Wireline Measurements Research Articles

Gamma ray spectrometric analysis of hydrothermally altered dacite samples from the PACMANUS hydrothermal field: Implications for the interpretation of gamma ray wireline measurements

Spectral gamma ray wireline logging derives the concentrations of potassium, thorium, and uranium of the formation by measuring the gamma ray spectrum under the assumption of secular equilibrium. These measurements were carried out in a number of boreholes drilled by Ocean Drilling Program Leg 193 at the PACMANUS hydrothermal field. Spectral gamma ray logs from several of these holes show intervals of increased radioactivity, associated with high uranium values of up to 60 ppm (Snowcap hydrothermal field) and 25 ppm (Roman Ruins hydrothermal field). Nine samples of hydrothermally altered dacite were analyzed using gamma spectrometry to examine the origin of elevated radioactivity and to test for distortion of secular equilibrium. Core spectrometry indicates that secular equilibrium is distorted. Distortion can be explained by either an uptake of nuclides of the lower part of the 238U decay series, or by removal of 238U or 234Th from the rocks. In all cases wireline uranium logs and core spectrometry do not reflect true uranium concentrations of the formation but uranium is overestimated by a factor of 3–4. At Roman Ruins, uranium values from wireline logging show higher uranium concentrations over large intervals than uranium values from core spectrometry and from published core geochemistry, even when a possible leaching of uranium is taken into account. Wireline logs indicate that depth intervals of increased radioactivity are related to the occurrence of stockwork mineralization. In these depth intervals, core recovery was extremely low. In addition to the distortion of secular equilibrium, low core recovery and preferential loss of softer and more altered material cause a sampling bias between core samples and wireline data and may explain the observed difference in uranium concentrations between core and wireline logs.

Reservoir Crude-Oil-Viscosity Estimation From Wireline-NMR Measurements - Rajasthan, India

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 101689, "Reservoir Crude- Oil-Viscosity Estimation From Wireline- NMR Measurements-Rajasthan, India," by R.J. Zittel, SPE, D. Beliveau, SPE, T. O'Sullivan, SPE, and R. Mohanty, Cairn Energy India Ltd., and J. Miles, Oil Optimizers Ltd., prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24- 27 September. In 2004, the Mangala, Aishwariya, and Bhagyam fields were discovered in Rajasthan, India. Oil viscosity is a main factor controlling performance from these high-permeability paraffinic reservoirs. Pressure/volume/temperature (PVT) data indicate areal and vertical variations in crude-oil properties. Meter-by-meter geochemical core data corroborate vertical variations in oil composition. Continuous wireline measurements of nuclear-magnetic-resonance (NMR) log properties and station NMR properties from wells drilled with water-based mud or synthetic-oil-based mud also were used to calculate a viscosity profile. This study correlated results from all techniques and showed how NMR measurements can provide oil-viscosity profiles in compositionally complex pools. Introduction Oil viscosity was estimated for the Mangala and Aishwariya fields by use of a variety of wireline data and methods. The objective was to investigate and use correlations between wireline and laboratory NMR measurements and in-situ PVT properties (especially oil viscosity) measured on oil samples collected from the fields. Further, correlations were made with geochemical analyses taken from field cores. The result was estimation of in-situ oil viscosity as a function of depth in the wells where appropriate data were available, along with fieldwide correlations of viscosity as a function of height above the oil/water contact (OWC). One desirable property of these viscosity estimates would be that they have the same depth resolution as the wireline-log data from which they were derived. The available data were from routine suites of wireline logs, NMR logs, station NMR measurements, PVT properties measured on reservoir-oil samples, and detailed geochemistry data. Estimating In-Situ Oil Viscosity The empirical relationship represented by µoil=4(T+273.16)/T2 between crude-oil viscosity, µoil (in centipoise), and the logarithmic mean of the measured T2 relaxation-time distribution of the oil, was derived from data for a variety of crude oils and has been demonstrated in industry literature. In this algorithm, T2 is the logarithmic mean of the NMR-T2 distribution of the bulk oil and T is the temperature in degrees Celsius. Laboratory measurements of the T2 distribution of bulk oil from drillstem tests were studied. Data acquired in Mangala, Bhagyam, and Aishwariya fields led to the speculation that crude-oil viscosity might be estimated from the continuous wireline NMR-T2 distribution data by use of an adaptation of the Kleinberg-Vinegar algorithm. A distinct peak in the distributions that occurs near 150 milliseconds apparently is caused by the oil in the reservoir having little or no influence from the water fraction. It was recognized that this peak was unlikely to represent the bulk-oil response, completely uncontaminated by diffusion and other effects, so it would be necessary to calibrate the results of the Kleinberg-Vinegar computation to the in-situ viscosities from PVT analyses on samples of the field crude oils.

