Showing papers in "Petrophysics in 2004"

Fluid Characterization using Nuclear Magnetic Resonance Logging

Abstract: This paper presents a variety of field applications that illustrate recent advances in nuclear magnetic resonance (NMR) logging fluid characterization methods. The main concepts of NMR logging and the principles underlying NMR diffusion measurements, which form the basis for all standalone NMR fluid characterization methods, are briefly reviewed. Field examples of the MRF 2 Magnetic Resonance Fluid characterization method are presented to demonstrate the separation of oil and water signals, saturation measurements, and oil-viscosity determination. The MRF method is also applied in conjunction with new diffusion NMR techniques to infer wettability states in a suite of partially saturated core samples. The application of two-dimensional NMR maps of relaxation times and molecular-diffusion rates to identify fluids and determine their properties in complex multi-fluid environments, including oil-base mud (OBM) filtrate, light oil, and gas is illustrated with field examples from the deepwater Gulf of Mexico and the North Sea.

A Triple Porosity Model for Petrophysical Analysis of Naturally Fractured Reservoirs

Abstract: The analysis of vuggy and fractured reservoirs has been an area of significant interest in the past few years. Several researchers have studied the characterization of these reservoirs using dual porosity models and have looked for means of estimating values of the dual porosity exponent m for use in calculations of water saturation. There are instances where the reservoir is composed mainly of matrix, fractures and non-connected vugs. In these cases a triple porosity model appears more suitable for petrophysical evaluation of the reservoir. A new technique is presented for these- types of reservoirs that is shown to hold for all combinations of matrix, fracture, and non-connected vug porosities. At low porosities, the fractures dominate and the m values of the composite system tend to be smaller than the porosity exponent of the matrix (m b ). As the total porosity increases, however, the effect of the non-connected vugs becomes more important and m of the triple porosity system can become larger than m b . To the best of our knowledge a solution to the problem associated with the triple porosity exponent has not been addressed previously in the petrophysical literature. This research is inspired by the availability of modem magnetic resonance, micro-resistivity and sonic image tools that permit reasonable characterization of complex reservoirs. The use of the triple porosity model is illustrated with an example.

Conductivity Anisotropy in Shale-Free Sandstone

Abstract: The existence of conductivity anisotropy has implications for formation evaluations using Archie's model for relating formation water saturation to formation resistivity. Bulk anisotropy of sedimentary rocks can arise from the interleaving of rock units having differing electrical properties. For special core analysis, whole core is often selectively plugged in attempting to obtain homogeneous samples in the supposition that measurements taken on homogeneous samples will yield values representing typical reservoir properties. It is an article of faith that heterogeneous rocks composited from components similar to the homogeneous samples will exhibit physical properties predictably intermediate between the properties of the homogeneous samples. This is a reasonable belief that is demonstrably true for certain scalar parameters of the formation, for example porosity. Unfortunately, the direction-dependent properties of the formation do not behave in this intuitive manner. For example, we examine a two-component layered model sandstone for which the values of Archie's porosity exponent m and saturation exponent n for the composite rock have values that are very different from those of the individual components. The exact values of m and n for composite rocks depend not only upon their values of the constituent components but also upon the relative volume fractions of the components, and the orientation at which the conductivity measurements are made. Estimates of m and n in layered rocks based on simple averaging are incorrect. The theoretical results are supported by the general variability in the resistivities of samples having similar porosities in the experiment that determines m, manifest as the commonly observed scatter in the formation resistivity factor-porosity plots, and as anomalously low values of saturation exponents (n 1) often observed in aeolian sand-stones. Neglecting the existence of these effects (as has been, and is still, done) must result in a false sense of the accuracy of formation evaluations, as well as an unwarranted lack of confidence in results from the laboratory when they are in conflict with naive preconceptions of how formation properties should behave in the aggregate. A theoretical understanding of this issue must, at a minimum, improve estimates of uncertainty in formation evaluations. There is a definite (but as yet unrealized) promise that these effects can be accounted for and properly weighted in formation evaluations based upon triaxial induction logging instrument responses.

