velocity is dependent on the type and size of the pores. According to Sarmiento (1961), "below a certain size, the pores are probably included in the elastic character of the rocks; but in the case of large pores. Or vugs, the acoustic pulse probably follows a least-time pa.th around the pores rather than going through them," However, Tokzoz (1976) reports that simple compressibility considerations better explains the observations. Based on Gassmann's theory the significant characteristic that controls velocity lies in the way the grains are interconnected to each other or how the rocks were structurally formed. The effect of the rock frame is included in his theory by the parameter rock­frame bulk modulus, Kr. The value of the rock-frame bulk modulus can be calculated from the porosity and brine-saturated P-wave velocity. Figures 3.13 and 3.14 show precisely these calculations assuming variations in the porosity of the rock with a fixed velocity and vice-versa. In the vicinity of the normal compacted sandstone indicated by the Wyllie equation, the rock-frame bulk modulus (Figure 3.13) shows almost no variations. But with the decreasing porosity, there is a decrease in the rock-frame bulk modulus necessary to maintain the assumed P-wave velocity constant. This fact possibly explains the observations by Gregory (1976) and Sarmiento (1967) that relatively small porosity values have more effect on the elastic character of the rocks than larger values. A porous rock buried at appreciable depth and retaining a high porosity value has a strong frame and a high value for its rock frame bulk modulus. The porosity effect in this case will be small. The magnitude of porosity can be effective only if the rock has a relatively low value for its rock-frame bulk modulus. Highly porous, shallow sandstone, exhibit low velocity, not only because of high porosity but also by the low value for the rock-frame bulk modulus. On the other hand, if the value of the porosity is fixed and the P-wave velocity varied, the rock-frame bulk modulus constantly increases with increasing brine-saturated sand velocity. Mo~t 06 the heali~tic*~edimentahy hock~ ahe placed neah the vicinity 06 the Wyllie time-avehage equation. Jn thi~ hegion, the hock 6hame-bulk modulu~ i~ mohe dihectly helated to the P-wave velocity than to poho~ity. Thu~, it ~hould be expected that the pohe-6luid e66ect will dechea~ a~ the bhine-~atuhated velocity inchea~e~, independent 06 poho~ity. *hock~ with value~ 06 poho~ity and P-wave velocity that exi~t in natuhe. POROSITY .40 .34 .28 .22 .16 .10 .04 5. N E u ....... .,, .. c: >­ "'O 4. 0 ""'o - (/) ::::> ...J ::::> 3. 0 0 :::lE :.: ...J ::::> CD 2. w :::lE ....... 0 w E 0 0 w (X) ~ IO > ­ ~ > Cp = 3000 m/s ... •... 0 E .. ,. () 0 ... ?:: .c 0 .c 0 ... Q. ... z 0 N 0 ..... !! ..J c ... a: z :::> ..." 0 c : ... " () () 0 0 c o. L-~~~.i....--1~~_._~~~.....~~~~.-.~~...i..~~~~~.....1 2.00 2.20 2.40 2.60 3 DENSITY OF BRINE SANDlc;ir/cm) Figure 3.13. Rock frame bulk modulus versus density or porosity assuming a fixed value for velocity. ’ = .25 zl 21 .... ~ E (lj , E 0 ........ "' G> c >­ "O 20. 0 -o (/) :::> ...J :::> 0 0 ::!! ::.:: ...J :::> ID 10. LiJ ::!! ct a:: LL.. ::.:: (.) 0 a:: 0.0 _________________, 2000 3000 4000 5000 BRINE SATURATED SAND VELOCITY (m/sl Figure 3.14. Rock frame bulk modulus versus brine saturated sand velocity assuming a fixed value for porosity. 3.4.5 Definition of realistic zone for velocity versus density for reservoir rocks In Figure 3.15 an attempt was made to define areas where sedimentary rocks with different density or porosity and P-wave velocity eventually can be plotted. The limits between the areas are veryuncertain and they probably cannot be well defined since they partially overlap. A large number of values is necessary to improve the proposed diagram. The rocks placed above the Wyllie equation line are affected more by the pore fluids and show a higher fluid-contact reflectivity. 3.5 USE OF GASSMANN'S EQUATION TO PREDICT GENERAL MAGNITUDE OF FLUID-CONTACT REFLECTIVITY Assuming ~ as a subscript that represents a sand that contains a given mixture of fluid, the intent is to calculate the P-wave velocity of this sand. Subsequently, this value will be used to calculate the contact reflectivity with the same sand filled 100 percent with brine. If the density and velocity of the 100 percent brine-saturated sand are knowi, and other values for rock 2.60 2.50 ,;; E 2.40 ~ ... "' >­ f­ - (/) z 2.30 I.I.I 0 2.20 2.10 2 .00 03 09 16 >­ f­ (/) 0 a: 22 0 c.. 28 34 _._ __. .._______.______.._____. 40 ~---_.__ _ ____ 2000 2500 3000 3500 4000 4500 5000 BRINE SATURATED P/WAVE VELOCITY (m/s) Figure 3.15. Porosity or density versus brine-saturated P-wave velocity graph showing the areas where different sedimentary rocks can be tentatively plotted. matrix and fluids can be assumed, the sand P-wave velocity containing a mixture of fluid can be calculated using the Gassmann' s equations. The P-wave velocity will be given by: 1/2 Vpx = (Mx/px) (3.19) PX = (1 -~) pm + ~pmix (3.20) pmix = P2a + pi(l a) (3.21) where: pmix = density of fluid mixture pl = density of fluid 1 P2 = density of fluid 2 a = percentage of each fluid in the mixture Mx, the P-wave modulus, is given by the White's formula 3.15 where: Mr = Kr + 4 ΅ (3.22) --r and, Kr = (K(Km + Q) -Km Q)/Km (3.23) Q is given by the equation 3.8 and: K = M -4 (3. 24) --r ΅ ΅ = Vs 2 PS (3.25) M = Vp2 p (3.26) The values of P-wave velocity and density can be taken from sonic and bulk density logs. Values for bulk modulus and densities for rock matrix and fluids are assumed from graphs and tables on related literatures (see Chapter 3.4). It is also necessary to know the value of the Poisson's ratio, that is generally not available,and in most cases assumptions must be made. Assuming that Possion's ratio of most dry rocks and unconsolidated sands is about .1, Gregory (1977) developed another approach for the same problem as follows. The plane wave modulus of the empty skeleton of the rocks is related to the bulk modulus and Poisson's ratio by: = 3 (1 -Tr ) Kr (3.27) Mr 1 +TT making: R = 3 (1 -Tr) 1 + Tr and substituting in White's formula we have: Mx = R Kr + (1 -~) 2 /( i£ + 1K~ 4 -~d (3. 28) Making y = 1 -Kr/Km and solve for Y it has a second order equation: ay 2 + by + c = 0 (3.29) where: a = R -1 (3.30) b =~ R(Kr/Kf -1) -R + M/Kr (3.31) c = -~ (R -M/Kr) (Kr/Kf -1 ) (3.32) Resolving this equation, Kr will be calculated: Kr = (1 -y) Km (3.33) With White's formula the P-wave velocity of the rocks filled with a mixture of fluid is obtained. The density is calculated taking equations 3.19 and 3.20. The fluid-contact reflectivity will be then calculated by: F.C.R = \Tp P Vpxp x (3.34) vp P - Vpxp x 3.6 IMPORTANCE OF PARAMETERS CONTROLLING FLUID­CONTACT REFLECTIVITY Although some parameters used on Gassmann's equations are well knm-m , others must be assumed. These assumptions carry a great number of uncertainties, because they are under depth, pressure and temperature of the subsurface conditions. As will be seen later, some parameters are crucial and others have little effect on the value of the calculated reflectivity. 3.6.1 Effect of Poisson's ratio on the fluid-contact reflectivity Gregory (1977) states that if the value of Poisson's ratio was assumed for the empty rock the calculated value of the P-wave velocity of the fluid-mixed saturated sand will be relatively accurate. How do the Poisson's ratio values affect the calculated fluid-contact reflectivity ? Figures 3.16 and 3.17 show the variation of the fluid-contact reflectivity for several values of the Poisson's ratio. The four solid curves correspond to calculations considering the saturation of hydrocarbons equal to S percent and 80 percent and the P-wave velocity of 100 percent brine-saturated sand equal to 2200 and 3000 meters per second. The greatest error (15%) occurs on the curve corresponding to the velocity of 3000 meters per second for the oil case and in other cases errors of S percent or less occur. Thus, we can justify the use of a fairly arbitrary assumption regarding Poisson's ratio in subsequent calculations. I I T I .... - >­ .30 - Sg = 80% - V = 2 200 m/s ­.... -: I­ (.) .... ­ _J u.. .... - I I I I .00 I­ - > ..... I­ (.) ..... UJ _J ... u.. .20 ,_ UJ er V = 2 200 m/s - --- - Sg = 5 °/o .10 Figure 3.16. .15 .20 POISSON'S Fluid contact ratio for gas .25 .30 .35 RATIO (dry rock reflectivity versus Poisson's saturated sand. .20 >­ I­ > .l5 I­ (.) UJ ..J u.. w a: .10 I­ (.) ..J u.. .00 So= 800/o V: 2200 m/s s 0 = 80% S 0 ::: 5 O/o V: 2200 m/s S0::: 5 O/o V = 3000 m/s .10 .15 .20 . 25 .30 .35 POISSON'S RAT I 0 ( dry rock l Figure 3.17. Fluid contact reflectivity versus Poissons's ratio for oil saturated sand. The assumptions used are: density of grain matrix = 2.65 gr/cm3 density of oil = . 78 and .74 gr/cm3 density of gas = . 0 2 and .16 gr/cm3 density of brine = 1. 