Abstracts from The 2002 Petrophysics Articles
In Situ Stress Determination using Well Log Data for the Oil Fields of the Krishna-Godavari Basin, India
Rima Chatterjee and Manoj Mukhopadhyay
ABSTRACT
The Krishna-Godavari Basin (KGB) is situated at the mid-portion of the Eastern Continental Margin of India (ECMI), where the orientation of the rifted margin clearly swings by more than 45 degrees. This is in apparent correspondence to the original breakup trend of continental India. The gross tectonic pattern developed here is categorized into “Intracratonic” and “Pericratonic” basinal areas where the hydrocarbon-bearing prospects are mapped. Four-arm dipmeter log data from 20 available wells distributed almost equally over the intracratonic and pericratonic areas of KGB are analyzed here to infer the orientation of the maximum horizontal compressive stress (SH) from the borehole breakout data extending to depths exceeding 3400 m. The mean orientation of minimum horizontal compressive stress (Sh) is N60°W as observed from the cumulative zone length versus azimuth histogram as well as from the frequency of occurrence versus azimuth histogram for wells belonging to the intracratonic and pericratonic areas. The Kaikalur Horst, which bears commercial accumulations of hydrocarbons in the intracratonic basin, is known to be identified by a NE-SW trending channel along its western flank, which presumably developed during the initial stages of fault reactivation. The breakout orientation observed in the Kaza-Kaikalur Horst is mostly E-W. The breakout orientation for both intracratonic and pericratonic areas of KGB varies from N36°W to E-W corresponding to geologic ages of sediments from the Permo-Triassic through Miocene.
NMR Identification of Fluids and Wettability in situ in Preserved Cores
G. Leu, A. G. Guzman-Garcia, D. G. Cory and P. N. Sen
ABSTRACT
The determination of the chemical composition and wetting fluid of the mobile phase in core samples are essential elements in understanding fluid dynamics in these systems. A combination of NMR, magic angle sample spinning (MASS) and relaxation measurements permits this determination in a simple, efficient and unambiguous fashion. MASS removes the effects of variation in the bulk magnetic susceptibility that would otherwise degrade the spectral information and prevent measurement of the chemical composition. Relaxation measurements permit the components in contact with the surface to be identified since the surface relaxation dominates all other contributions to relaxation. We demonstrate this by a series of measurements on two preserved cores taken from a sandstone formation.
Comparison of Modeling Codes for Resistivity and MWD Instruments: Part 2, 1-D Thin Beds
Liang C. Shen
ABSTRACT
Part 1 of this series of reports examined the codes that are used to compute the effects of the borehole and radial invasion on the readings of induction and MWD borehole tools. In this paper the second part of the comparison exercise is reported for instrument responses in formations containing many thin beds. In one case, the 6FF40 induction tool responses in the Oklahoma formation are computed with no relative deviation. In the other case, we compare the computed logs of a generic MWD tool in an 85-degree well in a multiple-layer formation. In both cases the formation resistivity profiles are assumed to be one-dimensional (1-D), that is, the resistivity is a function of depth only and the borehole and invasion are neglected. The objective of this survey is to compare different computer modeling codes that have been developed by various academic and industrial groups. Only the numerical results are compared. The computation speed, memory requirements, and other factors are not covered in this project. Five groups participated in this exercise for the MWD tools and four groups for induction tools. Agreements between results obtained from those codes are generally good. The maximum difference in computed apparent conductivity is less than 0.1 mS/m in induction codes. The differences in computed amplitude ratio and phase shift in MWD codes are limited to 0.02 dB and 0.1 degree, respectively. However, primarily due to different schemes used to convert the amplitude and phase data to Ra and Rp (amplitude-based and phase-based apparent resistivity) of the MWD logs, the differences in these logs may be as high as 9 ohm-m or 30% in zones with resistivity greater than 50 ohm-m.