Well Log Normalization: Methods and Guidelines

Abstract: Curve normalization identifies and removes systematic errors from well log data so that reliable results may be obtained for reservoir evaluation, solving difficult correlation and seismic modeling problems It is especially critical for any work involving batch-mode computer processing The normalization equation is a function of four variables, two of which are defined for each well and two of which are related to regional lithologic patterns Well-to-well comparisons are made using histograms, crossplots, depth plots, and statistical measurements Prior publications on normalization have been individual case studies This paper describes methods that can be applied generally, and provides guidelines for their use in a variety of rock suites Also discussed are the errors that are expected for the various curve types, and suggested methods for correcting them Factors to be considered in planning a normalization project include the rock types and compaction patterns in the study area, hole rugosity, curve types, and the stratigraphic level at which run changes take place Guidelines are provided to avoid the introduction of additional inaccuracies Even with these caveats, an irreducible random error will remain in the data

Assessment of In-Situ Hydrocarbon Saturation in the Presence of Deep Invasion and Highly Saline Connate Water

Abstract: This paper describes a field study undertaken to quantify the effects of mud-filtrate invasion on resistivity induction logs. The objective. is to assess in-situ gas saturation in a low-porosity carbonate formation. A large discrepancy between the salinity of connate water and drilling mud is responsible for the presence of a substantial low-resistivity annulus in the near-wellbore region. This annulus suppresses the sensitivity of electromagnetic induction currents to detecting gas saturation in the virgin zone. A quantitative explanation for the presence of the low-resistivity annulus is presented based on the physics of mud-filtrate invasion. The process of mud-filtrate invasion is modeled with a two-dimensional chemical flood simulator that includes the effect of salt mixing between mud filtrate and connate water. Radial resistivity profiles are obtained from the simulated spatial distributions of water saturation and salt concentration using Archie's law. These profiles confirm the presence of the low-resistivity annulus in the transition region between the flushed and virgin zones. Numerical simulation of induction logs validates the agreement between the mud-filtrate invasion model and the available wireline induction logs. An extensive sensitivity analysis is performed to quantify the effect of several petrophysical parameters on the spatial distributions of water saturation and salt concentration. Results from this study show that the pre-annulus and annulus segments of the radial resistivity profile remain insensitive to initial water saturation, thereby impeding the estimation of in-situ gas saturation from resistivity induction logs alone. Modeling of the process of mud-filtrate invasion is the only possible way to estimate in-situ hydrocarbon saturation from induction logs. It is also found that laterolog measurements are only marginally affected by the presence of a low-resistivity annulus. The sensitivity analysis described in this paper provides a rigorous quantitative method to assess the effects of different types of muds on the invaded zone prior to drilling.

Impact of SCAL (Special Core Analysis) on Carbonate Reservoirs: How Capillary Forces Can Affect Field Performance Predictions

Abstract: Accurate capillary pressure data in both drainage and imbibition cycles can be essential for understanding hydrocarbon reservoir performance. Drainage capillary pressure is usually used to initialize reservoir static models, i.e., to determine initial saturation as a function of height above free water level and to calculate hydrocarbon volumes in place. However, imbibition capillary pressure is often not used correctly to model fluid flow in displacement studies. This is often due to a general lack of reliable experimental data to cover the predominant rock types during reservoir studies or the perception that effect of capillary force might become insignificant once production commences. In this paper we examine the effect of capillary forces, in addition to viscous and gravity forces, on sweep efficiency of immiscible displacement in a heterogeneous porous medium at different wetting conditions. Capillary pressure curves have been measured using core materials from a heterogeneous Cretaceous carbonate reservoir in the Middle East. The core plugs were selected from different rock classes to cover a range of permeability from 0.1 to 1000 mD. Capillary pressure data were obtained in primary drainage and imbibition after aging the plugs at connate water saturation to restore wettability. The results show, for the case under study, that there is a subtle balance between viscous, gravity and capillary forces during oil displacement. Ignoring any of these forces, especially for non-water-wet heterogeneous reservoirs, could lead to erroneous prediction and sub-optimal field development planning. The study shows that for the subject carbonate reservoir, water-flood recovery is strongly dependent on the shape of the imbibition capillary pressure curves.

Fast 3D Modeling of Borehole Induction Measurements in Dipping and Anisotropic Formations using a Novel Approximation Technique

Abstract: Macroscopic electrical anisotropy of rock formations can substantially impact estimates of fluid saturation performed with borehole electromagnetic (EM) measurements. Accurate and expedient numerical simulation of the EM response of electrically anisotropic and dipping rock formations remains an open challenge, especially in the presence of borehole and invasion effects. This paper introduces a novel efficient 3D EM approximation based on a new integral equation formulation. The main objective of this approximation is to simulate the multi-component borehole EM response of electrically anisotropic rock formations. Firstly, the internal electrical field is expressed as the product of spatially smooth and rough components. The rough component is a scalar function of location, and is governed by the background electric field. A vectorial function of location is used to describe the smooth component of the internal electric field, here referred to as the polarization vector. Secondly, an integral equation is constructed to describe the polarization vector. Because of the smooth nature of the polarization vector, relatively few unknowns are needed to describe it, thereby making its solution extremely efficient. One of the main features of the new approximation is that it properly accounts for the coupling of EM fields necessary to simulate the response of electrically anisotropic rock formations. Tests of accuracy and computer efficiency against 1D and 3D finite-difference simulations of the EM response of tri-axial induction tools show that the new approximation successfully competes with accurate finite-difference formulations, and provides superior accuracy to that of standard approximations. Numerical simulations involving more than 10 6 discretization cells require only several minutes per frequency and instrument location when performed on a Silicon Graphics workstation with a 300 MHz, IP30 processor.

