Hughbert A. Collier

Attenuation analysis of acoustic waveforms in a borehole intercepted by a sand-shale sequence reservoir

We applied a new processing algorithm to extract intrinsic attenuation (1/Q) from the head P-wave of a full waveform sonic log. The sonic log was acquired in an oil reservoir in northeast Texas (USA). The reservoir is a sand-shale sequence characterized at the pore, core, and borehole scales. We found that the attenuation correlates with the lithology, including a sandstone zone partially saturated with oil and water. A comparison of 1/Q with the microseismogram and the petrophysics of other well logs provides a way of evaluating the consistency of Q at each borehole depth location. An analysis of the results explains the different attenuation anomalies found in the Q log.

Permeability and porosity images based on NMR, sonic, and seismic reflectivity Application to a carbonate aquifer

Carbonate formations generally have a large distribution of pore sizes, ranging from microcrystalline to large vugs. Knowledge of these pore spaces and their connectivity is crucial to hydrocarbon reservoir characterization and to hydrogeological and near surface environmental applications. In this paper, we present permeability and porosity images based on crosswell seismic measurements integrated with well logs and petrography from a carbonate aquifer underlying Palm Beach County, Florida, U.S. Petrography and core analyses reveal relationships between the rock physical properties that control the compressional- and shear-wave velocities of the formation. In addition, core data and petrography characterized the matrix permeability and pore spaces as well as the lithology. The lithology integrated with well logs determined the hydraulic and rock properties of a 500-ft zone intercepted by a borehole. We delineated vuggy and permeable/impermeable zones at the borehole and interwell scales in the upper Floridan aquifer in south Florida by inverting reflection seismic data for impedance which, when correlated with borehole permeability and porosity logs, led to empirical relationships that are used to transform impedance images to permeability and porosity images. The images showed continuity between the major geologic units and lateral changes in the porosity image. The high-resolution reflections observed at the field scale in the carbonate formation are associated with changes in porosity due to the presence of vugs. This was corroborated with P-wave and borehole data, which showed that, as P-wave velocity decreases, porosity increases. The images show that porous zones in the carbonate aquifer are laterally continuous up to 200 ft from the well and then become relatively discontinuous, and that these porous and permeable flow units are characterized by interconnected vugs. To analyze the pore structure of the carbonate rocks of the upper Floridan aquifer in South Florida, we processed x-ray CT and optical microscopic (OM) thin …

Interwell seismic logging for formation continuity at the Gypsy test site, Oklahoma

The continuity logging (or in-seam) method has been used extensively in the coal industry to determine continuity. Continuity logging is an alternative approach to multiple-offset crosswell seismic measurements using guided waves propagating parallel to the layering; in particular, to determine the continuity of sand and shale stratigraphy in oil and gas fields. The present work is a study of rock physical properties and seismic data for reservoir continuity using interwell logging techniques. Processing methods are used to delineate the reservoir boundaries and to relate seismic waves with rock physical parameters. The specific application has been to identify and analyze the propagation characteristics of guided waves in the Gypsy-fluvial sandstone formation at the Gypsy test site in Oklahoma. The integration of well logs and interwell seismic data, including trapped seismic events, suggests the presence of a continuous low-velocity clean sand in the Gypsy sandstone interval. The correlation of sand and shale stratigraphy with well logs and guided waves is consistent with available pressure pulse test data, indicating that the sands are in pressure communication between the wells and that an impermeable barrier exists between the top and bottom of the sand units in the Gypsy sandstone reservoir.

Characterization of dispersion, attenuation, and anisotropy at the Buena Vista Hills field, California

We create a log of intrinsic dispersion and attenuation for the Antelope Shale formation of the Buena Vista Hills field, San Joaquin Valley, California. High dispersion (or low Q) values correlate with thin sand and carbonate beds within the Antelope Shale. These beds are at least ten times as permeable as the host shale formation, so this effect provides a possible avenue for seismic prediction of permeability. The dispersion log is formed through comparison of crosswell seismic velocities (measured at approximately 1 kHz) and sonic log velocities (measured at approximately 10 kHz). In order to provide a proper basis for comparison, the sonic log must first be adjusted for field anisotropy, scaling effects, and resolution of measurement. We estimate a local shale anisotropy of about 20% based on correlations generated from published measurements of other shale fields. We apply resolution enhancement to capture the thin sand and carbonate beds, and windowed Backus averaging to match the measurement scales. A modeling study verifies the technique, and shows that beds of thickness greater than 30 cm have a measurable signature. The actual resolution is on the order of the crosswell Fresnel length, or about 7 m for the model study.

