Michael Batzle

Fluid mobility and frequency-dependent seismic velocity — Direct measurements

The influence of fluid mobility on seismic velocity dispersion is directly observed in laboratory measurements from seismic to ultrasonic frequencies. A forceddeformation system is used in conjunction with pulse transmission to obtain elastic properties at seismic strain amplitude (10 −7 ) from 5 Hz to 800 kHz. Varying fluid types and saturations document the influence of pore-fluids. The ratio of rock permeability to fluid viscosity defines mobility, which largely controls pore-fluid motion and pore pressure in a porous medium. High fluid mobility permits pore-pressure equilibrium either between pores or between heterogeneous regions, resulting in a low-frequency domain where Gassmann’s equations are valid. In contrast, low fluid mobility can produce strong dispersion, even within the seismic band. Here, the low-frequency assumption fails. Since most rocks in the general sedimentary section have very low permeability and fluid mobility (shales, siltstones, tight limestones, etc.), most rocks are not in the lowfrequency domain, even at seismic frequencies. Only those rocks with high permeability (porous sands and carbonates) will remain in the low-frequency domain in the seismic or sonic band.

Gassmann's fluid substitution and shear modulus variability in carbonates at laboratory seismic and ultrasonic frequencies

Carbonates have become important targets for rock property research in recent years because they represent many of themajoroilandgasreservoirsintheworld.Someareundergoing enhanced oil recovery. Most laboratory studies to understand fluid and pressure effects on reservoir rocks have been performed on sandstones, but applying relations developed for sandstones to carbonates is problematic, at best.We measure in the laboratory nine carbonate samples from the same reservoir at seismic 3‐3000 Hz and ultrasonic 0.8 MHz frequencies. Samples are measured dry humidified and saturated with liquid butane and brine. Our carbonate samples showed typical changes in moduli as a function of porosity andfluid saturation. However, we explore the applicability of Gassmann’s theory on limestone and dolomite rocks in the context of shear- and bulk-modulus dispersion andGassmann’stheoryassumptions.Forourcarbonatesetat high differential pressures and seismic frequencies, the bulk modulus of rocks with high-aspect-ratio pores and dolomite mineralogy is predicted by Gassmann’s relation.We also explore in detail some of the assumptions of Gassmann’s relation,especiallyrock-framesensitivitytofluidsaturation.Our carbonate samples show rock shear-modulus change from dry to brine saturation conditions, and we investigate several rock-fluid mechanisms responsible for this change. To our knowledge, these are the first controlled laboratory experimentsoncarbonatesintheseismicfrequencyrange.

Gassmann's equation and fluid-saturation effects on seismic velocities

Gassmann’s (1951) equations commonly are used to predict velocity changes resulting from different porefluid saturations. However, the input parameters are often crudely estimated, and the resulting estimates of fluid effects can be unrealistic. In rocks, parameters such as porosity, density, and velocity are not independent, and values must be kept consistent and constrained. Otherwise, estimating fluid substitution can result in substantial errors. We recast the Gassmann’s relations in terms of a porosity-dependent normalized modulus Kn and the fluid sensitivity in terms of a simplified gain function G. General Voigt-Reuss bounds and critical porosity limits constrain the equations and provide upper and lower bounds of the fluid-saturation effect on bulk modulus. The “D” functions are simplified modulus-porosity relations that are based on empirical porosity-velocity trends. These functions are applicable to fluid-substitution calculations and add important constraints on the results. More importantly, the simplified Gassmann’s relations provide better physical insight into the significance of each parameter. The estimated moduli remain physical, the calculations are more stable, and the results are more realistic.

Heavy oils—seismic properties

Heavy-oil seismic properties are strongly dependent on composition and temperature. In biodegraded oils, straight chain alkanes are destroyed and complex heavy compounds dominate. As a result, the simple empirical trends developed for light oils for fluid properties such as viscosities, densities, gas-oil ratios, and bubble points may not apply well to heavy oils.

Heavy oils: Their shear story

Heavy oils are important unconventional hydrocarbon resources with huge reserves and are usually exploited through thermal recovery processes. These thermal recovery processes can be monitored using seismic techniques. Shear-wave properties,inparticular,areexpectedtobemostsensitivetothechanges in the heavy-oil reservoir because heavy oils change from being solid-like at low temperatures to fluid-like at higher temperatures. To understand their behavior, we measure the complex shearmodulusandthusalsotheattenuationofaheavy-oil-saturated rock and the oil extracted from it within the seismic frequency band in the laboratory. The modulus and quality factor Qoftheheavy-oil-saturatedrockshowamoderatedependence on frequency, but are strongly influenced by temperature. The shear-wave velocity dispersion in these rocks is significant at steam-flooding temperatures as the oil inside the reservoir loses viscosity.Atroomtemperatures,theextractedheavyoilsupports a shear wave, but with increasing temperature, its shear modulus decreases rapidly, which translates to a rapid drop in the shear modulus of the heavy-oil-saturated rock as well.At these low to intermediate temperatures 30°C‐100°C, an attenuation peak corresponding to the viscous relaxation of the heavy oil is encountered also resulting in significant shear-wave velocity dispersion, well described by the Cole-Cole model. Thus, shearwaveattenuationinheavy-oilrockscanbesignificantlylargeand iscausedbyboththemeltingandviscousrelaxationoftheheavy oil. At yet higher temperatures, the lighter components of the heavy oil are lost, making the oil stiffer and less attenuative.The dramaticchangesinshearvelocitiesandattenuationinheavyoils should be clearly visible in multicomponent seismic data, and suggestthatthesemeasurementscanbequalitativelyandquantitatively used in seismic monitoring of thermal recovery processes.