The Effect of Scale on the Petrophysical Estimation of Intergranular Permeability

Abstract: An examination of empirical relationships for predicting permeability from porosity has revealed a significant scale dependence that has to be accommodated if integrated reservoir studies are to secure maximum benefit. If this is not done, the predicted permeability can be seriously in error. for example, case histories show that predicted permeability can be less than 50% of the benchmark value if a porosity-permeability relationship established at the core scale is indiscriminately applied to well logs. The errors are governed by the reservoir character, e.g. cyclically or monotonically distributed reservoir properties: they depend to a lesser extent on the way in which log-response information is used in defining the upscaling procedures. The errors increase where a permeability algorithm established at the core scale is indiscriminately applied at the grid-cell and reservoir zonal scales. A matrix of normalized cross-scale errors, generated by benchmarking against known permeability values, has allowed the effects of indiscriminate scale transgression to be quantified and compared for different situations. The resulting errors in permeability, as predicted from porosity, range from about -80% for indiscriminate transgressions upscale to around 400% for transgressions downscale. These observations have stimulated the development of procedures for using groundtruthing core data to estimate permeability at the well-log, grid-cell and zonal scales. Predictive relationships established at each of these scales can be markedly different and therefore they must be applied in a manner that is fit-for-purpose. This means that different predictive algorithms can legitimately co-exist. Where this is done, there is a marked reduction in the number of iterations required to generate an internally self-consistent reservoir model. In other words, a fit-for-purpose application of petrophysics leads to a greater synergy between the static and dynamic components of the reservoir model.

Two-Phase Flow Rock Typing: Another Approach

Abstract: Petrophysical units, also called rock types, are usually defined to help the reservoir engineers assign petrophysical characteristics to different zones of a reservoir. Estimation of initial hydrocarbons in place accounts for such petrophysical units, which are usually generated, using both single-phase data (i.e. porosity, permeability) and two-phase drainage data (i.e. capillary pressure curve) and coupled with sedimentological descriptions. It is then frequently assumed that these rock types are valid for assigning two-phase flow characteristics, such as relative permeability curves, to a reservoir, whatever the recovery process. This paper shows that this assumption is often incorrect, using several field examples, including sandstone and carbonate reservoirs. Based on a large number of core flood results, it is shown that the usual rock typing methods may not capture the actual variability of relative permeability curves. It is also shown that: 1) Multivariate descriptions, including petrophysical characteristics and wettability indicators, should be the basis for the generation of multiphase flow rock types. 2) Two-phase flow rock types should be dependent on the recovery process. Consequences on sampling for coreflood programs, as well as inputs of simulation models, are pointed out.

Joint inversion of transient-pressure and time-lapse electromagnetic logging measurements

Abstract: We develop a novel algorithm for the integrated petrophysical evaluation of hydrocarbon-bearing formations using dual-physics measurement data. Specific data sets used in this paper are (a) time-lapse electromagnetic (EM) measurements acquired with an array induction logging tool, and (b) transient-pressure measurements acquired with a multi-probe wireline formation tester in a vertical borehole. Dynamic behavior of saturation and salt concentration distributions due to mud-filtrate invasion creates a two-phase three-component flow system. In this work, the inverse problem associated with dual-physics wireline measurements consists of the estimation of a two-dimensional (2D) axisymmetric petrophysical model described by the layered parametric spatial distribution of both vertical and horizontal absolute permeabilities and porosities. We pose the inverse problem of estimating layer petrophysical parameters from discrete time-lapse EM induction and transient-pressure measurements as an optimization problem. A weighted least-squares constrained optimization method is employed to solve the inverse problem. Tool responses within the framework of the iterative inversion scheme are numerically computed via simulating dynamic physics of two-phase three-component flow that takes place during mud-filtrate invasion and subsequent formation testing. Time-lapse EM induction measurements are simulated in a coupled mode to the fluid flow. A conductive annulus is observed in all cases. Numerical examples have shown that the benefit of the joint inversion algorithm described in this paper is in the reduction of the nonuniqueness associated with the estimation process by simultaneously honoring two sets of complementary measurements that contain independent information about the underlying model.