Estimation of components of elastic scattering and intrinsic attenuation via well control at the Buena Vista Hills Field

Attenuation of seismic energy and velocity anisotropy consists of an intrinsic component and an apparent component caused by strictly elastic scattering from velocity and density heterogeneities. The intrinsic component of attenuation is believed to be related to fluid properties in the porous portions of a reservoir. However, it may be difficult to distinguish between the apparent (layer-induced) effects caused by elastic scattering and the intrinsic effects when both mechanisms are operative. In this case, a detailed velocity model of the formation is required in order to predict the elastic scattering component of velocity. We have implemented such a scattering correction technique to determine the magnitude of the intrinsic attenuation from observed sonic velocity data. We constructed a high-resolution velocity model with layers one inch thick based on FMI logs and quality factors derived from sonic log data recorded at the Buena Vista Hills field. Quality factors for intervals were derived using the two station spectral ratio method applied to the full wave sonic log data at the Buena Vista Hills field. The wave response for intervals at different frequencies was obtained using a viscoelastic plane-wave modeling code to model a finely layered region. Intrinsic attenuation is determined in one way by measuring amplitudes of sonic full wave seismograms. The amplitudes at two adjacent stations are processed using the spectral ratio method to obtain an estimate of the attenuation. A second approach to computing the intrinsic attenuation of the formation is to make an elastic scattering correction, based upon the contribution of the reflection coefficients that is caused by thin layers, to the total velocity measured for the interval at sonic frequencies. The resulting difference between the observed velocity and the velocity predicted as a result of elastic scattering is assumed to be due to intrinsic attenuation. The applicability of this method is demonstrated by comparing the predicted intrinsic attenuation results, based on the layered model, with the intrinsic attenuation determined from sonic logs.

A Methodology to Integrate Magnetic Resonance and Acoustic Measurements for Reservoir Characterization

The work reported herein represents the third year of development efforts on a methodology to interpret magnetic resonance and acoustic measurements for reservoir characterization. In this last phase of the project we characterize a vuggy carbonate aquifer in the Hillsboro Basin, Palm Beach County, South Florida, using two data sets--the first generated by velocity tomography and the second generated by reflection tomography. First, we integrate optical macroscopic (OM), scanning electron microscope (SEM) and x-ray computed tomography (CT) images, as well as petrography, as a first step in characterizing the aquifer pore system. This pore scale integration provides information with which to evaluate nuclear magnetic resonance (NMR) well log signatures for NMR well log calibration, interpret ultrasonic data, and characterize flow units at the field scale between two wells in the aquifer. Saturated and desaturated NMR core measurements estimate the irreducible water in the rock and the variable T{sub 2} cut-offs for the NMR well log calibration. These measurements establish empirical equations to extract permeability from NMR well logs. Velocity and NMR-derived permeability and porosity relationships integrated with velocity tomography (based on crosswell seismic measurements recorded between two wells 100 m apart) capture two flow units that are supported with pore scale integration results. Next, we establish a more detailed picture of the complex aquifer pore structures and the critical role they play in water movement, which aids in our ability to characterize not only carbonate aquifers, but reservoirs in general. We analyze petrography and cores to reveal relationships between the rock physical properties that control the compressional and shear wave velocities of the formation. A digital thin section analysis provides the pore size distributions of the rock matrix, which allows us to relate pore structure to permeability and to characterize flow units at the core and borehole scales. Vp, density, porosity, and permeability logs are integrated with crosswell reflection data to produce impedance, permeability, and porosity images. These images capture three flow units that are characterized at the pore and borehole scales. The upper flow units are thin, continuous beds, and the deeper flow unit is thicker and heterogeneous. NMR well log calibration data and thin section analysis demonstrate that interwell region permeability is controlled mainly by micropores and macropores, which represent the flow unit matrices of the confined aquifer. Reflection image-derived impedance provides lateral detail and the depth of the deeper confining unit. The permeable regions identified in both parts of this phase of the study are consistent with the hydrological results of high water production being monitored between two wells in the South Florida aquifer. Finally, we describe the two major methodologies developed to support the aquifer characterization efforts--(1) a method to estimate frequency-dependent scattering attenuation based on the volume fraction and typical size of vugs or karsts, and (2) a method to more accurately interpret NMR well logs by taking into account the diffusion of magnetization between large and small pores. For the first method, we take the exact vug structure from x-ray CT scans of two carbonate cores and use 3-D finite difference modeling to determine the P-wave scattering attenuation in these cores at ultrasonic frequencies. In spite of the sharp contrast in medium properties between cavity and rock and the violation of the small perturbation assumption, the computed scattering attenuation is roughly comparable to that predicted by various random medium scattering theories. For the second method, we investigate how the diffusion of magnetization between macropores and micropores influences NMR log interpretation through 2D simulation of magnetization diffusion in realistic macropore geometries derived from digital images of thin sections. In most cases, our simulations show that the resulting simulated magnetization decay rate and corresponding T{sub 2} spectrum fit the well log and core NMR results better when inter-pore diffusion is included in the simulation. Interpore diffusion moves some of the magnetized fluid from large pores to small pores, so part of the T{sub 2} distribution is shifted to smaller decay times. The shift is strongest when the rock contains small macropores that are large enough to cause bulk relaxation to dominate over surface relaxation, but small enough that the diffusion transport time scale is faster than the bulk relaxation time scale. The simulated T{sub 2} spectra are consistent with known facies characteristics.