Coates and SDR Permeability: Two Variations on the Same Theme
Richard Sigal
ABSTRACT
Currently there are two seemingly different expressions used to calculate permeability from measurements of nuclear magnetic resonance (NMR) decay signals. When applied to measurements on 100% brine-saturated core, both provide very similar fits to the measured permeability. One of the two, commonly known as the SDR permeability, ksdr, is soundly based in the theoretical understanding of flow through a porous media and in the work relating permeability to capillary pressure measurements. The SDR formula is, in fact, a straightforward mapping from the capillary pressure formulas into NMR quantities with the addition of a correction factor to account for the fact that NMR measures pore body size while capillary pressure curves are controlled by pore throat size. The characteristic time associated with the SDR formula is usually taken equal to the geometric mean of the NMR distribution Tgm.
The Coates formula for the permeability, kcoates, on the other hand, has been justified by more heuristic arguments. However the Coates formula is the preferred formula when the pores contain multiple fluids, so a better understanding of its basis is desirable. As it stands, kcoates has no explicit dependence on a pore size; but, since it works well for a wide class of rocks, it must have an implicit dependence. The Coates formula can be put into the same form as the SDR formula by defining a new characteristic decay time, Tcoates.
The relationship between Tcoates and Tgm depends on the NMR decay spectra for the rock. For synthetic, log-normally distributed decay spectra with a standard deviation less than 0.7 decade, the ratio of Tcoates to Tgm increases from less than one for large BVI as a percent of pore volume to greater than one for small BVI. For most of its range, the dependence is close to linear. Examination of lab data also shows a linear relationship between Tcoates and Tgm with Tcoates less than Tgm for small values of Tgm and greater than Tgm for large values.
March-April
Vol 3 No 2
Seismic Lithofacies Classification from Well Logs using Statistical Rock Physics
Per Avseth and Tapan Mukerji
ABSTRACT
In this paper we identify and classify populations of well log data into clusters, referred to as seismic lithofacies, representing sedimentary units with characteristic seismic properties. We show that detailed analysis of local geology and physical rock properties can improve the understanding of variability in well log data and guide the selection of optimal well log parameters for facies discrimination and classification.
We use data from a North Sea turbidite field, and define six different facies groups (I-VI) based on clay content, grain size, and bedding configuration. The facies are primarily determined from well logs (gamma ray, density, and sonic logs), but sub-facies of thick-bedded sandstones (Facies II) are defined by certain textural parameters (clay location, cementation, etc.), which are determined from core and thin-section analyses. Rock physics modeling is used to guide the recognition of characteristic clusters of data.
Having established a statistically representative training data base from a type-well, we perform multivariate classification of data from other wells in the area. We use different multivariate statistical methods and a neural network for the classification, and compare the success rates of the different methods. We find that the Mahalanobis discriminant analysis (MLDA), the probability density function (PDF) classification, and the neural network (NN) classification all have a “success rate” of about 80% when we use sonic and gamma ray logs together. The neural network does slightly better than MLDA, which again does slightly better than PDF. However, NN requires much more computational effort than do MLDA or PDF. The advantage of PDF over MLDA is that it will easily reveal types of lithofacies other than those in the training data and/or detect erroneous log measurements. In general, this study shows that a relatively simple statistical technique as MLDA is effective for classification of well log data into distinct lithofacies with characteristic physical rock properties.
RESEARCH NOTE
Archie Parameter Determination by Analysis of Saturation Data
X. Chen, L. C. Kuang and Z. C. Sun
ABSTRACT
Parameters in Archie’s equation are usually determined in labs through experiments on the electric properties of rocks. We discuss a new method using saturation analysis data to determine the parameters. Correlations among saturation, resistivity, and porosity derived from the two Archie equations convert calculation for values of electric parameters to a problem of calculation for the coefficients of an equation with several unknowns. Based on calculation and study on actual saturation analysis data in several oilfields in the Junggar basin, the calculated parameters are all within the theoretical range, which can be used to obtain a water saturation value using logging data. We discuss the factors that influence Archie’s parameters, especially the influence of petrophysical properties and wettability. This can be proved using saturation analysis data for a wide range of Archie’s parameters. Archie’s parameters determined through electric property experiments can’t prove this. More importantly, to determine Archie’s parameters using saturation analysis data makes it unnecessary to calculate the resistivity of the formation water. Saturation should be measured in well preserved core since large errors can exist between the measured values and the original values due to degasification and volatilization. This will influence the effectiveness of the saturation data. Therefore, the key to the problem is to correct the measured saturation values.