Joint inversion of acoustic and resistivity data for carbonate microstructure evaluation

Abstract: We propose a technique for the determination of the type and value of secondary porosity for carbonate formations. This technique consists in the joint inversion of the acoustic velocities and the electrical resistivity, and it is based on a unified microstructure model. For simulating the elastic and electrical properties the symmetrical effective media approximation (EMA) is applied. The secondary porous system is considered as a set of inclusions placed into the homogeneous isotropic matrix with the primary porosity. The matrix corresponds to the solid frame composed of mineral grains and primary pores saturated by conductive fluids. The grains, primary and secondary pores are approximated by three-axial ellipsoids with different aspect ratios. The variation of the aspect ratios of secondary inclusions allows different pore types such as vugs and cracks to be described. The inversion procedure consists in minimizing the difference between the measured and predicted parameters (acoustic velocities and electric conductivity) that are calculated as functions of the primary and secondary porosities as well as the aspect ratios of the ellipsoidal secondary pores. We applied the joint inversion technique for the experimental core and well log data to distinguish and evaluate the vuggy and cracked carbonate formations in the South zone of Mexico.

Fast 3D Imaging from a Single Borehole Using Tensor Induction Logging Data

Abstract: There is growing interest in the development of new borehole electromagnetic (EM) induction methods capable of characterizing the conductivity distribution in the space surrounding the borehole. The main goal of this paper is to develop a method of three-dimensional (3-D) imaging from a single borehole using a tri-axial (tensor) induction instrument. The tensor instrument has a directional sensitivity, which allows finding the correct location of the 3-D resistive and conductive targets from single-hole data. Our method is based on the novel localized quasi-linear (LQL) approximation. The LQL approximation is specially designed for modeling the electromagnetic field generated with a moving transmitter, which is the case for borehole induction logging. The traditional approach to electromagnetic modeling and inversion requires multiple solutions for different transmitter positions. The LQL approximation makes it possible to run the forward and inverse problem at once for all the transmitters, which makes the inversion of the well-logging data much more efficient. Our study demonstrates that this method can be effectively used for 3-D imaging from a single borehole.

Porosity from neutron logs. II: Interpretation

Abstract: This second tutorial on neutron porosity logging is part of an ongoing series on the general topic of porosity being published in Petrophysics. Part 1 dealt with the physics of the measurement and introduced a generic thermal neutron tool whose response was studied in detail with a Monte Carlo model. Its empirical response to porosity was shown to be related to a macroscopic parameter of the formation - the slowing-down length. In this section the three major tool perturbations-lithology, shale, and gas-are examined and explained. Some typical log formats are shown, and the use of the neutron/density crossplot is illustrated. The paper concludes with a short discussion of the LWD tool and its depth of investigation.

Electrofacies and permeability modeling in carbonate reservoirs using image texture analysis and clustering tools

Abstract: The continual development of the oil industry has led to a significant increase in the number of wells to be simultaneously analyzed, and to a need for geological integration in order to improve the understanding of reservoir properties, heterogeneities and distributions. It is therefore important to develop interpretation methods that facilitate and improve the integration of all well information at different scales, while reducing the amount of time necessary for each study. Porosity is a key parameter for characterizing a reservoir interval. Nevertheless, a simple porosity value which can be confidently estimated using conventional logs is not sufficient for a complete evaluation in complex reservoirs. An understanding of the porosity network or geometry is also needed as it drives permeability and therefore the dynamic properties of the reservoir. This paper investigates the integration of electrical borehole images (EBI) with other conventional logs for reservoir facies and permeability modeling in carbonate reservoirs. Due to its high resolution, electrical borehole imaging can provide important information concerning sedimentology and porosity distribution, e.g. the identification of vuggy porosity previously described by cores. A powerful step-by-step method has been developed which aims to reproduce the vertical geological heterogeneity. In a first step, different groups of data are processed to produce an e-facies classification driven by core description. The types of information used are: lithofacies modeled by clustering tools using conventional logs, automated image texture classification and automated bedding/structural feature-extraction from the EBI. In a second step, a permeability model is built based on the resulting e-facies, integrating textural information, available petrophysical measurements and wireline logs. The model aims to predict permeability even when the relationship with porosity does not fit a simple law.