09 gr/cm3 bulk modulus of grain matrix = 40 x 1010dynes/an2 bulk modulus of oil = .09 and .48 x lo10dynes/an2 bulk modulus of gas = 6.28 and 38 x 10 7 dynes/an2 bulk modulus of brine = 2.18 and 2.4 x lo10dynes/an2 porosity = .35 and .25 3.6.2 Brine saturated rock velocity and density­porosity versus fluid-contact reflectivity Figures 3.18 and 3.19 were computed using Gassrnann's equations and common values for matrix and fluid properties. A fixed porosity was assumed in the case of brine-saturated sand velocity versus fluid-contact reflectivity. In the same way, a fixed porosity value was assigned for the brine­saturated density versus fluid-contact reflectivity. The dashed vertical lines represent, where normal compacted rocks occur, the Wyllie time-average equation. A matrix velocity of 5800 meters per second was assumed in both cases. For all hydrocarbon saturation, the fluid-contact reflectivity shows almost no variation in the field occupied by the normal compacted rocks on the Figure 3.19. On the other Figure, 3.18, the reflectivity keeps increasing with decreasing P-wave velocity of brine-saturated sand. These behaviors are expected if the role played by the rock-frame bulk modulus is well understoo~ The small variations in the rock-frame bulk modulus for normal compacted rock, shown in Figure 3.13, is reflected on the fluid-contact reflectivity in Figure 3.19. The constant increase of the rock-frame bulk modulus in Figure 3.14 is shown in Figure 3.18 by the constant decrease of the fluid-contact reflectivity value. From the above conclusions, it can be postulated that for most rocks,po~o~ity value~ a~e not ~o irnpo~tant 60~ p~ediction 06 the 6luid-contact ~e6lectivity.Knowing the lithology, the 6luid-contact ~e6lectivity can be e~tirnated 6~orn the b~ine-~atu~ated velocity alone. 3.6.3 Effect of fluid properties on the fluid­contact reflectivity As was already noted, the chemical composition and subsurface conditions have a great effect on the properties of the fluids. Among fluid properties that affect the fluid-contact reflectivity, bulk modulus is the most important. 0 0 0 0 0 0 <:: IC) CD e>i N N r.i C\i DE N S IT Y OF BRINE -SATURATED Sd (gr/cm3) 0 v ,., v ~I ol 00 :: 1 ~I ·I !1 !1 ~I .30 ~I ~, >­w I­ ... > ..J ~I I­ (.) w ..J ..... w I a: .20 I I­ (.) I .10 ..J ..... j I __ I_ 5%_ p 0 R 0 s I T CXl C\J CD N C\J y v 0 0 ... 0"' 0 Figure 3.19. Density of brine saturated sand versus fluid contact reflectivity assuming a fixed value for P-wave velocity. How does the wide range of values shown by oil and gas in Figure 3.5 and 3.6 affect the calculated fluid-contact reflectivity ? In Figure 3.20 at each pair of values of P-wave brine-saturated velocity and bulk modulus of the fluid, the corresponding value of the fluid-contact reflectivity was calculated. Lines were then drawn linking reflecti"\li.ty points of the same values. Bulk modulus values range from light gas to heavy oil. For the gas there is little effect regardless of its specific gravity. Consequently, it can be assumed that the type of the gas has little effect on the fluid-contact reflectivity. Heavy oil has a bulk modulus near the value of the brine-bulk modulus. The total bulk modulus of the oil-saturated rock will not be affected significantly, resulting in a very low value for the fluid-contact reflectivity. Condensate or light oil, on the other hand, may exhibit values for fluid-contact reflectivity almost as large as gas. It is interesting to consider that oil behaves differently than gas or brine, i.e., decreasing its bulk modulus with depth For this re ason, at reasonable depth, light oil can give a "bright spot" in the same way as gas does. The expected fluid-contact reflectivity is plotted against observed brine saturated P-wave velocity in Figure 3.21. Four hydrocarbon assumptions which cover the reasonably expected range of hydrocarbon compressibility were made. For a given brine-saturated P-wave velocity, heavy and light gas (bulk-modulus ranging from 2.0109dynes/cm2 to 5.0 x 10 7dynes/cm2) present small differences on the value of the expected fluid-contact reflectivity. On the other hand, the variation given for oil is very large. For low values of velocities the magnitude of the fluid-contact reflectivity for heavy oil is less than one tenth of the value for light oil. 58 .. ....... e 0 z < "' 0 .... ..... < a: :::i ..... < "' .... z - a: CD "­ 0 >­ ..... - <..) 0 ..J .... > .... > < !I: "' 6000 5500 5000 4500 4000 3500 3000 2500 2000 107 108 10 9 1010 BULK MODULUS OF HYDROCARBON FLUIDS (dynes/cm~) Figure 3.20. Fluid contact reflectivity as a function of brine saturated P-wave velocity and bulk modulus of the saturating hydrocarbons. ..... (..) < ..... z 0 (..) 0 :::> ..J I.I.. 0 UJ ..... (..) UJ Q. >­ UJ 0 0 0 "' BRINE SATURATED P -WAVE VELOCITY (m/s) Figure 3.21. Expected fluid-contact reflectivity against brine-saturated P-wave velocity for different situations which cover the reasonably range of hydrocarbon compressibility. CHAPTER 4 -PREDICTION OF FLUID-CONTACT REFLECTIVITY As was already mentioned, by knowing some pro­perty values and the lithology, it will be possible, using Gassmann's equations, to predict the fluid­contact reflectivity. Graphs derived from these calculations are presented in Figures 4.1, 4.2, and 4.3. Table 4.1 shows the values that were used in the calculation of these graphs. The parameters chosen are average values. The oil parameter, as one can verify in Figure 3.20, reflects the condition of a high API or a very light oil. 4.1 FLUID-CONTACT REFLECTIVITY VERSUS RESERVOIR TYPES Figure 4.1 shows the behavior of the total bulk modulus of a sandstone, buried at depth of 600, 1800 and 3000 meters, when different amounts of gas or oil are replaced by salt water in its pores. In the case of gas sand, the bulk modulus remains almost the same, until the last amount of gas, 5 to 10 percent , is replaced. Then, a TABLE 4.1 PARAMETERS USED TO PERFORM GASSMANN'S EQUATION CALCULATIONS SANDSTONE CARBONATE 600 m 1800 m 3000 m 600 m 1800 m 3000 m Density matrix ( gr/crn3) 2.65 2.65 2.65 2. 71 2. 71 2. 71 Density oil (gr/crn3) . 78 .75 .74 .78 .75 . 74 Density gas (gr/cm3) .02 .10 .16 .02 .10 .16 Density brine ( gr/crn3) 1.09 1.09 1.08 1.09 1.09 1.08 Bulk mcdulus matrix (x1010dynes/cm2) 40. 40. 40. 67 67 67 Bulk modulus oil (x1010dynes/cm2) .985 .670 .480 .985 . 6 70 .480 Bulk modulus gas (xlO 1 O dynes/cm2) .00628 0208 038 .Offi28 .0 20 8 .038 Bulk modulus brine (x1010dynes/cm2) 2.18 2.38 2.40 2.18 2.38 2.40 Poisson's ratio (dry) .10 .10 .10 .25 .25 .25 Porosity .35 .30 .25 .20 .15 .10 P-wave velocity Cm/sec) 2000 2500 3200 3600 4000 4600 very abrupt change occurs. Therefore, a small amount of gas say 5 percent, can change drastically the elastic property of a sandstone reservoir. The bulk modulus of oil, on the other hand, increases continously as brine saturation increases.There­fore, a high value of oil saturation is required to produce a large change in the elastic properties of the whole sandstone. How does this elastic behavior affect the value of the longitudinal wave velocity ? Figure 4.2 shows the P-wave velocity plotted against water saturation. The large drop of the bulk modulus causes the P-wave velocity to show the same behavior when there is a small amount of gas in the rock. After the initial large decrease, the curves show a linear increase as gas saturation increases due to the fact that bulk-modulus curve remains almost horizontal and the bulk density keeps dropping, as gas saturation increases. The oil curves continuously decrease while varying the water saturation from 1.0 to 0.0. Finally, in Figure 4.3, the fluid-contact reflectivity plotted against brine saturation, clearly shows that a small percent of gas can change the elastic property of the sandstone at such extent that only 5 percent of gas saturation will be necessary to achieve 7/10 of the value of the fluid-contact reflectivity for the completed saturated rock, regardless of the buried depth. For oil, the value of the fluid-contact reflectivity is not as large as for gas and behaves more linearly than gas does. The abnormality exhibited by oil is due to the anomalous behavior of the oil compressibility.Depending on oil saturation, a deeply buried sandstone can give a greate fluid-contact reflectivity than a shallow one, as is shown in the case of the curves for 600 and 1800 meters depth. All the curves (mainly gas curves) present values greater than the common lithologic background reflectivity and will produce a very marked anomalous amplitude. Backus and Chen (1976) consider .04 to .06 to be a good value for the lithologic background reflectivities. A carbonate case is shown in Figure 4.3. The carbonate behaves the same as sandstone, except that the reflectivity effects are less. The magnitude of the fluid-contact reflectivity in this case is relatively small and is usually less than the background lithologic reflectivities. 14 12 2 0 x N. 10 E u ........ Ill ., c >. 8. "O Cf) :::> ..J 6. :::> Cl 0 ~ ::.:: 4. ..J :::> lil 2. --- OIL SA ND -GAS SAND / 3000 m - - - - - 1800 m 600m BRINE SATURATION Figure 4.1 -Bulk modulus of a sandstone as a function of brine saturation and depth. 3200 2900 ..<.> fl! ...... 2600 E >­ I­ 2300 u 0 ...J UJ > 2000 UJ > ­ ..... > 1­ u .2 I.LI _, ~ I.LI a:: 1­ u ct 1­ z 0 ...... u . 1 ..... ...... 0 ..... ­ - BRINE SATURATION Figure 4.3 -Fluid-contact reflectivity vari ation in sandstone a nd carbonate rocks as a function of hri ne saturation and depth. 4.2 PREDICTION OF FLUID-CONTACT REFLECTIVI1Y ON VELOCI1Y VERSUS DENSI1Y GRAPH As was already mentioned in Chapter 3, knowing the P-wave velocity of brine saturated rock and the density or porosity, it is possible to estimate the fluid-contact reflectivity. Figures 4.4 and 4.5 show exactly how this can be accomplished. These figures were calculated using the same data given in Table 4.1 but the reflectivity was assigned for each pair of values of P-wave velocity and porosity. The gas and oil saturation was chosen to be 80 percent but any other saturation can be tried. Again, in the vicinity of the Wyllie time average equation the reflectivity contour lines are almost parallel to the porosity axis. The value of the fluid-contact reflectivity-therefore, is not so dependent on the pores i ty value in this zone. The refore, the. 6.tui.d-c.on:tac;t ne.6.fe.cil­ vdy c.an be. eo:t<.ma;te.d 6nom the. P-wave. ve..toc.J...:ty 6on a b!U.ne. ,t,a;tWz.a;te.d -6 and a.tone.. Q. w .28 2.20 2.00 L-....l...