The Pressure Dependence of Permeability
R. F. Sigal
ABSTRACT
The dependence of matrix permeability with pressure can be modeled by applying elasticity theory to a modified Katz-Thompson relationship for permeability. In the modified Katz-Thompson relationship permeability is proportional to the product of the characteristic pore throat size squared and porosity raised to the power of the cementation coefficient. The pressure dependence of permeability can then be estimated from the changes with pressure of the porosity and the characteristic pore throat size. The change in porosity with net effective confining pressure is easily calculated from the static bulk modulus. The calculation of the pressure dependence of the characteristic pore throat size requires an assumption on pore throat shape. The pressure dependence depends on both the static bulk modulus and the static Poisson’s ratio, along with a numerical constant fixed by the shape. In this work the pore throat shape is taken as a cusped hypotroichoidal.
The pressure dependence for fracture permeability has been found to be fit very well by Walsh’s model for the closure of a rough crack. This functional dependence on pressure produced by this model is very different than that in the equations developed for the pressure dependence of matrix permeability. Consequently, the determination of which of the two theories best fits observation provides an excellent way to distinguish fracture permeability from matrix permeability.
Petrophysically Constrained Inversion of Resistivity Logging Data
Zhiyi Zhang, Elton Frost Jr., Raghu Chunduru, and Alberto Mezzatesta
ABSTRACT
We have developed a petrophysical inversion algorithm that uses gamma ray, neutron, density, acoustic, and resistivity data in a single, unified interpretation process. The steps in the interpretation process consist of first estimating bed boundary positions from all available measurements, including gamma ray, neutron, density, and resistivity data, using a weighted inflection point method. Bed boundary positions are then adjusted using the response functions associated with the various instruments. These are mututally reconciled to produce a consistent set of bed boundaries which best represents the subsurface geology and lithology. Next, upper and lower bounds for formation resistivity and flushed zone resistivity are estimated using an appropriate water saturation equation. Resistivity bound estimation considers shale volume, porosity, the possible range of variation for water saturation, formation water resistivity, and shale resistivity. Resistivity bounds are incorporated into the inversion algorithm by using an outside penalty function added to the original objective function of the optimization. Our algorithm utilizes a generic objective function that includes a reference model and data-weighting based on uncertainties. Further, a first-order spatial finite difference operator has been built into the objective function to eliminate unrealistic oscillations in the final model. A synthetic data example demonstrates the effectiveness of the general objective function using our selected constraints. An application to real data shows that the proposed inversion process can effectively handle systematic noise in the data caused by borehole washouts and inappropriate bed boundary positioning. The result is a petrophysically meaningful inversion results.
May-June
Vol 3 No 3
Grain Sorting, Porosity, and Elasticity
Jack Dvorkin and Mario A. Gutierrez
ABSTRACT
This paper presents an effective-medium theoretical description of the elastic properties of isotropic sand-shale mixtures. The effective elastic moduli and velocities are related to the total porosity, shale content, and the mixing mode (dispersed or laminar). The effective-medium equations can be used for theoretical mixing of sand and shale in dispersed or laminar modes and, ultimately, for seismic forward modeling and reservoir characterization.
Practical Application of Geostatistical Scaling Laws for Data Integration
P. Frykman and C.V. Deutsch
ABSTRACT
Reconciling data from different scales is a long-standing problem in reservoir characterization. Data from core plugs, well logs of different types, and seismic data must all be accounted for in the construction of a geostatistical reservoir model. It is inappropriate to ignore the scale difference when constructing a geostatistical model. Geostatistical scaling laws were devised in the 1960s and 1970s primarily in the mining industry where the concern was mineral grades in selective mining unit blocks of different sizes. These principles can be extended to address problems of core, log and seismic data. The adoption of these classic volume-variance or scaling relationships presents some challenges. Three specific concerns are the ill-defined volume of measurement, uncertainty in the small-scale variogram structure, and non-linear averaging of many responses including acoustic properties and permeability. We demonstrate the application of volume-variance relations for upscaling and downscaling techniques to integrate data of different scales. Practical concerns are addressed with data from a chalk carbonate reservoir and a clastic reservoir in the Danish North Sea.