Time-lapse gravity monitoring: A systematic 4D approach with application to aquifer storage and recovery

We studied time-lapse gravity surveys applied to the monitoring of an artificial aquifer storage and recovery (ASR) system in Leyden, Colorado. An abandoned underground coal mine has been developed into a subsurface water reservoir. Water from surface sources is injected into the artificial aquifer during winter for retrieval and use in summer. As a key component in the geophysical monitoring of the artificial ASR system, three microgravity surveys were conducted over the course of ten months during the initial water-injection stage. The time-lapse microgravity surveys successfully detected the distribution of injected water as well as its general movement. Quantitative interpretation based on 3D inversions produced hydrologically meaningful density-contrast models and imaged major zones of water distribution. The site formed an ideal natural laboratory for investigating various aspects of time-lapse gravity methodology. Through this application, we have studied systematically all steps of the method, including survey design, data acquisition, processing, and quantitative interpretation.

Effective pressure or what is the effect of pressure

Using time-lapse seismics as a reservoir-monitoring tool, geophysics can help distinguish different reservoir production scenarios. For example, Eiken et al. (2000) successfully detected fluid-saturation changes after CO2 injection using time-lapse seismics at Sleipner Field. Over the cycle of a reservoir life, oil saturation usually decreases, reservoir pressure declines, and gas breakout may occur. These changes cause rock property changes that are detectible in time-lapse seismics. Therefore, it is important to understand the effects of pressure and saturation changes on rock properties. While the effects of saturation changes are often well described by Gassmann (1951), Brown and Korringa (1975), and Mavko (1975), the effects of pressure changes are less understood. Here we focus on understanding the effects of fluid pressure on velocities.

Fluid substitution in rocks saturated with viscoelastic fluids

Heavyoilshavehighdensitiesandextremelyhighviscosities, and they exhibit viscoelastic behavior. Traditional rock physics based on Gassmann theory does not apply to materials saturated with viscoelastic fluids. We use an effective-medium approach known as coherent potential approximation CPA as an alternativefluid-substitutionschemeforrockssaturatedwithviscoelasticfluids.Suchrocksaremodeledassolidswithellipticalfluidinclusions when fluid concentration is small and as suspensions of solid particles in the fluid when the solid concentration is small. Thisapproachisconsistentwithconceptsofpercolationandcritical porosity, and it allows one to model sandstones and unconsolidated sands.We model the viscoelastic properties of a heavyoil-saturated rock sample using CPAand a measured frequencydependent complex shear modulus of the heavy oil. Comparison of modeled results with measured properties of the heavy-oil rock reveals a large discrepancy over a range of frequencies and temperatures. We modify the CPAscheme to account for the effect of binary pore structure by introducing a compliant porosity term. This dramatically improves the predictions. The predicted values of the effective shear modulus of the rock are in good agreement with laboratory data for the range of frequencies and temperatures. This confirms that our scheme realistically estimates the frequency- and temperature-dependent properties of heavy-oil rocks and can be used as an approximate fluid-substitutionapproachforrockssaturatedwithviscoelasticfluids.

Maturity and Impedance Analysis of Organic-Rich Shales

Organic-rich shales (ORSs) need to be studied in detail to understand the provenance and the generation of hydrocarbons from source rocks. In recent years, ORSs have gained importance as hydrocarbon resources as well. Successful exploration and production programs for ORSs need reliable identification of their kerogen content as well as maturity through indirect seismic methods. However, the properties of kerogen are poorly understood, so predictions about maturity and rock-kerogen systems remain a challenge. Assessment of maturity from indirect measurements can be greatly enhanced by establishing and exploiting correlations between physical properties, microstructure, and kerogen content. We show correlations between the impedance microstructure of ORSs and their maturity and elastic properties. We have used scanning acoustic microscopy to analyze and map the impedance microstructure in ORSs. We quantified textural properties in the images and related these textural properties to maturity and to impedance from acoustic-wave propagation measured at centimeter scales. This combined study of acoustic properties and microstructures of ORSs gives important insight into changes resulting from kerogen maturation. We introduce a modified porosity term and find that (1) there is a significant correlation between velocity and modified porosity of all ORSs; (2) imaging and quantifying microscale impedance texture and contrast in the images allow us to correlate them with ultrasonic measurements on a centimeter scale; and (3) textural heterogeneity, elastic impedance, velocity, and density increase with increasing shale maturity. We also discuss possible methods to predict maturity from impedance on the basis of understanding the changes resulting from maturity in well-log response, core measurements, and microstructure of ORSs. Our work has important bearing on developing successful production and stimulation methodologies.

Acoustic property of heavy oil - measured data

Summary Heavy oils are viscous fluid having three phases: fluid, quasi-solid and glass solid depended on temperature. We have measured ultrasonic velocities on 10 heavy oil samples at different phases. Measured data suggest that heavy oil properties are similar to the light oil properties if temperatures are higher than the liquid point. With temperature decreases below the liquid point, heavy oil transfers from liquid phase to a quasi-solid phase with drastic increase of viscosity, S-wave velocity appears measurable and P-wave velocity deviated up from the light oil trend. P- and S-wave velocities of heavy oils show a systematic relation to API gravity, temperature, pressure, GOR, and appear dispersive as heavy oil in the quasi-solid state. densities, gas-oil ratios and bubble points may not apply well to heavy oils. Heavy oil at high temperatures can be characterized similar as light oil. However, at low temperatures, viscosity of heavy oils increases drastically and properties of heavy oils are significantly different. We need study properties of heavy oil thoroughly in order to build a proper rock physics model for heavy oil reservoirs.