-.....L.---'--l...-..l---~-J.----...Jo---....Jio..-'8....____-:o .40 § g g 8 00 ~ 8 N ~ ~ ~ v V ~ p WAVE VELOC I TY OF BRINE SATURATED SAND (m/s) Figure 4.4 -Fluid-contact reflectivity for an 80% gas saturated sand as a function of density and brine-saturated P-wave velocity. (/) >­ I­ CZ: 2.30 .22 P-W AV E VELO CIT Y OF BRINE SATURATED SAND ( m Is l Figure 4.5 -Fluid-contact reflectivity for a 80% oil saturated sand as a function of density, porosity and brine-saturated P-wave velocity. 4.3 GENERALIZATIONS ON FLUID CONTACT REFLECTIVITY IN RESERVOIR ROCKS IN GENERAL-MAJOR CONCLUSIONS The magnitude of fluid-contact reflectivity is directly related to how the fluid can affect the elastic property of the rocks. The capacity of a fluid to affect the elasticity of the rocks is related primarily to the rock-frame bulk modulus and to the bulk modulus of the fluid. Porosity values influence the fluid-contact reflectivity value only if the rock has a low value for the rock-frame bulk modulus. If two different sandstone have the same velocity, the one with lower porosity will present a higher value for fluid-contact reflectivity. Depending on the rock-frame bulk modulus, low to medium porosity values for unconsolidated sandstone can give fluid-contact reflectivity value in the same range as does bigly porous sandstone. Unconsolidated sedimentary rocks occur in the zone above the curve given by Wyllie time-average equation on the P-wave brine-saturated rock velocity versus density or porosity. This zone is the most favorable to produce "bright spots". A 5 percent gas saturation can modify the elastic properties of the whole rock to such· an extent that fluid~ contact reflectivity will be as much as 7/10 of the value if the rock were 100 percent saturated. This is a limitation to "bright spots" exploration method because makes a non-corrnnercial reservoir as detectable as a ·commercial one. The saturation effect on the elastic properties of the rock do not depend on the gas properties; i.e., if the rock properties are appropriate, a "bright spot" will be produced with any type of gas. For the oil case, only light oil or condensate has the property to give easily detectable values for fluid-con~act reflectivity and consequently needs high values of saturation. The structural condition of the sendimentary rocks or the rock-frame bulk modulus value is more directly related to the brine saturated P-wave velocity. For this reason, fluid-contact reflectivity may be accurately estimated from this value, given by well surveys. CHAPTER 5 -OFFSHORE AREA ONE -PREDICTION OF FLUID-CONTACT REFLECTIVITY Offshore Area One contains a young elastic section. For this area, data for five wells and a series of 31 seismic lines are available. The lines and wells are located on Figure 5.1. The data show a succession of alternating layers of shales and sandstones, of Tertiary age, that are probably unconsolidated. Values of the brine saturated P-wave velocity versus depth for sandstone present in three wells are plotted on Figure 5.2, and the data from two wells were used to graph the density of the brine-saturated sandstone curve in Figure 5.3. Solid curves, representing a visual fit of P-wave velocity and bulk density versus depth, were traced. From these curves values were taken for constructing the Wyllie time-average equation on both graphs. Wyllie's curve on Figure 5.2 was calculated from porosity value given by the average curve density on Figure 5.3 and vice-versa. Matrix and fluid density and velocity were estimated to be 2.65 gr/ cm, 1.0 gr/cm3, 1500 m/s and 5800 m/s, respectively. N • N • 0 • 0 N • 0 • • • • 0 0 • • N 0 •• • • 0 0 • N 0 0 N 0 0 0 • • • ... 0 0 0 0 • 0 0 0 • 0 • 0 0 • • 0 0 • WEl.L-3· 0 0 0 • 0 • • 0 0 • .• • , 0 ••• • 0 ~O..· ·· ·OO •o-... 0 ••• 0 0 ... ..• . 0 ··­ 0 0 0 : WELL·( 0 0 0 0 2• .. 00 •o,.. •• 0 0 .. 0 . • .• 0 .. ..,. ... ... ! 0 . Yt'ELL-2 ". 6 • 0 0 .. 0 : • •.• ... 0 .. . 0 •.o. 0 .-.. ·. 0 .• eo . ... .·. 0 .• • . .... . 0 . .• . .o) 0 0 4 0. • 0 o~. 00 . ... • . .o . 0 ·o · o ·· · ·.n •. 0 0 • •· • o D • ••• o ..•! .o. 0 ·. •.....·.." •• 0 0 I> . 0 •.· .. 0 : . 0 0 0 .·. • 0. • ·5 0 0 o WEU.-8 • • • • 0 0 0 • 0 6 0 .• Do • 0 0 0 ·O. . .. 0 •. • •, • O •O• • •..•. 0 ..•. • 0 p 0 •• 0 0 0 0 00 • • • 0 0 0 0 • .• 0 0 •••• 8 .o. . ·•. 0 .. .... 0 0. . •· 0 •: ·7 0 0 0 ~ . yO. . .. 0: 0 • • 0 0 " 0: 0 ..· 0 • 0 7 0 WELl.44o . . ~ . .. .. ... 0 0 b • 0 .. • ... -~ . ... • 0 . ••• . o 'o. ·.. o .. • o o.. . .. ' • • 0 0 0 0 e WELL-.4 ' O' \ • .•.... 0 8 ·•. · 0 • 0 .. I. .... ... ~ . 0 0 0 · . • • • . .. '0 • 0. 0. ·o0 0 0 .• " • 10 · 3. .o. ..• 0 O· 0· •.• 0 '0. ... 0 .. 0 ... .. 0 • 0 • 0 • 0 • 0 • • • • • ..·~· ..·. ..•. ·• 0 • • • • • • • 0 = ~ ;; .. N ... ;; • • 0 ... • ...•• • • ...• • • • ~ ... !! ...• I I Km FIGURE 5.1 Seismic lines and well locations on Offhore Area One. From these figures it is clearly evident that above 9000 ft depth, the sands do not follow the Wyllie time­average equation. They display lower values on the brine­saturated P-wave velocity, a behavior that is proper for unconsolidated rocks. On the graph of bulk density versus brine saturated P-wave velocity (Figure 5.4) these unconsolidated sandstones occupy the area immediately above the Wyllie time-average equation. Designated as unconsolidated sandstone zone in Figure 3.15. For these unconsolidated sandstones conspicuous decreasing on its P-wave velocity can be expected when saturated with gas or light oil. For offshore Area One, at depth of the order of 2000 meters, some gas saturated sandstones generally present P-wave velocities with values 10 percent lower when brine saturated. For greater depth, the velocity variation , when presented, is of the order 5 percent. There is no available data on velocities for shallow gas sand , but they should exhibit a very large variation since the sands are still less consolidated. For oil-saturated sandstone, a reduction on the velocity is not readily detectable from the sonic log. A decrease of 8 percent is evident in one reservoir,although this could be caused by lithologic variation. p D E T H (m) 0 0 0 0 0 0 0 0 q 0 q 0 0 (\J ro ­ ~ ’ I­ (.) 0 s 0 ..J II.I >­ > I­ 0 (.) 0 II.I an 0 rc'i > ..J 8 ct II.I 0 3: > c:i I Q. II.I > ct 0 0 3: 0 I 0 8 oi 0 II.I rc'i I­ Q. ct 0 IX II.I I­ ::::> 0 0 I- ct 0 IX a) c:r (/) ::::> 0 I­ 0 ct IO Cf) C\i LLJ 0 0 z 0 ~ II.I a:: z Ill a:: c:o 0 0 0 0 00 w C\i • 0 8 0 0 0 0 0 0 0 0 0 0 0 0 '° 0 0 0 0 0 q (\J c-.i v ID ex> ci D E p T H ( ft ) Figure 5. 2 -P-wave velocity for brine saturated sandstone of Offshore Area One plotted against depth. p 0 E T H Im) 0 00 0 0 0 0 0 0 0 0 I() 0 I() Q 1£? N (\j 0 ~ C\J • • "' E (.) ' .... Cl 0 ,.., C\i >­ I­ 0 ~ Cf) C\J z UJ 0 0 C\J ~ ...J ::::> ID 0 0 C\J 0 CJ) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 ,.._ N LO D ( f e E't l Figure 5.3 -Density values for brine saturated sandstone of Offshore Area One plotted against depth. BULK DENSITY 2.00 2.10 2.20 2.30 2.40 250 2.60 2000 • 2500 • > !:: (.) 0 ...J • w 3000 • > • w > • I )'I • • ~ 0. ..,~ • •• • • • 3500 0 ~" ~ • w .~~ . I­ • • • IS"~ •• < 0:: • • • • :::> ~" •• I­ • "11>. • • < Cf) 4000 "'o 1' w z a:: ID 4500 sooo~~~~_._~~~~...._~~~--',......~~~.....1.-~~~~1----..1.~~-'-~--' .39 .33 .27 .21 .15 .09 .03 POROSITY Figure 5.4 -Offshore Area One brine-saturated reservoir rock properties on velocity versus density curve characterization. S.l RESERVOIR OF OFFSHORE AREA ONE Two producing wells, numbered 1 and 4, were chosen to study the reservoiIS of Offshore Area One. Producing intervals are logged on Figure S.S. Each porous sand in the interval is numbered and the numbers are not correlated in well 1 and 4. Some of the properties of the oil and gas reservoirs are tabulated in Table S.1 and S.2. The corresponding points on the predicted fluid­contact reflectivity graph are given in Figures S.6 and S.7. An 80 percent saturation for oil and gas is assumed. In young basins, where the sediments are still unconsolidated, a very low average background lithologic reflectivity could be expected. Individual sands and shales, of course, are not average and the lithologic background reflectivity would be larg~than the average property. Backus and Chen (197S) estimated that ''a reasonable representation of the young sand/shales reflection would be closer to R = .OS rather than the very low values based on average properties." They pointed out three requirements that are important in order to recognize a reflection from the fluid contact, in the presence of noise and lithologic reflections: first, the strength of the target; second, the strength of the noise and the coherent rock-reflection background; and third, the thickness of the saturated reservoir. If we take the .OS value for background lithologic reflectivity as a reference, the shallower reservoirs, with potential fluid-contact reflectivity values of .12 and . 