The Response of a Triaxial Induction Sonde in a Biaxial Anisotropic Medium
S. Gianzero, D. Kennedy, L. Gao, and L. SanMartin
ABSTRACT
The theoretical response characteristics of a triaxial induction logging instrument are developed for the case of a sonde comprising a triaxial transmitter and a triaxial receiver array (i.e., three mutually orthogonal transmitter- receiver pairs) immersed in an unbounded, homogeneous, biaxially anisotropic medium. In the case we consider, the instrument's transducer axes are aligned parallel to the principal axes of the conductivity tensor. The eddy currents induced by the instrument's transmitters circulate in geometrically (more-or-less) complicated loops. In view of the circulation of the eddy currents, intuition suggests that instrument responses ought to be influenced by multiple components of the conductivity tensor. However, our results show that in the low frequency limit (i.e., negligible skin effect) there are only two independent responses to conductivity. The coplanar, or transverse, dipole coupling responses, Cxx and Cyy depend only upon the z-directed principal component of conductivity, sz. Conversely the axial coupling Czz (i.e., vertical magnetic dipole transmitter and receiver) does depend upon both horizontal principal components of the conductivity tensor, namely upon the geometric mean of both horizontal conductivities, .
Methodology: The Fivefold Way
D. C. Herrick
INTRODUCTION
Some time ago, the editor of this august journal and I were discussing the vagaries and vicissitudes of oil company management. I observed that they could be categorized and their motivation understood since, after all, there are only five ways of doing things. I had determined this while working with Amoco's Petrophysics Training Program a number of years ago. Mr. Kennedy expressed amazement, so I described them and their implications. He asked me to write this essay. Since the Wyoming winter wind is blowing (blasting), I would rather sit in front of a warm computer than expose myself to the elements. The following should be considered a work in progress. If anyone has comments or discovers additional methodology, I would be honored if you were to share it with me.
Recent Developments In Logging Technology
Stephen Prensky
ABSTRACT
Industry's need to minimize the huge costs associated with deepwater reservoir development has fueled rapid advances in well design and drilling technology over the past decade. Since I last surveyed the state of the logger's art in 1994, advances in logging technology have kept pace with these improvements to facilitate drilling, evaluation, and completion of these deepwater, extended reach, horizontal, and multilateral wells. Recent advances and developments in wireline logging and logging-while-drilling (LWD) technology have been largely evolutionary. Continued improvements in digital electronics and telemetry have resulted in improved tool accuracy and reliability, extended tool operation to higher-temperature and higher-pressure environments, improved downhole processing, and enabled new slimhole designs. With the exception of a few radically new tool designs, recent advances in wireline and LWD technology largely consist of incremental improvements and competitive equivalents to the openhole and cased-hole designs discussed in 1994. Reservoir monitoring is one area that has experienced significant advances with the development of new wireline tools and permanently placed sensors. Advances in acoustic wireline devices include low-frequency acoustic multipole (full, waveform and crossed-dipole) devices that enable shear- and Stoneley-wave acquisition in soft formations. Recent electromagnetic (EM) tool designs include a multi-electrode lateral device, two through-casing resistivity tools, a high-resolution azimuthal laterolog service, and a multi-component induction instrument that responds to resistivity anisotropy (Rv and Rh). Second generation pulse-echo NMR devices provide additional measurements, improved evaluation in light and heavy hydrocarbons, and faster reconnaissance logging. In nuclear logging, several through-tubing pulsed-neutron designs provide both capture and spectroscopy measurements. A new through-casing formation tester is capable of drilling holes in the casing, testing, and setting high-pressure plugs after the formation test is completed. The primary emphasis in LWD continues to be achieving real-time delivery of a variety of measurements and borehole images to facilitate safe drilling, accurate well placement (geosteering), and optimum reservoir drainage. Recent advances include acoustic shear slowness, seismic-while-drilling, and NMR; pulsed-neutron measurements have been field tested. An entire class of downhole wireline and permanently placed sensors for reservoir monitoring has been developed since 1994. Wireline sensors include tiltmeters and accelerometers for monitoring fracture growth and fluid flow. Permanent sensors include seismic and EM arrays and fiber-optic sensors for detecting fluid flow, monitoring changes in fluid contacts and saturation, and fracture detection and evaluation.