Acoustic and CT images to characterize vuggy carbonates in aquifers of South Florida

Summary Based on standard core measurements and image analyses, we determined that the carbonate rock from the Ocala Group, South Florida is formed by moldic, vuggy, intergranular, intraparticle and intercrystalline pores. The thin section analysis provided information on the matrix porosity and the x-ray computed tomography (CT) image provided information on the vuggy porosity. We constructed vuggy porosity models to calculate synthetic ultrasonic responses based on the finite difference method, and we compared the synthetic with ultrasonic data. The results explain the velocity changes associated with vugs in the carbonate rock at the core scale. We used the modeling results to explain the scattering of velocity versus permeability relations based on core measurements for different flow units of the carbonate aquifer. Velocity correlates well with permeability for each carbonate flow unit. To determine whether we can assess the degree of connectivity between vugs or between the matrix and the vugs based on acoustic data, we calculated the squirtflow lengths using a poroelastic model by fitting the calculated and observed velocities at the ultrasonic dominant frequency of 250 kHz. The results show a good correlation between the squirt-flow lengths and the increase in permeability for each flow unit. In addition, we calculated dispersion and attenuation curves based on core data in the frequency range of sonic logs. We found that the attenuation can be related to the fluid flow between the matrix and the vugs. We therefore conclude that the sonic log data has the potential to estimate whether vugs contribute to permeability in the region surrounding the borehole by examining P-wave attenuation and dispersion.

Abstract: Petrophysical Properties and Geology of Selected Intervals in the Frio Formation, Stratton Field, South Texas for Modeling Interwell Seismic Logging Responses

ABSTRACT Seismic or continuity logging consists of locating a seismic source in one borehole near or in a low-velocity layer and deploying a detector array in a second borehole. Detection of guided waves transmitted between the two wells indicates bed connectivity. The guided wave signatures are either leaky modes or normal modes (or both). The technique has numerous applications in various types of heterogeneous geological environments, including many Gulf Coast gas reservoirs. It can be used to determine the continuity of beds between wells, estimate and locate variations in the thickness of beds, and estimate the average rock physical properties of the beds. Stratton field was selected as the Gulf Coast gas-play type field for a project to model interwell seismic logging responses. Stratton is a mature gas field located in the south Texas Gulf Coast, about 30 miles southwest of Corpus Christi. It encompasses over 120,000 acres in portions of Kleberg, Nueces, and Jim Wells counties. Stratton is one of 29 fields in the Frio Formation fluvial-deltaic play associated with the Vicksburg fault zone along the Texas Gulf Coast Basin. This poster presentation explains the technique of interwell seismic logging, documents the petrophysical properties and geology of intervals in the upper and middle Frio, and presents the results of the forward modeling tests. End_of_Record - Last_Page 472-------

Effect of isolated biomoldic porosity on log analysis of Pennsylvanian carbonate reservoirs: Case history

Carbonate reservoirs with isolated moldic porosity require more than just routine log analysis (cementation exponent = 2 and a logging suite of dual induction, microlog, density, and neutron logs). A sonic and/or a dielectric tool should be part of the logging package. Both tools are effective in analyzing carbonate reservoirs with moldic porosity, but only if sonic porosities are calculated with the Wyllie equation and the dielectric is used to calculate a variable m. This study documents the log analysis of a north Texas well in a Pennsylvanian Canyon limestone with isolated moldic porosity. A thorough logging suite (dual induction, microlog, density, neutron, sonic, and EPT), plus petrographic and SEM analyses of two whole cores, made a number of analytical techniques possible: Productivity Ratio Index and five methods for calculating m. The reservoir appeared to be productive with routine log analysis, but upon further examination it calculated wet.