09 would be re latively easy targets. The reflectivities have sufficient magnitude to be distinguished from the lithologic background reflectivity. The deeper reservoir will be detectable if, in the zone of ocurrence, the lithologic reflectivities have lower values. For the third requirement, the sandstone reservoirs present a variation from 4 meters to 28 meters in thickness, corresponding in time from 3 milliseconds to 2 7 milliseconds. The structural dip of the layer is another consideration. The dip should be gentle to provide an areal extent for the fluid-contact interface to be picked up by a relatively large number of seismic traces. TABLE S.l MAIN RESERVOIRS OF THE PRODUCING INTERVALS FROM WELL-1 OFFSHORE AREA ONE Brine saturated Predicted Reservoir P-wave velocity (m/s) Hydrocarbon Fluid Porosity Fluid-contact Reflectivity 1-1 2770 .27 .11 1-2 2700 .28 .12 1-3 3100 Gas .2S .09 1-S 30SO .26 .09 1-6 3130 .2S .09 1-8 3050 •27 .09 1-10 3300 .20 .08 1-11-12 30SO Gas .22 .09 1-14 3300 Gas .22 .08 1-15 3S80 .19 .07 1-16 34SO Oil .21 .04 1-18 3SSO .21 .06 1-20 3590 .19 .OS 1-22 3660 Gas .14 .07 1-25 3810 .17 .OS 1-28 3960 .18 .04 1-29 3960 .13 .05 1-30 3800 Gas .16 .06 1-31 3800 Gas .16 .OS 1-34 3960 Gas .lS .OS l-3S 3960 Gas .lS .OS TABLE S.2 MAIN RESERVOIRS OF THE PRODUCING INTERVALS FROM WELL-4 OFFSHORE AREA ONE Brine saturated Predicted Reservoir P-wave velocity (m/s) Hydrocarbon Fluid Porosity Fluid-contact Reflectivity 4-1 30SO .30 .09 4-2 30SO Oil .30 .06 4-3 2990 .27 .10 4-4 2960 . 30 .10 4-6 3200 .2S .08 4-7 3600 Gas .22 .06 4-8 3313 Gas .24 .07 4-9 3300 Gas/Oil .24 .OS-.07 4-11 3142 Gas/Oil .22 . 06-. 08 4-12 3400 Gas/Oil .24 .04-.07 4-13 3460 Oil .19 .04 4-14 33SO Gas .20 .08 4-lS 3S20 Gas .20 .07 4-16 3620 Gas .19 .06 4-17 3620 Gas .18 .06 4-18 3700 Gas .19 .OS 4-20 3850 Gas .18 .OS 4-23 3930 Gas .16 .04 4-25 4030 Gas .22 .04 Figure 5.5 -Lithologic log of producing intervals from well-1 and "'ell -L1. WELL-1 1.4­ .............-: ...-.::·..._. 4 775 :::.".· :.. :·:.'<·> -5'000 ~-----­ 1-1 <\ .·:·: ·:::: :..:-:·: :"<:: ...... ..... . 1.6-... -~... -:-::.....-:-:: ...:-;:.. ..... .. ,... .. ... 6000 ..;...:.·..,.:.,·.-:~·~. i ­ - pzz~~t-i '1 1.8 ---=-=-=-= w ::.:.:.:_:_ ·.': ......... :... :_:_::_. -7000 ..._.. .. .. . .... . r1=e·~~~~-,_, 'f' z .. :·...·. ·. : .:.. : 0 ... . ... .. w I­ 2.0-:..:..:. .-·:.:.:_ ".:..:.: .. 8000 0 (.) ...... .. .... .. . .. ...... -1.(.. w ..J . . ·. ·... · ... ... :. : Li.. ·.·. ·: . .. : ::.. :... : w 2 .1 _ _p._ "'i._ .:....z-=c..~.. ·""'· ·""· ~.. _-;=._?f._ t-8 500 er: L___----• .. .... .: '. ·: ~~~~9000 ~ /-7d 2.2~~~~~~ I > ·.·. ·,·.·.'· .. ~ I 2.7 WELL-4 <..> J; w :::!; I­ 1.90 ~~!lil!!.li~7 3 70 z 0 I­ (...) w ..J Li.. w er: - :I: I­ ~GAS SAND OIL SAND 2.50 2.40 > I­ 4-211 2.30 • fl) z LL.I 2.20 2.10 .03 .09 .16 > I- Cf) 0 .22 It: 0 Cl. .28 .34 2.00'--~~~--L~--L--L~-'-~~~...__._~~~--'........~~--'..........~~~---'.40 2000 2500 P-WAVE 3000 VELOCITY 3500 OF BRINE 4000 SATURATED 4500 SAND 5000 FIGURE 5.6 - Prediction oreflectivity reservoirs of Offshore considering f the fluid-contact for the producing gas Area One, an 80% of gas saturation. 2 .60 .03 .09 2.50 >­ fl) I­ - 0 I.fl 2.30 . 21. a: z 0 0 ii. UJ P-WAVE VELOCITY OF BRINE SATURATED SAND FIGURE 5.7 -Prediction of the fluid contact reflectivity for the producing oil reservoirs of Offshore Area One considering an 80% of oil saturation. CHAPTER 6 -SEISMIC DATA FROM OFFSHORE AREA ONE The seismic reflection exploration method provides excellent data for Offshore Area One. The quality of the data is shown in the lines given in Figures 6.1 to 6.6, where six out of 31 lines were presented. A simple four­tracc mix was used to reduce the number of traces and to increase the vertical exageration on these sections. An interpretation was attempted by following three selected reflectors all over the area. They appear in solid lines on the displayed seismic sections. Growth faults cut the area and constitute the main structural feature for trapping the hydrocarbons, either by "roll-over' structures, or up dip entrapment against the fault. The most striking feature on these sections is the amplitude enhancement of the seismic signal that occurs in several horizons within the boxed areas. The time structural map of these three horizons, all over the area, are presented in the appendixes A, B and C. The producing structure marked on lines 12 and 15 was penetrated by well 1, which was logged in time scale corresponding to the seismic section, and projected along the contour line on Figure 6.10 (line 15). Well 4 drills the structure outlined on Figure 6.6 and is logged and projected along the contour line in Figures 6.8 and 6.11, lines 9 and 27, respectively. Depending on the areal extent, the interface of brine-gas or brine-oil will produce different seismic behavior and the flat reflector given by this interface can be recognizable or not. The presence of hydrocarbon can be recognized on seismic lines by two different features known by "flat spot" and "bright spot" . Both of these features are perfectly seen on our seismic lines. Each of the reservoirswill be discussed in the next chapter, but we would like to call attention to two shallow "flat spots", shown by the arrows, in the center of the Figure 6. 7 at 1240 milliseconds and 1380 milliseconds. They constitute a very nice example of "flat spots" -limited in areal extent; unconformable with surrounding rock reflections; and mapped in the same time on other lines. Line 12 (Figure 6.9) is normal to line 4 and picks up these reflectors at the same level on the time scale. We do not have data dealing precisely with these reservoirs because they are not producing at the well location. They are represented in the well by two brine­saturated sands. The shallow sand has a thickness of 24 meters with sonic log velocity of 2650 meter per second. The deep sand, reservoir number 1-lon the log, has a thickness of 36 meters and velocity of 2770 meters per second. Both give an estimated fluid-contact reflectivity of about .12, wich is as strong as the surrounding rock reflectivities. On these reservoirs the pay thickness of the gas should be enough to produce a recognizable fluid­contact reflection.A 40 meter thickness, in the middle of the structure, would be assumed for both reservoirs. The flatness appears because the sand is not completely full of gas or oil. Most of other reservoirs are thinner, and the "flat spot" does not appear. When this happens, the reflection will be given by the sandstone-shale interfaces. In this case, the reflection signal will pass from a modest reflection to a bright or strong reflection when the saturation zone is reached. However, if the gas sand is thick enough, also constructive interference in the seismic display pass band results, and the reflection signal will appear very bright. Other reflectors appear as strong as the producing sands and must be distinguished from them. Lateral change in the strength of the signal is the most important clue in "bright spot" exploration. Figure 6.12 shows line 15 where static corrections were used to flatten structure, in an attempt to show the change in the amplitude and character of the reflections parallel to the bedding planes. 27 29 31 21236 21 256 t:o~ , 2*ss I. 2i~7o I 21495 21!'1E O. C 0. 0 2 0.1 -~~--~~~~~--~~~~~~~~~~~~~~~ ---------~ 0. 0.2 0. 0 . ~~~·~:m.,~·~~~,~~12~~~~~~~~~:. , .s .:···.:::·::~:;::::·::·;; ;:~:::'.::::;~::··:·::::· '.·::::>~~I;~,:.:·~~.:::::::~;·::::::···...........___,__...........: o.s 0 . 6 :-=='-'~--'·:~::~~:~:~: : ~~~:;; ~ .. ~: :;.;;.:; 0. 0.7 0 . 0 .8 0.8 o. O .~ .0 .0 . I I.! I. 2 .2 .3 .3 ·' ~~~g~~~~:dl· ' _ .:'.'.::'.::::'.'.::~ :'.:'.~~:: ::::~;;~::<~~~~1 .: =~~:.;;;:"-...... . 7 :: ::;:::::·;:.:.. .. •. ~: 5t ::;~:·: .. ::::;;···· ·~:-;:-......... .~:-.8 •: • ·•• · ,:~,,,~ :T~· · ~--= 9 :·n:··~".,,•,,•,.c ~: : ::::::~~;~ ; . ::~; ;::: :: : :: : :::: .: 1~;;~:·· · .: ..:1,.: •.. :::· ::" :: ~::: ..:~ . · :~::: :::" ...._!._ .. . .... . :: : :: : ::::::::: • 2.0 ............ . 0 2. I 2 .( 2.3 2.4 ...... '.::::::::ii ." 2.S . ''• .";;··~ .S .6 :: ::::::::~: ;~i .S 2. 2 3 0 .. .. .• ...... .:~ 3 I 2 3 . : :~:.•.•· . ;. ;::•~i1:):·: ::: ·;-". ~~..-,7'-'---·-'.,....~~:·-~~-... ,.,-'"'<~----~....,....-.--~ : :-:·~;-·: ..-.:-.. : :-·~.~~~:~...,._....,..,..~'°* .. .--~:.-•.7• • . ~:-.~.:-::,.-.,.~-.-.~w.~~-.-.:-'·--.;;;:.. 3.2 .. .. " 1 3 ~· :· .. . ~: ::-·· •, "'.,'. ' ~··· ."•: . :::.::;;~ 3. 3 ·?:: . ... . 3 4 ~ ,• t~. .. ..... , . fi ..::::·~,.''r,, ;:: :;:::·· .;;;, ·::: .. ~;: 3. ·· .. i· .... •.. . : .s ~· ' .S ...... . . 3. ..-"'· -· .. •.;._:""~:'---"-__if:-:.·· .,··""--"-'o-'-'-'-'---·~..·---~-··__ _ ~· ···. . :~··,..·.... .,·.,...::~: : .. ;:: ..,; .... <:: :: ·::::. · . ·:·::~:=~~ 3 ·. 7 _· : ,:_··'-_ .•_:· __-----....~~ :::.,...:':' : ::I'·•• :I,I;::'.,' ''. >,;.·.'·,• ' ~. : .',;' ·'•,."': ;..::::: ::::'. '."::::;;;,; 3 : 6 ::T•_,~:_..._·~•__·: ·~'_~----·::... ·'::-::-.' ::,' ',: 0,,' '.'.' ·1~·'·~·' 10 0 ;. •: o. ' • • • ~; • -• o • '• 1 "I '. :: ' ': '.~ : L:: 3.8 1 .9 r.·• . .. .. ::: :,j~ 3. .9 ···:.. .0 .0 II FIGURE 6 . 1 Seismic section of strike line 2. ll 13 17 19 21 23 25 27 29 31 0 0 . 4 I. I. I I I I I I I I I o. •r" . .. . . . . ..... . . 2 0 . ~:: ~~~·~ ·~=--····· ............ ,, ·· ·~­·· .: 0 . . 5 . 5 0 . 6 0 . 0 . 7 0 . . 8 . 8 . 9 . 9 I. 0 .I .2 .3 .·~·::•.····:·.····::::::::::•.~:·.:::~~~;:f:~~~:~ii! •: I ' 6 -. ·--:····· :l .. . :·:.J: .....: . ::.~~~•.. :::~.:~:::::··· : :" · .... ..:~ . 7 ~-. " ' ""'"""' ·: :::::::~ . 7 . e ;::: ::-:-:~:~;:;::;;;.;;::;: ;:-;:r.:·,.,·~;;-::-::'-'.;=f.::.~t-,...--:-r-,-,~=~' : ~:,:,:,,_·"'""~"~~"c.-'­ : ; · ".;.~: : · ''-c"c!!':-:'·'~· ..7.:...,==·-°E'~:-----.;i,'·i.