JULY-AUGUST
2001
Vol 3 No 4
Pore Network Simulation of Low-Field NMR Relaxometry under Conditions of Drainage and Imbibition: Effects of Pore Structure and Saturation History
D. Chang and M. A. Ioannidis
ABSTRACT
Nuclear magnetic resonance (NMR) relaxometry tests, carried out on partially saturated porous media, convey information on the distribution of fluids within the pore space. Proper interpretation of this information requires a means to isolate the effects of pore structure (pore and throat shape and size distributions, spatial correlations, etc.) wettability and saturation history. A pore network simulator of NMR relaxation that can clarify the effect of these factors on observed T2 distributions is developed in this work. The pore network model can be calibrated with pore structure parameters (pore volume and throat size distributions, pore connectivity) determined from analysis of stochastic 3D replicas of the pore space generated from thin-section image information. The presence of irregular, and possibly, fractal pore surfaces is accounted for through a "late pore filling" model calibrated to match mercury porosimetry data. The network model is then used to simulate the water distribution and proton magnetization decay under conditions of drainage and imbibition. The model can be used to examine: (a) conditions under which diffusive coupling between pores has a significant effect on the decay spectra; (b) contributions to the magnetization decay spectra from water trapped at the irregular pore surfaces; and (c) contributions to the magnetization decay spectra from water in large pores which are inaccessible by the non-wetting phase during drainage, and water in pores containing oil trapped during imbibition.
A New Methodology to Derive both Relative Permeability and Effective Permeability Reduction Profile from Numerical Simulations of Formation Damage Experiments
P. Egermann, D. Longeron, and F. Lamy
ABSTRACT
Near wellbore flow properties are affected by mud and mud filtrate invasion during overbalanced drilling operations. The degree of alteration depends on a large number of parameters such as the nature and characteristics of the drill-in fluid, formation properties and operating conditions. Laboratory mud filtration experiments have been conducted for many years to determine the extent and the degree of formation damage due to drill-in fluid invasion. This paper proposes a new methodology to interpret formation damage tests performed with water-based muds. Numerical simulations are performed to quantify independently, on the one hand the impact of mud solids invasion and on the other hand the effect of multiphase flow process on the global permeability damage. Effective oil return permeability profiles are first determined through local pressure measurements along the core at different backflow rates. Then, corresponding relative permeabilities are determined from matching of the pressure differences and cumulative production evolution as a function of time. Results show that a good fit between experiment and simulation is obtained with a unique set of relative permeability curves for a given formation permeability. Their shapes are very similar to what is obtained using standard water/oil displacement experiments. The efficiency of the restoration of effective permeability is highly dependent on the oil backflow rate. The higher the imposed oil flow rate, the better the restoration of initial permeability. The main advantage of the proposed procedure is to provide, from a single laboratory test, a consistent interpretation of both permeability damage mechanisms (mud solids deposition and filtrate invasion ). This leads to a better diagnosis of the origin of the damage. Finally some recommendations are given to improve the design of laboratory formation damage experiments and to interpret natural cleanup of open hole completion. Guidelines are also provided to select the least damaging drill-in fluid formulation for a given permeability formation.
Petrophysical Properties and Anisotropy of Sandstones under True-Triaxial Stress Conditions
X. D. Jing, S. Al-Harthy, and M. S. King
ABSTRACT
Development of an innovative polyaxial (true-triaxial) stress loading system is described. The system was originally designed to determine ultrasonic velocities, fluid permeability and elastic properties on cubic rock specimens in which sets of orientated fractures and microcracks had been introduced. The original system was also used to compare differential strain analysis with ultrasonic shear-wave splitting for predicting the in situ state of stress in rock masses. The system was modified to incorporate acoustic emission sensors, in addition to the ultrasonic velocity transducers, to investigate laboratory-induced fracturing of a sandstone and to analyze directly the mechanics driving the fracturing. The loading system has subsequently been modified further to incorporate a pressure-sealing scheme, to enable high pore pressures to be achieved, and a dedicated loading frame with all principal stresses servo-controlled. In this latter form the system has been used to study directional permeability and electrical conductivity on the same specimen, pore volume change and capillary pressure characteristics at elevated external stresses and pore pressures, in addition to the measurements for which it was originally designed.