Temperature Dependence of Wettability Related Rock Properties Correlated by the Arrhenius Equation

Abstract: Application of the Arrhenius equation is extended and demonstrated for correlation of the temperature effect on wettability-related properties of rock In addition, it is verified with experimental data, including the capillary pressure, unfrozen water content, wettability index, and CT (computed tomography) number relating to fluid saturation in porous media The temperature dependence of the wettability indices of uniformly water-wet Berea sandstone cores saturated with various oils is correlated successfully This paper is not concerned with the alteration of wettability by chemical and physico-chemical processes due to temperature effects Rather, it provides meaningful correlations for the effect of temperature on various wettability state-related rock properties The correlation with the Arrhenius equation provides useful information about the activation energy requirements associated with the imbibition and drainage processes involving the flow of immiscible fluids in porous rocks The exercises provide ample evidence of the applicability of the Arrhenius equation for correlating the temperature dependency of the wettability state on the petrophysical behavior in porous formations It is concluded that the Arrhenius equation yields a phenomenologically meaningful correlation of the experimental data

Visualization of Three Phases in Porous Media using Micro Computed Tomography

Abstract: Three-phase flow in porous media is a common phenomenon in hydrocarbon reservoirs. This study presents quantitative maps of fluid distribution in a granular porous medium using micro computed tomography (MCT). The study was done in an effort to determine the position, distribution and saturation of each phase at the pore-scale level. Quartz sand was used as the porous media. The fluids used were water (doped with NaI), benzyl alcohol (BA) and decane (doped with iodo-dodecane). The three fluids and the solid phase were mapped in images that were acquired at a single energy setting. Single-phase, two-phase and three-phase saturation distributions were developed. The intermediate phase was detected by direct observation of the phase distribution in the porous medium thus confirming calculations using interfacial tensions and the spreading coefficient. The results obtained from this research showed that micro computed tomography (MCT) is a useful technique to study multi-phase flow mechanisms in porous media. This work provided three-dimensional maps of fluid saturations at the pore level and should allow the reconsideration and adjustment of pore-scale modeling. This method provides the possibility to obtain three-dimensional saturation data that can be used for simulator development and calibration of models.

Correcting for Tool Decentralization of Oriented Six-Arm Caliper Logs for Determination of Contemporary Tectonic Stress Orientation

Abstract: Tool decentralization is a major problem in the analysis of six-arm caliper data, particularly in highly deviated wells. It precludes accurate determination of borehole geometry and hence, interpretation of borehole volume, stratigraphic horizons and present-day stress orientation. We test four methods for correcting tool decentralization of six-arm caliper data, for the primary purpose of interpreting present-day stress orientations from borehole breakouts. The ''chord approach'' and ''ellipse algorithm'' yielded the most accurate corrections for tool decentralization in real and modeled scenarios of breakouts, key-seats and in-gauge holes.

Automated Interpretation For Lwd Propagation Resistivity Tools Through Integrated Model Selection

Abstract: Petrophysicists often have difficulty interpreting logs from today's multispacing, multifrequency logging-while-drilling (LWD) propagation resistivity tools. Which of the many resistivity curves represents the true formation resistivity? The logs may be affected to varying degrees by Borehole effect, tool eccentering, shoulder-bed effects, fractures, invasion, anisotropy and/or dielectric effects. These effects may occur individually, or multiple effects may be present in the same zone. Identifying these effects and correcting for them is challenging, especially when conclusions are needed quickly. Much of the information required to answer these questions is contained in the array measurements themselves. This paper presents a general automated scheme that can help analysts to identify environmental effects and to select the appropriate environmentally corrected formation resistivity. It answers the key question of how to select the correct model amongst many candidates, based primarily on inversion of the tool response and possibly other additional information. The key idea is to invert different formation models that may apply and select the one most consistent with the measurements of the tool and with auxiliary data from user inputs and/or other logs. When a dominant effect is identified, the correction is applied automatically, the relevant environmentally corrected data are generated, and confidence of interpretation is assigned. When none of the models result in an adequate fit, the data are flagged to indicate that an automatic interpretation could not be made because of more complicated or compounded environmental effects. In addition, petrophysicists can accept or reject certain models and impose petrophysical constraints to improve the interpretation. The program based on this approach has been used to process field logs with diverse formation characteristics, and it has been evaluated by experienced petrophysicists. The program includes borehole, invasion, dielectric, and anisotropy models in its model-base. Results show that the algorithm successfully identifies most environmental effects and highlights zones that need further analysis because of complex or compounded effects. The benefits of such an integrated-interpretation-through-model-selection approach will be demonstrated through four field log examples. Availability of these results at the wellsite is expected to improve both the timeliness and the quality of decisions made based on resistivity data.