-i·;;. . • 111 ~~~::··~··'."';.• ~!: ~ ....... ~: .. ~:-=-= .. .. .•;... .. ..... ....... '7> .... .. " " .... • . . 9 · . '·'·'·:t··..·-~;2. 9 ==:::::c::l==.::~~::::~~~§~~==SJ:=:::··-. .........~-· ·· '•1 ···!:. •.::t ............ ......... I .2 .2 .3 .5 2.6 2. ·2 2. 3" ~t' ·:;,1:•0••• '), ,•t''''•oll'•I '••' •,1·,",~':,. ,., • •''' ,:,; ::. ,,, I ' ''1, ,lo•,; ' l' ,,, , ,• : :••:: .~:­ ~~_;,~~...:...,~-.--.~"""'' "~~""'"'..--4.........-'-t--,-~°'--it-..--t~.,-,,~..-~~-.-~~-.---i~~~.....,c:-:::'-,o ~r"~"' _ .0 15 19 23 27 31 ~ FIGURE 6.2 Seismic section of strike l ine 4. II 13 IS !7 19 21 23 2S 27 29 31 I I 1· 1 I. I I I I I I .I I 9 .0 o. j : 0 . .:·:~= ...:::. :·...... :::::::::::::::::.::::::~::::::~::::~:::=::::::~~ . : : ... . . -=· ·.. ..... .. o. : : :: : : •;: •: O, •• • '. • • • :.;..::~: :: ' • • qo 1 •' ,~II • "•':'.: : ::;,.1•': :i' '',, .::; ,;''•: ~ ••.:I,':: ::'.'·~~'.~·:..;: • ' 7:::~~:: ' 1 ' -;;;,;-.;;;;;;;;;------------;;;;o~:t';~<---:-:-:-:~~........;~----"-.....,~~~~'7'.7:c-:7~~-:--~:;-;;-~ .5 .6 .7 .8 • ~ E~:·::·:"··•·••••••::',i~~:::~·;~::::::::~~~~~~:,~. -·' .9 o ~~-......~~-.. ...~.. r. .. ~~..-... . ..~' . ..~~ . . ..~--. ~ -.:-:-·--~.•• .· ..~-.--'­ --.. .. .. --.-~~... ..~..-'-'-'-~'-'-'-'~~~•.~~ .. ---~.~. .. -~..-: :: .::: , /-//.-·~~-"*"'~. .. ---­ 2 1 .. -:-: . . 2 : ::··,,.,..:.:..:'----··~~_... .. ·~: :r. :_::~·__ ··~~:~: .~···~~-·.. ·:__ 1~/_~ -:.~ 2+.'.:~'~-·~·~~-· .:~_ ··~~::_:: .....~~: ··~···~~~-_:: · ·~2. ::~4- .. '~/i:: .__......:.:.:-'-'-­ "''·· . ::::. :· ,. ... ,. . ~ ·., . .,:; ... :~ ,.,,,, ........ ""l"''· . ··/ ··" "' ·~'" " ' 2 .3 ,.::" ·f!··"· . . .... ;;: '>. . .. t:· /" :.·. 2.• .. ~----.~..~ ----~~"-:::~~-'--"'~-""'----.~--"~'-------'=...c.--'---~.. 2.l ~--'-.. .-..- . ~p..-'.~~­ . 5 +."-~---'--~~,..,,...,,..,,.......~~--··~--'---· ~::~-----".~-~~~~---'-'---~.5 · ·._~ -~· . . _=~--'-. · ·· 2.6 ~~~·-·-"-· ·~,,~~-~··-··--'--_Y---,r'-'-''"· · ._~-~---'~ · ··---~·~·"r-····-~ '·~~-~~~------=----'-"-~~-· 2. ~: " ""' ·'• ••''"'~: : : ,*•••' f I '': '~ '" I ,··~:· ,f!,11 11, , ~' "''' I 2 . -'--...:. .'-. --."" . "'-.-'-.,r, ...~=· , -, _...__ _ . =·.:.:..~ ...-........~--~~ ,...'-'-, •.'-'-..""~-.'--'-''-'---.-'. ""---"-'----',"'.,._.~.-'-.-. . . -'-''. 2 . 7 . ,...;,."-~---'-"-'---'-'"--.. ---4-­ ... 7s ''• . ····· · ~···, .. · = ·· ·ff· . 8 -~.~;..~. ~ ..~·. ~=-:_~~~~:-'"'~;;.: ... ._..§..'"'._-_-_-:..;.-_~._.-_:~...;·..,";;.,..··-"--'-_-'_;_-_-_-~-~-...:.·:_;:"-·~·_... .-··~~~~..<;2 . 8 ~ ~ ,..~-~ ~ "' · ~~~~:~:~~~·.--._. --::.:---.__ ..~ --~_-. . :_·~: =-._.-'­ ~•• •1": ,,,. ·,,., :~,,.,, •11 •'' • · .. ~·: '•"I• ~.... ·~ :: ,:,.," • .. :~ 3 o ·~~.~....:..-'-.:;....~......---'---~~~---'---~'---.:.....--.::....----'--~~ .,-'-.:-~~.-.• .. ..:. : .... ,.-.-. -.~.'---' J' '" ,I' ,.;;• " 'l 'll l-f'tt1 '1, I '" " :;..,. _ • ,:!-• tOl\o , .1 :·· ...... . .... :..:.:~:· . ··::· ··· ... .. . ..... ..... . ,·. E'.· ........ -:.·· ·· : ~:c..•'_.,.__' · _· · ..__o··.:...··:_·~:. . 2 _.:,,_•'-'-:·_·_,' ' _. °"· ·~-'----_,_""-.._-' ''"'L,; ''"• -.;,."°'·,.:.c..'~-r··__ ~-_.___· ".:._...••'' . 2 ·:'-.'~",,_••_. _~;Cl..· · · ··'-"'--,..U•,J·~·· "' ''~' __::...·:,:. ~-'---''_' !.:·..·.;' • • ~· ' " ·:·"""': .~~"~" ·'· ··~···· ' I'·• · .3 • 3 . ' .,....,.~----~--~ ""~"~"~·. _,_~_ . ·..:._ ·-=~- . "~--~~..,____...c:_ · . .:..."-'· _, 3.' .· ,·.·.·· · ' . ..... .. .~_• . ' .::!''• ,••" ; ....·•• •. ••·• ·.••.• ;:";. · .. · 3 .•,, ••:...... ' ". . .. ·" ... .. . .5 .-,: it' •', ,• "" '::.:~t" .' :· ,.•, •' ~. I ' :>!,:: ~ ,•' . 6 ---~~ :.::.:..:::;~ ~ . ' •' .., ... ' ' 1, ii, ,. .·: ·:··... . ' ... II 15 19 Z3 27 !I L!.B:Ll FIGURE 6.3 Seismic section of strike line 9. o. ..:.:.;,.: .·.: ::: :: :: .. '""'--·,.;.··;,,.·:,.·-· ..·-~-~,.,..,,____...;........,~-~..:.; .......: ;.: :.:.:: .~; ;:~~;: .;:-··.::~:::~:····=·· . ....::· 1~.... . , : :::·:;..:: .~:: . ·· ·· ···-·· ·········· G. ' :·: ::.. .. ..:. :·'. ·T. ·""'°:··: 0 .5 o o l .0 .1 .2 .3 ~ 5 7 9 .0 I I. t .I I 12 0. = 0. 0. 0 . 0 . S 0. 0 . 0 . 8 0 . . 0 .I ·' . 6 . 7 .8 .9 .0 .2 2. 2.' .S .S .6 . 7 ~ ~ 6 .8 .9 9 .0 .0 3. , .. :.,:;,, .... ·:· ~·~1-1 ;1•J . ~·: .· .. : . ...... ,· ·"°'··· .2 .2 -~: ·,..-:~;·_'~:: ..::;:::::-:~. -· . ... : .....o-'-'.':.:.!': ~: ~ 3 . 3 ... ....... .. ... .. . ·= 0 . .3 , ;:;: l : : " : •• . ~·:,:-... ., . '""' ...... ~. -" ' ' ~ ' ·ii··... ··· FIGURE 6.4 Seismic section of dip line 12. ,'II' ·: ·· .. ,. :..... . ... ' ;. ';•, •. ,, · ,•r •''•'•;:-• . : ::. • '•t ·~~ · ' •• ;,·. :;"'~:.; ' , .· . 6 :1: . ,···· · 1'1: .•• · ::~ · .. ···" ...:..... : .. ~:.· :: ..•:~:!~:. : .... ,...'' .. 3 . ~~:_:-~~~;:· '•ri •' ·'· : ·:. :;·.• ·.'.:'.:·• ;~~.~~.·~ :-----3. e ~:-----:...--· ·-·--.~· ...~::: ::.. ......;, . .:: :: :: ~ --:.::'. ... ·~.~. ~-~. -:· . _·.~J . : ": ... . ... : .........;:,.:::·.;·: . 3, 9 ~,:..:::. ,·.,,.-;---"-t , , ·:··, , ~ •.' ' ••• :, • lo 1 • 3. 9 "<'" . ,.. .. .: ... . .... .. ..:~.; ~ FIGURE 6. 5 Seismic section of dip line 15. I 3 5 7 9 0 .0 .I I I. ~ I .I I I .0 0 _27~-~~~~~~~~~---'"--~~~-;.....~~~---;---'~ 0. ------· :.:.::::::::::....:::::::::::::::-:::·· ...... ··-·. . -· .. ":~·:::::::: : : C. 2 -----0 . 0 ' 0 . 6 0., .s -----..,== 0 . s 0. 0 . . 9 .0 .C --·--- . I .2 1. 3 .3 ·' . 5 .S . 7 :_-·~~~;·::~::.:::~,::. ~:: ::;~ .6 .e .9 . 0 -------,-,.•~,..~..--.:~:~..~..--:.-:-:~~~~...,,..-...-t-""r-,......-L.,j....._..,,....,.f.....-;.;.~,,f-...,.,.,.-;.,.,.,.": :~2 0 •.7~::-.-..-.~.~ :~,,-.~: .",.~:­ -------.::~~:· :~ . ,.~~tiT.,,~,~:·7;:,~..~~ T:~..-----,--'""'E>-_...,,.,,....,.,,~-'i~~~---~...--~-...---:~-·~~;~..~ . :·~.-. 2. 2.6 s :::.. ft::::........... .6 .8 .9 .0 .3 .9 .0 FIGURE 6. 6 Seismic section of dip line 27. FIGURE 6.7 -Line 4 -Enlarged boxed area from Figure 6.2 showing two conspicuous "flat spots". ~-O IL. --GAS Figure 6.8 -line 9 -Enlarged boxed-area from Figure 6.3 showing the "tying" between hydrocarbon reservoirs and the enhancement cf the reflected seismic signals. FIGURE 6.9 -Gas reservoirs on line 12. 6. 5 showing the ''tying" between well -1 gas reservoirs and the enhancement of seismic signals. FIGURE 6.11 -Line 27 -Enlarged boxed-area from Figure 6 .6 showing the ''ty:i ng" between well-4 gas and oil reservoirs and the enhancement of the seism:ic signals. Figure 6.12 -Seismic line 15, flattened by static corrections showing the lateral change of amplitude due to the gas effects. CHAPTER 7 -HYDROCARBON DETECTABILITY ON OFFSHORE AREA ONE -RECONCILIATION OF PREDICTIONS WITH OBSERVATIONS In Chapter 6 reservoirs were located on the seismic lines and discussed, in a general way, how they are tied with the anomalous enhanced amplitude signals. In this chapter the intent is to make a more detailed study, reservoir by reservoir, to compare predictions with observations. 7.1 RESERVOIRS FROM WELL 1 As was already discussed, well-1 presents a series of 35 potential hydrocarbon reservoirs in the producing interval, nine produce gas and one produces oil. Others, although brine saturated at the well location, show seismic evidence of being saturated with hydrocarbons updip from the well (possible gas). An attempt to explain the seismic behavior, reservoir by reservoir was made, but the lack of density logs limited the study, and synthetic models will be necessary to produce a clear explanation of several complicating effects. Each reservoir was tentatively mapped on the reduced seismic sections. These maps are presented with each seismic reservoir discussion. 7.1.1 Reservoir 1.3 Reservoir 1.3 was already an object of detailed study by Backus and Chen (1975) when the flat fluid contact was examined as an exploration objective. The seismic reservoir 3-map is shown in Figure 7.1. Time structure contours show a structural nose with closure ~ against the gro~th fault. A flat unconformable reflector indicating the gas-brine contact was detect on the seismic data (lines 12 and 15 -Figure 6.9 and 6.10). Up structure the reservoir is filled by gas and down structure is filled by brine. The available well logs in the vicinity of reservoir 1.3 are shown in Figure 7.2. The Gamma-ray log shows 43 meters of sand sealed above and below by shales. The resistivity log shows the upper 13 meters to be full of gas at this location. The gas sand has a 7.5 percent lower velocity than the brine sand. FIGURE 7 . 1 -Reservoir 1. 3 map . FIGURE 7.2 -Logs from well l in the vicinity of reservoi r 1 . 3 . Assuming the density values, Backus and Chen (1975) found a fluid-contact reflectivity value of about .08. We predicted the same value in the graph of fluid-contact reflectivity as a function of porosity and brine-saturated sand velocity -Figure 5.6. Figure 7.3 models the reservoir and illustrates the seismic behavior in a synthetic seismogram. The gas-brine reflection strength is about equal the difference between the top gas-sand reflection and the top brine-sand reflection. Backus and Chen (1975) state that "when a polarity reversal is present at the top sand when going from hydrocarbon to brine, the flat-fluid contact reflector has a strength. equal to the sum of the absolute value of the top gas-sand and top brine-sand reflections. When a polarity reversal exists, the flat fluid-contact reflection should be the strongest event in the reservoir reflection sequence." This polarity reversal is perfectly seen on line 15, Figure 6.10. If we follow the top sand event up dip by "phantoming" through the interface zone, we find that the top sand changes to a trough or negative reflection when passes from brine to gas. GAS SAND WEAK .02• Z=SOOO FT OAl RESERVOIR l GOOD .10­ STRONG .so•··--­ Figure 7.3 -Seismic model for reservoir 1.3. From Backus and Chen (1975). A "blooming" or amplitude enhancement exists when the dipping negative top-sand event diverges from the flat positive gas-brine contact event. This "bloom" occurs when the two-way travel time through the gas-sand produces a trough/peak pair tuned to the seismic display pass band. The reflection strength of the fluid-contact reflectivity, although not "bright" on this reservoir, is very strong and is well distinguished from the surrounding lithologic reflections. Results given by the seismic work were expected from the predictions. 