Anchoring Methodologies for Pore-Scale Network Models: Application to Relative Permeability and Capillary Pressure Prediction
Steven R. McDougall, John Cruickshank, and Ken S. Sorbie
ABSTRACT
The work described in this paper attempts to extend the predictive capability of pore-scale network models by using real experimental data as lithological "anchors." The development of such an anchored model capable of relative permeability and capillary pressure prediction would clearly be of great utility, providing a cheap and flexible tool for interpolating and extrapolating sparse and expensive laboratory data sets. Moreover, once the model had been anchored to reservoir rock samples, a wide range of sensitivities could be examined without recourse to additional experiments. In the context of gas reservoir engineering, a preliminary methodology-utilizing mercury injection capillary pressure (MICP) data-has been developed that could permit both the matching of existing experimental gas/oil relative permeability curves and the quantitative prediction of additional data sets. Two approaches have been considered. The first involves matching capillary pressure data from MICP experiments to extract pore size distribution and pore volume scaling information. These parameters are then used to predict the relative permeability curves directly. A second approach is to simply match the gas-oil relative permeability curves using a highly constrained bond model. Capillary pressure prediction is then treated as an inverse problem. The constrained set of adjustable parameters in the macropore network model comprises: coordination number (z), pore size distribution exponent (n), pore volume exponent (n) and pore conductivity exponent (l)-i.e., only four simple parameters. Results demonstrate that this basic four-parameter model is sufficient to reproduce the vast majority of experimental drainage relative permeability curves examined. Only one network simulation per sample is required to match both the wetting and non-wetting curves and each parameter obtained from the matching process lies within a narrow range of possible values. These highly encouraging results suggest that further over-parameteri- zation of the model is unnecessary in the context of drainage processes. However, we also show that anchoring network models to mercury intrusion data alone is insufficient for predicting relative permeabilities a priori-there is an interdependence of parameters and, consequently, an infinite set of parameter combinations will produce almost indistinguishable capillary pressure curves. Therefore, future analysis of MICP data should be performed in conjunction with the analysis of some other independent experiment-an experiment that gives one additional datum that forms the "missing link" between anchoring and prediction.
Scaling of Viscosity Ratio for Oil Recovery by Imbibition from Mixed-Wet Rocks
Zhengxin Tong, Xina Xie and Norman R. Morrow
ABSTRACT
Displacement of oil by spontaneous imbibition from the rock matrix of fractured reservoirs can be a dominant production mechanism. Laboratory tests on reservoir cores are often used to predict oil recovery from the reservoir by scaling results to reservoir conditions. Factors involved in scaling are the rock properties, liquid viscosities, interfacial tensions, core geometry and wettability. Some previous developments in scaling were based on oil recovery from very strongly water-wet rocks results for different viscosity ratios were closely correlated by the geometric mean of the oil and aqueous phase viscosities. Most reservoirs have mixed wettability and, as judged from rate and extent of imbibition, many are weakly water-wet. Results have been obtained for mixed-wet sandstone prepared by adsorption of organic film from an asphaltic crude oil. The crude oil used to induce wettability change was displaced by decalin followed by mineral oil. The mixed wettability states attained by this technique, referred to as MXW-F, depend on the aging temperature, the initial water saturation, and the number of pore volumes of decalin used to displace the crude oil. For MXW-F cores prepared by this technique, imbibition rates were much slower than for strongly water-wet cores and were highly sensitive to initial water saturation. A series of imbibition tests were performed with initial water saturation ranging from 11.0% to 28.0%. MXW-F imbibition results for recovery of mineral oil, with viscosities ranging from 3.8 to 180.0 cp and initial water saturation close to 21%, were correlated satisfactorily by the geometric mean of the viscosity ratio.