Application of NMR Diffusion Editing as Chlorite Indicator

Abstract: We present a nuclear magnetic resonance (NMR) based study on a series of sandstone cores from a major reservoir in the Norwegian Sea. The cores have varying amounts of chlorite and were prepared in different saturation states. NMR measurements were performed using the standard Carr-Purcell-Meiboom-Gill (CPMG) pulse sequence and the new diffusion editing method that is designed to separate diffusion and relaxation effects. This procedure generally results in more reliable S w values and we demonstrate here that it can also be used to derive an indicator of chlorite content. Since the measurement of diffusion editing can be performed with logging tools, this technique can be used directly in a reservoir for the improved determination of saturation and to estimate the chlorite content, with important implications for the assessment of reservoir quality. When the samples were saturated with a mixture of refined oil and brine, it was generally difficult to separate the contributions of the two phases in the CPMG relaxation measurements. The relaxation time of the oil often overlapped significantly with the T 2 distribution of the brine signal. To overcome this problem, we used the technique of diffusion editing to obtain simultaneously diffusion and relaxation information and its correlation. This was achieved by preceding the standard short-echo-spacing CPMG sequence by an editing sequence that attenuates the amplitude of the signal according to diffusion in the applied gradient. In the current work, we implemented the diffusion editing by increasing the first two echo spacings systematically. Relaxation information is obtained from the signal decay after the diffusion encoding. This effectively orthogonalizes the diffusion and relaxation information and allows the extraction of diffusion - relaxation distribution functions. These two-dimensional D - T 2 maps can be used to extract information about important reservoir parameters such as water saturation, oil viscosity, wettability state and hydrocarbon-corrected bound-fluid volume. For the samples with low chlorite concentration, the diffusion - relaxation distribution functions clearly separated the signal into oil and water contributions. For samples with higher chlorite concentrations, the D - T 2 maps showed an additional significant contribution at apparent diffusion coefficients in excess of bulk oil or water. In these samples, the presence of chlorite gives rise to internal gradients in the adjacent pore space that exceeds the externally applied gradient. This leads to an increased diffusive decay that can be characterized by a large apparent diffusion coefficient. We found that the chlorite concentration in the sample is correlated with the fraction of signal that exhibits such large apparent diffusion coefficients.

Geosteering using Ultradeep Resistivity on the Grane Field, Norwegian North Sea

Abstract: The Grane field consists of massive, homogeneous marine turbidite sandstones with excellent reservoir properties. The hydrocarbon contained in the reservoir has high density (21°API) and viscosity (12 cp), and hence an extended transition zone height of about 25 m (from OWC to S wirr ). The reservoir topography and drainage strategy impose certain geosteering challenges including landing and drilling production wells at a fixed distance above the oil-water contact (OWC), or as close to the bottom of the reservoir as possible in areas where the base reservoir is above the OWC. Similarly, gas injectors need to be drilled as close to the top of the reservoir as possible. The appraisal wells indicated consistent resistivity and saturation profiles, and geosteering based on resistivity vs. height functions was planned. However, the actual experience showed that the height above the OWC derived from LWD resistivity data was variable and often inconsistent with the suryey data. The likelihood that this was caused by subtle facies variations, anisotropy or local variations in the OWC meant that an alternative measurement on which to base geosteering decisions was needed. To meet this need Schlumberger developed the VDR (deepVision Resistivity tool) in collaboration with Norsk Hydro. The tool has the ability to detect resistivity-contrast boundaries tens of meters from the wellbore. Thus, it allows wells to be drilled at fixed distances above the OWC, while shales approaching from above and below the well path can be detected and avoided. If a shale is penetrated, the tool is able to indicate distance back to sand. The VDR data can also aid in detecting and calibrating drifting survey data, in sidetrack planning and in geomodel updating. The ability to avoid shale adds direct value by increasing the length of production intervals in the wells.

MWD siren pulser fluid mechanics

Abstract: Three-dimensional flowfields concerning mud sirens used in Measurement-While-Drilling (MWD) are studied using a comprehensive inviscid fluid-dynamic formulation that models the effects of key geometric design variables on rotor torque. The importance of low torque on high data rate telemetry and operational success is discussed. Well known field problems are reviewed and aerodynamically based solutions are explained in detail. Both problems and solutions are then studied numerically and the computer model - developed using flow concepts known from aerospace engineering - is shown to replicate the main physical features observed empirically. In particular, the analysis focuses on geometries that ensure fast stable-opened rotary movements in order to support fast data transmissions for modern drilling and logging operations. This paper also addresses erosion problems, velocity fields, and streamline pattern in the steady, constant density flow limit. Studies related to drillpipe mud acoustics, signal propagation and telemetry, where fluid compressibility is important, will be presented separately.