7.1.2 Reservoirs 1-7, 1-8 and 1-9 Gamma-ray log shows (Figure 7.4) these three sand bodies (7, 8 and 9) to be 29.0, 4.0 and 16.0 meters thick, respectively. The resisitivity log shows that only reservoir 1-8 contains gas. The value of the brine saturated P-wave velocity on the sonic log in the vicinity was extended to reservoir 1-8 and the fluid-contact reflectivity was estimated to be .08, .09 and .09, respectively, for reservoir 1-7. 1-8 and 1-9.Reservoirs 1-7 and 1-9 on top of the anticlinal structure, show nice "bright spots", interpreted as the result of gas fillings (Figure 6.10). The reservoir maps are shown in Figures 7.5 and 7.6. >­ ...J ..... ..... >­ >--..... <:> ....J t-~ > iii :r "' 2 >-<:> ;::: "' > "' 2 E ... ;;; a: 0 a: z ..... "'u E 0 > 0 -0 2 ...J < IL ;: :IE • a: ...J a: u "' ...J "' "'..... ... ... Ea:: ... ... < a: 0 C> "' z ..... 0 ..... ~ > IL ...: "'a:: ~ 1609 (3200) ,2 1 .08 .10530 1627 1632 .27 .09 1635 2560 9710 1642 .093050 .2.7 10 .000 1652 FIGURE 7. 4 Logs from wel l 1 in the vicinity of reservoirs l. 7 , 1. 8 and 1. 9. ·.wen-3 . . . .. . . ... . ... .•.. ·, .•···· ~ .. .....: .. ....... . ···.··· c.1.= 20ms FIGURE 7.5 Reservoir 1.7 map. .. ......... .. ... ·• .,, C. t.• 20ms FIGURE 7 . 6 Reservoir 1.9 map. The brightness of these reflectors is essentially the result of presence of gas, although some tuning effect should also be computed. The predicted fluid-contact reflectivities for these reflectors were seismically the same for both reservoirs (.08 for reservoir 1-7 and .09 for reservoir 1-9). If reservoir 1-9 appears in the seismic section brighter than reservoir 1-7 is because reservoir 1-9 has greater lithologic reflectivity.Reservoir 1-7 changes from a modest reflector to a strong one and reservoir 1-9 from a good to a very ''bright" reflector. The amplitude enhancement for both traces when it passes from brine to gas sand is the same and corresponds very well with the predicted fluid-contact reflectivity value. Reservoir 1-8 is too thin to be mapped and appears so limited on the seismic section that it may be a localized gas sandbody. In spite of the thickness, the effect of gas is still evident because of the locally weak background reflectivity. However, in Figure 6.10 it is difficult to see because it appears in a few traces with enhaneced troughs, instead of peaks.Figure 7.11 displays the same line 15 with the polarity reversed and reservoir 1-8 appears now more conspicuous. Reservoir 1-8 is located on the downdip side of the structure and the trap may be controlled by an antithetic fault. This fault is suggested by a "break" in the normal dip of the much deeper refJectors. uo The break in the normal dip of the deeper reflectors can be interpreted, also, as a result of "pull down" effect, due to the upper gas sand. In this case, the trapping fault would not exist and the "weakness" on top of the structure would be credited to loss transmission effect through the gas layers. The last interpretation is supported by an enhancement on the other side of the downdip structure. 7.1.3 Reservoir 1-11 Reservoir 1-11 is the brightest reflector on the seismic lines. Its predicted value for the fluid-contact reflectivity is no greater than others but presents a very strong lithologic reflectivity. Figure 7.7 maps the reservoir and Figure 7.8 shows the available data. Gamma-ray log shows a sand 17 meters thick sealed by shales. Resistivity log shows that this reservoir is gas filledA brine -saturated velocity from other nearby sands gives a value for the fluid-contact reflectivity at about .09. Backus and Chen (1975) calculated the reflectivity between shale and brine sand equal to -.01, with an assumed value for density. Gas increases these lithologic reflectivity value by the fluid-contact reflectivity and the reflection interface becomes strong (reflectivity= -.10) for the gas sand-shale interface. The signal of the negative reflection is preserved when we pass from brine to gas and a polarity change does not occur. The fluid contact reflection has insufficient lateral extent to be recognizable and the reflection interface will be between the sealed shales and the gas sand. Reservoir 1-11 is a good reflector until the zone saturated with gas is reached, where it passes from a good to a very "bright" reflector. The maximum pay thickness of gas is about 11 milliseconds and this causes the reflected signals, from botton and top, to be tuned to the frequency of 45 Hz ­the middle of the 20-60 Hz display pass band, on the seismic section. This tuning effect also contributes to give the strong amplitude for this reflector. 7.1.4 Reservoir 1-14 Reservoir 1-14 (Figure 7.9 and Figure 7.10) is a sand layer 17 meters thick completely full of gas at the well location. With the estimated fluid-contact reflectivity of about .08 reservoirl-14should present the same seismic behavior as reservoir 1-11, except not so bright. Reservoir 1-11 and 1-14 have the same thickness. The two-way travel time causes almost the same tuning effect and fluid-contact reflectivities are the same magnitude. Why does reservoir 1-11 appear brighter than reservoir 1-14 on the seismic section ? By tracing the two reservoirs laterally (Figure 7.11) we observe that reservoir 1-11 passes from a -Ot~ong brine sand reflection to a very "bright" gas sand reflection. On the other hand, reservoir 1-14 passes from a we.ak brine sand reflection to a "bright" gas sand reflection. The change. in strength, given by the fluid­contact reflectivity, is very close and in accordance with the predictions. The same schema given for reservoi~ 1-7 and 1-9, between traces for reservoirs that contain gas and those for reservoirs that do not contain would yield almost equal strength anomalies for the two reservoirs. Again, the behaviors described by reservoir 1-11 and 1-14 illustrate the statement (Figure 7.11) given by Backus and Chen (1975) that the. filuid-contact ~e.file.ctivity i-0 given by the. di66e.~e.nce. betwe.e.n the. ~efile.ctivitie.-0 at the. b~ine. -0and and ga-0 -0and at the. top FIGURE 7. 7 -Reservoir 1.11-map 0 0 >-., >-­ ..J I->­ >-..J t-~ .. -0 0 ::c E E .. -E I­ :: u 2 ..J "' ...: er I-"' 0 0 I-... >o er 0.. ll:; ..J z :I 0 "'-...... ._; 2 ..J 0 ... er "' I-I->... .. • ...: 0 0 z er ..: ... 0.. 0 "' ... ~ (31 31) 10.300 6302 1725 (301 7) (1 937) .22 .09 9900 6356 1736 (3200) (1g59) 10.500 1750 6430 (3'144) .16 11 .300 FIGURE 7. 8 Logs from well-1 in the vicinity of reservoirs 1.11 and 1.1 2. v ~ .. I I .. .·.. :.. ·... ·.. ... . . . . . . . .. . : . . .... ~ . . c. 1.=2om1 FIGURE 7.9 -Reservoir 1. 14-map >­ c > ~ " E .. E a: < :i:: > ll> (.) ::; 0 ~ ... 0 ~ 0 (.) < ...J ::;: IL ::; < c: ...J "' ... ...J z 0 ... ll> "' ... 0 .. ~ a:: "' ... ,08 FIGURE 7.10 Logs from we ll 1 in the vicinityof reservoir 1. 14 . Figure 7.11 -Seismic line 15 -displayed with reversed polarity showing the ''bright spot" for reservoir 1.8. Reservoir 1.11 although ''brighter than reservoir 1.14 shows the same increasing anomaly (same flujd­contact reflectivity) when both reservoirs pass from water to gas satl:ration. inten6ace. Thu~, the 6luid-contact ne6lectivity conne~pond~ to the magnitude 06 the amplitude anomaly put in the ~ei~mic tnace~. 7.1.5 Reservoir 1-16 -Oil effect Only reservoir 1-16 contains oil in well 1. The reservoir map is presented in Figure 7.12 and the available well log data in Figure 7.13. The gamma ray and resistivity logs show an 8 meter sand completely full of oil. If the value of the brine-saturated P-wave velocity for the reservoir 1-15 sand is representative for the reservoir 1-16 a predicted value of fluid-contact reflectivity of .04 is estimated. Data for properties of this oil are not available but, based on data for other oil in the region, a high A.P.I. grade (46 to 65) is assumed. A detectable effect on the elastic properties of this sand will be expected if a bulk modulus for light oil is assumed. The sonic log weakly supports this assumption, showing a low P-wave velocity in the clean basal sand. A predicted value for the fluid-contact reflectivity of .04 would cause a change on the seismic trace equal to the half of the magnitude change given by the reservoir 1-14 or reservoir 1-11. This is likely seen in Figure 6.10, line 15. 