SEPTEMBER-OCTOBER
2001
Vol 3 No 5
Simulating NMR Magnetization Diffusion in a Real Carbonate Pore System
Chris L. Hackert and Jorge O. Parra
ABSTRACT
Carbonate rocks have always been problematic for nuclear magnetic resonance (NMR) log interpretation because of their low surface relaxivity and wide distribution of pore sizes. Recent work has suggested that a part of the interpretation problem may be understood in terms of diffusion of magnetization between macropores and micropores. We investigate this effect through two-dimensional 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 T2 spectrum fit the well log and core NMR results better when inter-pore diffusion is included in the simulation. The inter-pore diffusion moves some of the magnetized fluid from large pores to small pores, and so part of the T2 distribution is shifted to smaller decay times. The shift is strongest when the rock contains small macropores that are large enough that bulk relaxation dominates over surface relaxation, but small enough that the diffusion transport time scale is faster than the bulk relaxation time scale. The simulated T2 spectra are also consistent with known facies characteristics, suggesting that modeling NMR response based on digital thin section images may be useful in quality control for NMR well log interpretation.
Trends in Cementation Exponents (m) for Carbonate Pore Systems
Deborah A. Ragland
ABSTRACT
In carbonate rocks, the cementation exponent (m) is one of the most variable parameters in the calculation of the formation factor (F) from porosity logs and, subsequently the determination of Sw. In this study, m values were calculated from laboratory-measured resistivity and porosity data and compared to thin section analyses of pore systems. Average m value for samples dominated by moldic pores is 2.46; for samples dominated by interparticle pores, the average is 1.90. For intercrystalline pore systems, the average is 1.93; and for samples with nearly equal percentages of three or more pore types, the average is 2.03. Auxiliary pore types (dissolution porosity, microporosity, microfractures) were shown to have minor to significant influence on m, depending on the abundance and variety. Two simple equations were generated from the data which can be used to more closely predict m values in moldic and interparticle systems. For moldic pore systems, m = eJ + 0.7 and for interparticle pore systems, m = (-0.44J) + 2.29; in both cases, J is percent moldic or interparticle porosity of total porosity (normalized to 100 percent) as determined from thin section. Attempts to correlate measured m values and pore types described in this study with equations derived in the past by other authors met with limited success.
Pore Geometry and its Geological Evolution in Carbonate Rocks
Y.-Q. Song, N. V. Lisitza, D. F. Allen and W. E. Kenyon
ABSTRACT
Heterogeneity of pore structures and the lack of quantitative understanding of it are one of the fundamental causes of inefficient oil recovery. The key element influencing oil flow is the connection between pores. Dissolution of calcite and other minerals is one of the major factors in geological evolution that creates complex pore geometry and connectivity in carbonate formations. We quantify pore connectivity by identifying pore bodies and connecting throats and measuring their sizes using bulk measurement techniques. Our experiments on carbonate rocks from the Bombay offshore basin in India show a consistent picture of pore space evolution due to dissolution.
Using Sonic Logs to Predict Fluid Type
W. W. Souder
ABSTRACT
The work described below is a result of testing a method published by Ramamoorthy and Murphy (1998) for identifying the type of pore fluid predominating in a high porosity carbonate rock utilizing modern sonic and porosity logs. Although the method was developed for a carbonate in the Middle East, it was found to work very well for a North Sea chalk reservoir and corroborates the technique for this particular field. The shear wave velocity and bulk density are combined to calculate the shear modulus of the formation at each depth level. The porosity and the shear modulus are related to the bulk modulus of the rock framework (rock with empty pore space) using an empirical relationship derived from laboratory measurements. Gassmann's equations (1951) are then used to compute the bulk moduli of the rock under three separate conditions: 100% water saturated, 100% oil saturated, and 100% gas saturated. These three bulk moduli are next used to compute three corresponding compression wave travel times. These three compression sonic curves are plotted in a track superimposed on the logged compression wave. The pore fluid is qualitatively identified by the position of the actual compression log relative to the three computed curves. Three field examples are shown to illustrate the technique: (1) an openhole log from 1986 prior to the arrival of the injected water; (2) logs run in 1995 in a cased well offset by approximately 200 foot distance, clearly showing high water saturation in some zones known to be swept by the waterflood, and (3) an openhole log run in 1998 in a well ahead of the water front, using a later generation sonic logging tool.
November-December
2001
Vol 3 No 6