Improved log analysis in shaly-sandstones-based on Sw and hydrocarbon pore volume routine measurements of preserved cores cut in oil-based mud

Abstract: Routine measurements of properly preserved cores cut in oil-based mud (OBM) give accurate porosity (Φ) and water saturation (S w ) values in hydrocarbon reservoirs. Above mobile water zones the Hydrocarbon Pore Volume (HPV) of these OBM cores is usually accurate in both clean and shaly sand reservoirs. HPV evaluations from the 'core' and the 'total' and 'effective' porosity systems must all be the same: HPV = Φ core (1 - S wcore ) = Φ t (1 - S wt ) = Φ e (1 - S we ), where the subscripts denote the specific system being addressed. In shaly reservoirs, core porosity (Φ core ) and total porosity (Φ t ) may be larger than effective porosity (Φ e ), with the extra porosity being generated from the drying of the clay minerals, especially smectites. The water volumes measured by Dean-Stark extraction of OBM core plugs includes this clay-bound water, so OBM Φ core and S wcore used together as a pair give an accurate evaluation of HPV. Example core and log data from a shaly-sand formation are evaluated using several well-known log analysis models. As tested, the Dual-Water, Cyberlook and Indonesia models all provide quite similar S w results and agree fairly well with the OBM S wcore corrected to reservoir conditions Because the standard Cyberlook and Indonesia S w results are close to S wt , they are paired with total porosity for HPV calculations. They have previously been thought to give S we , not S wt, and have been paired with 'effective' porosity giving pessimistic HPV results. The Archie total porosity model also gives useful, but pessimistic, results. The Archie effective porosity model gives very pessimistic S w and HPV results in shaly sands. The most accurate evaluation method, the OBM core analysis, can be used to calibrate current resistivity-S w models for shaly sands. This process leads to improved estimates of oil- and gas-in-place and, potentially, to improved shaly-sand models for application in worldwide log analysis.

A Comparison Of Logging-While-Drilling And Wireline Nuclear Porosity Logs In Shales From Wells In Brazil

Abstract: Variations between logging-while-drilling (LWD) and wireline neutron logs in shales were studied from six wells in Brazil. Since only small variations were observed in the respective density logs, the neutron differences were not attributed to environmental changes during the time elapsed between LWD and wireline measurements. Monte Carlo simulations for clay minerals show that the large-diameter LWD neutron porosity response is generally lower, and closer to the true hydrogen content, than wireline thermal neutron tools. The LWD and wireline logs confirm this trend in shales. The large amount of steel in the LWD tools reduces the number of detected low-energy (thermal) neutrons and results in the detectors seeing a larger fraction of higher-energy (epithermal) neutrons than conventional wireline tools. Since epithermal neutrons are less sensitive to the strong neutron absorbers found in shales, the LWD tools read lower neutron porosities than wireline in shales. The neutron response in shales is also affected by source-to-detector spacings, and LWD spacings often differ from wireline. Larger LWD neutron tools will read closer to the true hydrogen content of the shales than smaller LWD neutron tools.

NMR Application in Reservoirs with Complex Lithology: a Case Study

Abstract: Nuclear Magnetic Resonance (NMR) logging has developed into a powerful reservoir characterization tool and was recently applied in the West Siberia basin, Russia. NMR typically is represented as a lithology-independent measurement of porosity, because hydrogen in the rock matrix does not contribute to the signal. Both the rock matrix and the cement composition, however, seriously influence the tool's response. We present four cases of NMR log response in reservoirs with complex lithology: . Weathered-crust volcaniclastic conglomerates and coarse-grained sandstones, with an apparent shift in T 2 distribution of the free-fluid index (FFI) towards faster components, placing it below 33 ms because of a large amount of finely dispersed iron material; . Fore-reef clastics composed of quartz sandstones with well-developed kaolinite cementation, low surface relaxivity, and bound water in the 33 to 128 ms range; . Slump and debris-flow deposits with a complex mixture of clastic, carbonate material, and organic matter that results in variations of surface relaxivity, possible oil-wetting, and a general shift of T 2 distribution towards the bound-fluid interval (3 to 33 ms); . NMR- hostile environments related to the black shales and the continental Tyumen formation. Excessive amounts of the iron-rich minerals leucoxene, pyrite, and siderite, which are associated with coals, and the presence of plant fragments and bitumen inclusions effectively kill the NMR signal.

Logging-While-Coring- First Tests of a New Technology for Scientific Drilling

Abstract: A newly developed logging-while-coring system was deployed and tested during Ocean Drilling Program Legs 204 and 209 on Hydrate Ridge off the coast of Oregon and on the Mid-Atlantic Ridge. The system consists of two existing devices modified to be used together-a Schlumberger Resistivity-at-the-BitTM tool and a Texas A&M University wireline-retrieved core barrel and latching tool. The combination allows for precise core-log depth calibration and core orientation within a single borehole, and without a pipe trip. These tests during Leg 204 and Leg 209 mark the first simultaneous use of coring and logging-while-drilling technologies. The first test was conducted in 788.5 m (2586 ft) water depth at the crest of southern Hydrate Ridge (Site 1249) in clay-bearing sediments. Eight cores were recovered from Hole 1249B with 32.9% recovery, on average, through an interval from 30-75 m (98-246 ft) below the seafloor and as high as 67.8% recovery in one core (Bohrmann et al., 2003). All eight cores were processed and archived on board the D/V JOIDES Resolution following normal ODP core handling protocols (Ocean Drilling Program, 1999). High resolution logs and image data were recorded in the downhole tool memory over the entire 74.9 m (245 ft) drilled interval. The log data were processed post-cruise and correlated to recordings of conventional logs in nearby Hole 1249A. The logging-while-coring system was also deployed in lower crustal (Kelemen et al., 2004, in press) in a 20-meter (65 ft) deep hole during ODP Leg 209. It is expected that the logging-while-coring systems will be utilized more routinely at other drilling locations, where rig time constraints may otherwise preclude coring in difficult drilling environments.