7.1.6 Reservoir 1-22 Reservoir 1-22 is mapped on Figure 7.14 and the available well log data are given in Figure 7.15. Gamma-ray log shows a two 14 meter thick-sand layers separated by a thin layer of shale. Resistivity log shows the lower sand to be full of gas. A velocity value of 3600 meters per second read on the reservoir-23 sand was taken as representative for the reservoir. A fluid-contact reflectivity of .07 was predicted for this reservoir. Although the reservoir appears evident on the seismic lines, strong enough to conciliate with the predictions, a more detailed study with synthetic model would be worthwhile to provide a good explanation for this. 7.1.7 Reservoir 1-30 and 1-31 The gamma-ray shows two sands interbedded with thin layers of shale. The resistivity log shows the upper portion and the middle to be gas saturated. The gas-brine interface on reservoir 30 appears to be very doubtful .. ..... . >­ >-.. (!) I-o; I­ E .... ::c E >­ 0 _, v E (.) ~ ...J > (!) >-(!) ~ a: ct "' ::E z ::E 0 ...J ...J (.) a: "' a: "' ::E a: 0 "' "'> I-0 ..: "' ct I­ 0 (!) "' "' z .. .. .... a: ... ..... IL ( 3584 ) (21 3 0) 11 760 .19 .01 1989 1852 (3388) 7031 1858 II. 110 7062 (2158) 7052 1865 1571 10.750 •21 12' ·04 (3627) 11 . 900 .01 FIGURE 7.13 Logs from well l in the vicinitv of reservoir 1 .lfi . ..,• ... ....: ... . . .. .... .. ... C. I.= 10 ms FIGURE 7.14 -Reservoir 1. 22 map. >­ >­ >-­ f­ :I: .. -' t-~ a: E E ... ct uE Cl) f­ > o­ 0 (.) a: _, 0.. 2 ... a: ... ... > • 0 ..: 0 f-z ... 0.. .. f-... ... ... (2464( (3383) 7589 2009 .rJ7 ,14 (2416)t 740" 2013 (3422) (2418) 11.230 7934 2018 136601 FIGURE 7.15 -Loos from well 1 in the vic inity of reservoir 1. 22 . within the shaly sand formation. With a two-way travel time of S milliseconds reservoir 1-30 offers a more difficult target for detection. Decrease in velocity is seen weakly on the sonic log when it passes from brine to gas. On seismic section an increase in amplitude proportional with the predictions is clearly seen associated with gas reservoir 1-31 -Figure 7.16 and 7.17. The predicted value of .OS suggests that this reflector can be distinguished due to the low amplitude of the lithologic reflections in this portion of the seismic section. 7.1.8 Reservoirs 1-34 and l-3S Reservoirs 1-34 and l-3S (Figures 7.18 and 7.19) present a story similar to reservoirs 1-30 and 1-31. The first sand has a thickness of 24 meters and is almost full of gas (the gas-brine contact is very doubtful) .Reservoir l-3S, although thinner, has a well determined fluid-contact with a predicted value of .OS. Two "bright" reflectors corresponding with the same time were detected on seismic lines (Figure 6.10) and were interpreted to be associated with these two reservoirs. Although some flatness is suggested, it is difficult to tell what kind of interfaces are responsible for the reflections. At this depth the anticlinal structure is not clear and the normal dip for lithologic reflections is seismically undetermined. . . . . . .. . .... ..... C. I. = 25 ms FIGURE 7 .16 Reservoir 1.31 map. >- >­ t­ < t- • .. u :c E E ..... >­ ..J u Cl) f­ a: ::f >-0 > 0 < 0 E ..J < 0 ... 0 f-"' :> ::f 0 z ll. Cl) ::f a: "' a: ..J "' 0 u ..J ..J c ... > 0 f­ "' a: Cl) "' 0 ... ...: a.. a: "' 0 ..... f-z !.... 2162 .18 -218 7 ---­ 12.500 .05 l3610l 2196 .16 11.760 .OS (35641 . 14 2209 12. 500 [381 O) 2214 FIGURE 7. 17 Logs from well 1 in the vicinityof reservoir 1.31. . . .. . ....: .•.. .,• .. ', , ...... -• 2 • :..:· . .. . . .• ' ... . ~· . ... ~ ..... .: .. -.................. ·... '......... . - . . . . . . . . . .. ... .. ... -~. ·· .•... • .• ·. . · · ·:.we~ll· ~· ·:· , ~·. : • . ; ... , ... ~· .... , . 1.c . =2!5ma : .' ·. FIGURE 7.18 Reservoir 1.34 map. >­ > > % I-~ I­ I­ ..J u E a: .., .. < u I-E E I!> > C!> C!> IL :2 > ..J "' a: "' < 0 .., I­ I-0 ..: 0 C!> "' z ~ a: .... IL 2283 11760 l3S84l .IS .05 2296 12190 (371 !51 2300 12340 (376ll 308 11900 .0!5 .IS 2317­129510 (3910) 2326 12300 (37491 (3627) FIGURE 7.19 Logs from well 1 in the vicinity of reservoirs 1.34 and 1.35. 7.2 RESERVOIRS FROM WELL -4 Well 4 has also a density log and a more complete study on the acoustic impedance of the layers can be made. Figure 7.20 presents the acoustic impedance as a function of depth. A synthetic seismic trace is also provided and four reservoirs, including three that give strong "bright spots" shown in seismic line 27 (Figure 6.8), constitute the most striking features, presenting the lowest values for the acoustic impedance. The dry well -14 is localized in the vicinity of well -4 (Figure 5.1) and its formations can be readily correlated with the formations of the producing well -4. Assuming little lateral variation on the lithologic properties of the reservoirs and vicinities, a comparison for the same sand reservoir when filled by brine ( well ­14) and filled by gas or oil (well -4) can be made. Table 7.1 compares the data and an average of 12 percent reduction in the P-wave velocity is observed when the sandstones pass from brine to gas. Density presents an average reduction of about 2 percent. These values give for the calculated reflectivities a very anomalous increase about 3 to 12 times greater than the value when brine saturated. This kind of variation can clearly change a modest reflection to a "bright" one. 2 AC OU ST I c IMPEDANCE G/Cm . S 0 0 0 0 0 00 0 0 0 0 0 0 0 0 0 0 0 SYNTHETIC 0 0 0 0 0 0 8 0 v Cl) N ­>-;; < ::c -' I-.... >­ I­ - u I­ < -E ..,_ ... "' E c:> - 2 I-E a: - 0 > " > >­ 0 - - Q. 0-0 a 2 -:::t ­ "' -' 0 < 0 I- z ... v _, -' ... < a: a: 0 I-"' >"'::: ...: z 0 0 I­ ... Q .. "' ~ -' "' Q. -... a -L ) 13110) (1758) 10204 1603 5769 3 ~ ~ 9620 ll768) (2932) ~ ~ 1611 5802 ~ .30 .06 8930 5811 '-1613 r 12987) 11771) ~ 9800 5839 1-1618 ~ ) ll779l 130171 9900 ,...=:===­ ' ;;;:: ? - FIGURE 7.21 -Log data for reservoir 4.2 fluid·contact reflectivity. Although with a gentle dip, this thin reservoir does not provide a fluid-contact reflection event: reflections will be given only by the sand and the sealing shales. Table 7-1 indicates that there is a change from a reflectivity value from + .02 to -.08 on top, when the gas saturated zone is reached. This implies a fluid-contact reflectivity of .10, . The brightness of this reflector, given by this kind of variation, can be well observed on line 27 (Figure 6.11) and on line 9 (Figure 6.8). For reservoir 4-9 data indicate 36 meters of alternating sand and thin shales. The resistivity log presents the upper 8 meters to be saturated with gas and the middle 19 meters with oil. Thus, reservoir 4-9 presents two fluid-contact interfaces: oil-gas and brine-oil. An estimation of the reflectivity value associated with the gas-brine contact is .07 and oil-brine .OS. Furthermore, the reflectivity value for oil-gas contact would be the difference, .02. Nevertheless, none of these reflection interfaces can be seen on seismic lines. The pay thickness of the gas sand is too thin but the light oil should affect the sand almost in the same way as gas and a 27 meters thick section (17 milliseconds), corresponding to the sum of gas sand and oil sand, would probably be picked up by the seismic system. In the seismic lines a weak reflector probably corresponds with this reservoir, but does not appear to be related to a fluid-contact interface or to some other fluid effect. Density and sonic logs show that, from the seismic point of view, reservoir 4-9 can be divided in two distinct thin reservoir. Clearly, there is a shale layers that separates them and a more detailed study would be necessary to better explain the seismic behavior of this reservoir. 7.2.3 Reservoir 4-11 and 4-12 On seismic sections 9 and 27, Figures 6.8 and 6.11, respectively, two most striking "bright spot" appear between 1800 and 1850 milliseconds. These "bright spots" were interpreted to be associated with two reservoirs containing oil and gas. Reservoir 4-11 is mapped on Figure 7. 24 and the available data for the two reservoirs are presented on Figure 7. 25. The gamma-ray log indicates thickness of 13 meters and 15 meters for each reservoir.Resistivity log indicates that the sands are completely saturated >­ ... ...J >-., (.) x ... ... .., .. .. !::: IJl a: .. >->-E e ... E > (.) 0 ::I >-<:> ~ IJl a: 0 (.) ... 0 0 c.. :! ...J 0 z ::I .. IJl z 0 0 ...J a: ...J ...J ...J "'"' a: 0 ..: ~> .. < "' "' "' "' I-....... c.. 0 0 "'a: ;: ~ (32691 0965) 10530 6449 1741 (2990) ( 1977) .09 ----9809 .24 6489 1749 (32691 10530 6539 (1993) 1759 (31391 .22 (2001) .0810300 6565, 1762 (31391 .24 .0510300 (20201 6629 1776 -­ (3269) (20291 .24 10530 S6!59 1782 F I GURE 7.2 2 -Well 4 log data for reservoirs 4.8 and 4. 9. ,.e11-2 • • : ' ' ........· ... ...... ·.· .~ .-~ .. ~' .... . :..:.. .:..~-· .: .......... ............ . . .. . '• ... . FI GURE 7. 23 -Reservoir 4.8 map. by gas or oil. The only fluid-contact interface present is between oil and gas. The sonic log spectacularly displays the decrease in P-wave velocity for both sands,principally related to gas fillings. The density log shows a similar relationship. Oil must be light,or a high gas/oil ratio is causing the decrease in bulk density. With velocity values taken from well 14 predicted values for the gas-water contact reflectivity were .08 for the two reservoirs. Oil-water contact reflectivity was predicted to be .06 for both reservoirs, Thus, the gas-oil contact would be .02. 7.2.4 Other reservoirs from Well 4 Below 1900 milliseconds well 4 presents several gas-saturated sands. The fluid-contact reflectivity was predicted for some of the main reservoirs and were listed on Table 5.2. The velocity of brine-saturated sand was read from the log data of well 14. All reservoirs are completely gas-saturated and do not provide any fluid­contact interfaces at the well 4 location. The sonic log,at this range of depth, show no great differences between shales and sands . High bulk densities cause high acoustic impedance for shale layers and strong reflectivities between gas sand and shale layers are predicted. On line 27 short anomalous reflectors,compounded by a few seismic traces can be seen associated with the gas reservoirs. It seems that small amounts os gas were trapped, at several levels, by two growth falts. Line 9 (Figure 6.8) cuts line 27 normally (Figure 6.11) in the middle of these two faults and show better these weak but distinguishable reflectors. .. ·... ... ;. ·:·. .