Q&A with Sami Iskander

Oil prices, profits, and capital spending are on the rise, and future hydrocarbon demand appears robust. Do you expect the industry to enjoy a sustained boom? All indicators point to a sustained period of strong activity. Two things are key. First, the industry must add production capacity to meet increasing demand. Second, it must also replace production lost to the decline of the aging production base. With E&P spending increasing to record levels, with only a thin margin existing of excess supply over demand, and with oilfield services' human and equipment resources stretched, we see no immediate drop in activity. How have the sustained high oil prices affected Schlumberger's business and operations? Last year set new records for Schlumberger activity as the price of oil allowed the E&P industry to increase spending. This year looks even stronger as more companies return to exploration-type work, and this is of particular significance to us because we have a wide range of technologies well suited to exploration, such as the Scanner family. What is the significance of the Scanner family of wireline measurements introduced late last year? The Scanner family is a step change in technology and in the benefits it brings to how our clients populate reservoir models with their data. What kind of field test results have you had thus far? Results have been great in a wide range of applications for each technology worldwide. Client acceptance has been very encouraging, and the number of case studies is growing. Where do you see its main applications? Scanner applications are numerous throughout all the oil and gas upstream processes. The Rt Scanner runs with our Platform Express service in standard induction applications, with its major advantages apparent in thin beds, low-resistivity pay, and high-formation-dip environments. The Sonic Scanner is a service applicable to nearly every oilfield discipline: meeting geophysical challenges, detecting anisotropy accurately as low as 2%, delivering a clear understanding of formation-integrity issues likely to happen during production, and allowing completion engineers to make the best decisions on their completion and fracture designs. MR Scanner provides nuclear-magnetic-resonance measurements to help resolve petrophysical challenges in a variety of environments, including unknown or varying salinities, low-resistivity or low-contrast pay zones, and/or thin beds. This is made possible using a single pass with multiple depths of investigation. MR Scanner provides detailed formation evaluation of the near-wellbore region, fluid identification, and in-situ hydrocarbon characterization. In Middle East carbonate reservoirs, which are normally difficult to interpret using conventional resistivity techniques, the MR Scanner service has clearly distinguished hydrocarbon-bearing zones from the water zones by use of patented interpretation techniques. What other technologies are you working on that will address key production issues facing the industry? To address the pressing production issues, we are launching two new cased-hole Scanner technologies: the Isolation Scanner and Flow Scanner. The next-generation zonal-isolation evaluation service is the Isolation Scanner for the latest lightweight and foam cements as well as traditional and heavy weight cements. It measures radially and deeper toward the formation, confirming zonal isolation, pinpointing channels in the cement, and ensuring confident squeeze or no-squeeze decisions. Because of its increased depth of investigation, the Isolation Scanner also provides detailed information about casing and casing-within-casing eccentralization, allowing for better identification of whipstock locations for sidetracking, while its internal-diameter and thickness measurements identify corrosion and drilling-induced wear.