Depressurization under tertiary conditions in the near-wellbore region: experiments, visualization and radial flow simulations

Abstract: Depressurization can be a very interesting process for recovering hydrocarbons from waterflooded oil reservoirs with high gas-oil ratio. Most of the published results are related to depletion experiments under secondary conditions (virgin reservoir). Data are more scarce under tertiary conditions after waterflooding (Ligthelm et al., 1997; Grattoni et al., 1998; Naylor et al., 2000). This paper treats the issue of the depressurization under tertiary conditions in the near-wellbore region. Practically, this has been achieved by combining experimental results, obtained from both core and a transparent micromodel, with radial flow depletion simulations that are representative of the conditions prevailing in the near-wellbore region. A validated methodology previously presented (Egermann and Vizika, 2000) has been used to design the experiments on core (the core under tertiary conditions was continuously flushed with water at a fixed rate, while the pressure at the outlet was decreased to reproduce a drawdown). The saturation profiles, the pressures and the fluid productions as a function of time were recorded in the two experiments that are presented. From the core experiments, critical gas saturation (S gc ) and relative permeability (k r ) have been determined using a specific simulation code that takes into account nucleation, diffusion and mobilization processes related to the appearance of the gas phase from solution. Constant depletion rate experiments were also conducted on a transparent micromodel to study the process of connection of the gas phase under tertiary conditions. The specificity of the near-wellbore region (high dP/dt and radial flow) was then investigated by conducting a numerical experiment with radial geometry. It is shown that gas relative permeabilities obtained under tertiary conditions are lower than the ones obtained under secondary conditions. This behavior is attributed to the double connection process that is needed for the gas to get mobilized: connection of the disconnected oil phase and connection of the gas phase itself. This phenomenon is also confirmed by the visualization experiments conducted on the micromodel. The numerical experiment representative of the near-wellbore conditions with a radial geometry demonstrates that S gc is a function of the distance to the wellbore, which can have a large impact on reservoir simulation results.

Improved Density Logging in Hot, Rugose Carbonate Formations

Abstract: The Canadian Rockies are a difficult logging environment because of elevated borehole temperatures (greater than 125°C in some of the deeper formations) and large anisotropy in the stress field that results in elliptical or rugose boreholes. This field case study focuses on the Saddle Hills area in northern Alberta, close to the Peace River Arch, where unexpected density responses were observed while logging the Wabamun carbonate formation. The responses included overcorrection of the density in bad holes and higher-than-expected bulk density and photoelectric factor (PEF) measurements from the Platform Express* integrated triple-detector density wireline logging tool in several wells. Anadarko and Schlumberger personnel investigated the cause of the unexpected readings by reviewing all tool maintenance and calibration procedures, and conducting tool-positioning experiments in calibration blocks that were validated with tool modeling. As a result, the density and PEF measurements can now be used quantitatively, greatly adding to the ability of the geoscience teams to evaluate these complex carbonate formations.

Characterization of the Intrinsic Porosity Exponent through Dual-salinity Measurements of Electrical Conductivity

Abstract: Dual-salinity measurements of electrical conductivity allow the identification of a petrofaciesspecific intrinsic porosity exponent m* without having to determine any shaly-sand parameters. The method requires measurements of the conductivity of a reservoir rock when it is fully saturated with two different electrolytes of known conductivity. The method has been tested and benchmarked for sands ranging from clean to very shaly. It is not significantly impacted by lowsalinity effects in most oilfield situations. A key element of the approach is that the pairs of electrolyte conductivities do not have to be the same for each sample. This is especially useful where a database covers several generations of core analysis. Field examples illustrate how the dualsalinity method can be used to quantify m* and identify petrofacies units simultaneously. The method requires fewer data than traditional multiple-salinity conductivity studies and it is more definitive than approaches that use an electrochemical measurement of the non-Archie conductivity. In these respects the dual-salinity approach offers a balance between the cost of data acquisition and the need to contain uncertainty.