-·.. .•.. . .. -.. ~· .·.. -·~~~ !-?,. --~ -... ,· .. ... . . . . . ··--.. ........... ..· ..... ............ . FIGURE 7. 2 4 -Reservoir 4. 11 map -t ::::; >­::::; c < a: 0 0 0 ..J >­I­> 0;; 0"' ..J "' "'a: u z 0 "' 0 0 ..J >­I­"' z .... 0 0 0 ..J :I; -... I­E .. 0. ::::; E "' 0 .. I­~I 6711 1790 12058 675'1 (2065 6774 1804 -­(2077) 6814 1814 ..J >­< ,_ > ;:;a::... 0 ..JI-z "' -> (2700) 8856 >­I­-"'0 a:: 0 0. 22 ci 0 ...: . 10 .or- FIGURE 7. 2 5 -\·le 11 4 log data for reservoirs 4 . 1 1 and 4.12. CHAPTER 8 -CONCLUSIONS AND RECOMMENDATIONS FOR FURTHER WORK A study of the fluid-contact reflectivity is important because, in a system sand-shale-fluid, the most consistent reflection will occur at gas-brine contact. In thin reservoir, where the gas-water contact is not detectable the fluid-contact reflectivity is given by the difference between the shale-gas sand reflectivity and the shale-brine sand reflectivity at the top reservoir. Knowing the characteristics of the rock matrix and fluids, and the P-wave and shear-wave velocities of brine­saturated rock, the velocity of the gas or oil saturated rock can be calculated using the Geerstma and Gassmann's equations. The fluid-contact reflectivity also, can be derived from this calculation. Based on Gassmann's theory an important factor that controls the fluid effect, besides the rock-matrix and fluid properties, is the rock-frame bulk modulus (reciprocal of the rock compressibility, devoid fluids) that reflects the structural condition and the grade of consolidation of the porous rock. The rock-frame bulk modulus can be calculated using Gassmann's equations and the grade of consolidation by comparison with the time-average equation. Most of the realistic sedimentary rocks are placed near the vicinity of the Wyllie time-average equation. In this region, the rock-frame bulk modulus is more directly related to the P-wave velocity than to porosity. Thus, it should be expected that the pore-fluid effect will decrease as the brine saturated velocity increases, independent of porosity. Unconsolidated sedimentary rocks occur in the zone above the curve given by Wyllie time-average equation on the P-wave brine saturated rock velocity versus porosity. This zone is the most favorable to occur "bright spots." Porosity values are not so important for predictions of the fluid-contact reflectivity. Knowing the lithology, the fluid-contact reflectivity can be estimated from the brine-saturated velocity alone. If two different sandstone reservoirs have the same velocity, the one with small porosity will present a higher value for fluid-contact reflectivity. The saturation effect on the elastic properties of the rock do not depend on the gas properties; i.e., if the rock properties are appropriate, a "bright spot" will be produced with any type of gas. For the oil case, only light oil or condensate has the property to give easily detectable values for fluid-contact reflectivity but high values of saturation are required. An assessment on Offshore Are One reveals that above 9000 ft depth (2970 m) the sand reservoirs do not follow the Wyllie time-average equation. They display lower values on the brine-saturated P-wave velocity, a behavior that is proper for unconsolidated rocks. For medium depth (2000 m) gas-saturated sandstone in a general way, presents a velocity value about 10 percent lower than the brine-saturated velocity. For greater depth the velocity variation is of the order of 5 percent. There is no available data on velocities for shallow gas sands, but they should exhibit a very large variation since the sands are less consolidated. With one exception, for oil-saturated sandstone, a reduction on the velocity is not readily detectable from the sonic log. A decrease of 8 percent is evident in one reservoir, although this could be caused by lithologic variation. Anagreement was detected between the estimated and observed fluid-contact reflectivity, although assumptions for the fluids properties had to be made. In seismic sections the anomalous enhacement in the amplitude signals correspond with most of the gas and oil-sand reservoirs. The magnitude enhancement is proportional with the predictions. 140 Some reservoirs present results differing from the predictions because seismic, geometric and lithologic considerations are envolved. Wave interference, transmission losses through gas reservoirs, thickness of reservoirs and presence of interbedded thin layers of shales in reservoir contribute to produce a behavior different from the predictions. Further studies, for these reasons, are recommended. The suggestion is to use synthetic traces and construction of models with an appropriate wavelet. Transmission losses and "pull down" effects would be better studied to show how much the shallow gas reservoirs affect the deeper reflections on the seismic sections. The magnitude of the fluid effect could be studied in a scheme making use of actual field traces. After flattened the anticlinal structure , the traces that contain brine would be subtracted from traces that contain hydrocarbons. A relative scale could be provided and the magnitude of the fluid-contact reflectivity could be directly visualized and compared. No lithological variation of the lateral extension of the reservoirs and trapping layers, must be assumed in application of this method. REFERENCES Biot, M.A., 1956, Theory of propagation of Elastic Waves in a fluid-saturated porous solid: I. Low-frequency range, and II -Hight Frequency range, Acoustic -Soc. Am., V.28 pag.168-191 Craft, C., 1973, Detecting hydrocarbons -for years the goal of exploration geophysics: Oil and Gas Journal, Feb., p. 122.125. Domenico, S.N., 1974, Effect of water saturation on seismic reflectivity of sand reservoirs encased in shale: Geophysics: vol. ,39 p. 759-769. Domenico, S. N., 19 76, Effeet of Brine -Gas mixture velocity in An Unconsolidated sand Reservoir, Geophysics: vol.41, p.882-894. Domenico, S.N., 1977, Elastic properties of Unconsolidated porous sand reservoirs, Geophysics, vol.42, p. 1339-1367. Gardner, G.H.F., Gardner L.W., and Gregory A.R., 1974, Formation Velocity and density -The Diagnostic basics for stratigraphic traps: Geophysics vol. 39, p. 770-780 Dorsey, N.E., 1940, Properties of Ordinary water substances in all "its" phases, Am. Chem. Soc. Monograph Ser t=f. 81. Faust, L.Y., 1953, A velocity function encluding lithologic variation: Geophysics, vol. 18, p. 271-288 Gassmann, Fritz, 1951, Elastic waves through a packing of spheres: Geophysics, vol. 16, p. 673 a 685. Geertsma, J,m 1961, Velocity -Log interpretation: The effect of rock Bulk compressibility Soc. Petr. Eng. J., vol. l, p.235-248. Gregory, A.R., 1976, Fluid Saturation Effects on Dynamic Elastic Properties of Sedimentary Rocks Geophysics, vol.41, p. 895-921. Gregory, A.R., 1977, Some Aspects of Rock Physics from Laboratory and log data that are important to seismic interpretation. Bureau of Economic Geology -University of Texas at Austin -un published. Hicks, W.G., and Berry, J.E., 1956, Fluid Saturation of Rocks from Velocity-logs: Geophysics, vol.21 p. 739-754. Mann, R.L. and Patt, I, 1960, Effect of pore fluids on the elastic properties of sandstone: Geophysics, vol.25, p. 433-444. O'Doherty, R.F., and N.A. Anstey, 1971, Reflection on Amplitudes: Geophys. Prospecting vol. 19 p. 430-458. Sarmiento, R., 1961, Geological factors influencing porosity estimates from velocity logs "Bulletin AAPG", 45 n9 5 p. 633-644. Schechter, 1977, University of Texas at Austin, Petroleum Engineering Departament.Personal Communication. Sheriff, R.E., 1975, Factors affecting seismic Amplitudes; Gephysics, vol.23, p.459-493. Toksez et al, 1976, Velocities of seismic waves in Porous Rocks Geophysics,vol.23, p. 459-493. White, J.E., 1975, Computed seismic speeds and attenuation in rocks with partial gas saturation Geophysics, vol.40, p. 224-232. Wyllie,M.R.J., Gregory,A.R. and Gardner,L.W., 1956, Elastic wave velocities in heterogeneous and Porous media: Geophysics, vol.21 p. 41-70. Wyllie, M.R.J., Gregory, A.R., and Gardner, G.H.F.,1958, "An experimental investigation of factors affecting elastic wave velocities in porous media' Geophysics, vol. 23, p. 459-493. White, J.E., 1965, Seismic waves: Radiation,transmission and attenuation: New York, Mc Graw -Hill Book Co. Inc., p. 132. .., 0 ..,. N ..,. "' N N CD 0 0 0 0 N 0 0 0 0 0 0 0 0 0 0 0 N 0 N co 0 0 N ,., 0 0 0 0 . . 0 • 0 0 0 0 0 ~ ~ 0 ,._ ,., 0 "' N Ol N "' CONTOUR INTERVAL• 20 MS 11 Km APPENDIX A Time structural map from the upper seismic hori zon, presentea on Figures 6-1 to 6-6. 0 0 0 0 0 0 () 0 0 0 .... N "' N "' °" CONTOUR INTERVAL 20 MS 1 t Km APPENDIX B Time structural map from the medium seismic horizon.presented on Figures 6-1 to 6-6. • N ~ N N • IO 0 •0 0 0 0 N 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 ... 0 ,,, N ... N "" CONTOU" INTERVAL'-25 MS 11 Km APPENDIX C Time structural map from the lower seismic hori zon, presented on Figures 6-1 to 6-6. VITA This digitized document does not include the vita page from the original. Illllll lllll lllll lllll lllll lllll lllll lllll lllll lllll 111111111111111111111111111111111 2006293258 THESIS 1980 C297 GEOL