LWD for Imaging, Wellbore Placement, and Formation Evaluation

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 17646, "LWD for Imaging, Wellbore Placement, and Formation Evaluation," by J.C. Rasmus, SPE, C. Esmersoy, SPE, J. Seydoux, and A. Hawthorn, Schlumberger, prepared for the 2005 Offshore Technology Conference, Houston, 2-5 May. Logging-while-drilling (LWD) measurements are widely available for a variety of applications. Many of the first generation LWD measurements are similar to those obtained traditionally with wireline methods. However, there are measurements available now that are either complementary or are entirely unique compared with traditional wireline measurements. Introduction LWD borehole-seismic measurements can enable placing the bit on the seismic map or producing a seismic-impedance map ahead of the bit while drilling the well. These measurements provide accurate depth determination of drilling targets and identification of pore-pressure transgressions. LWD ultradeep-resistivity (UDR) measurement technology meets the requirements for geosteering at the reservoir level by use of subseismic resolution. Its major applications include delineation of the oil/water contact (OWC) and distance to reservoir caprock and bottom shale. Well Placement Since the emergence of LWD in the 1980s, the industry wanted a reliable while-drilling borehole-seismic measurement. However, several technical roadblocks prohibited its realization until recently. These difficulties included the nature of and required accuracy of the measurement, timing issues, sensors, automation, and the lack of an electrical connection between the downhole tools and the surface in a while-drilling configuration. Technological solutions to these road-blocks have since been found. Seismic-while-drilling data are delivered in real time to make critical decisions while a well is being drilled. They also replace intermediate wireline check-shot surveys, eliminating the need to stop the drilling process and pull drilling equipment out of the hole for the duration of a survey. Real-time accurate positioning of a horizontal borehole within a reservoir can be performed with standard LWD tools. However, a limitation of these measurements is the relatively small volume of investigation with traditional LWD sensors, which typically probe no deeper than 1 m into the formation. Therefore, unpredictable geological events are, in many cases, detected too late to allow proactive geosteering decisions. A prototype LWD resistivity tool was developed with a much larger radial response that allows detection of lithology features and fluid contacts that are tens of meters away from the borehole. The tool has a modular design with separate transmitter and receiver subassemblies that can be placed a large distance away, anywhere in the bottomhole assembly (BHA). The main output is estimated distance to boundaries indicated by resistivity contrasts. These distances are computed through inversion of a formation model in real time. On the basis of tool measurements, determining the optimum formation model and its related parameters allows proactive geosteering decisions and pro-vides significant geological insight into the reservoir structure.

Geologically based estimation of k v / k h ratios: an example from the Garn Formation, Tyrihans Field, Mid-Norway

During reservoir model building, one encounters several stages where upscaling or averaging of petrophysical data is required; core plug data have to be compared to wireline measurements and wireline measurements are averaged to the scale of building-size reservoir grid cells. Simple averaging does not, in most cases, give representative values, since the property in question is very scale-dependent. This is especially true for permeability and permeability anisotropy ( k v / k h ). For the case of a reservoir model of the Garn Formation (Middle Jurassic) in the Tyrihans Field, a simple geologically based upscaling method including the use of the SBED TM software package has been developed. Small-scale models of near well-bore geology are upscaled using single-phase flow simulation to obtain directional-dependent permeabilities for facies with different mud contents and style. The resulting k v / k h estimation curve has been implemented in the reservoir model by modelling V shale as a continuous parameter and applying the function to derive upscaled horizontal and vertical permeability grids. Upscaled permeabilities were found to closely match the well test data. This approach gives a more realistic k v / k h ratio than traditional methods involving simple averaging, or arbitrary guesses, of vertical permeability.

Numerical Simulation of Mud-Filtrate Invasion in Deviated Wells

Summary Understanding the spatial distribution of fluids in the near-borehole region caused by mud-filtrate invasion is necessary for the accurate petrophysical interpretation of wireline measurements acquired in deviated wells. This paper provides a sorely needed petrophysical and fluid-flow template that can be used to integrate several wireline measurements into a unique model of petrophysical parameters in the near-borehole region of deviated wells. We simulate numerically the physics of mud-filtrate invasion in vertical, horizontal, and highly deviated overbalanced wells. The numerical algorithm is adapted from a general 3D multiphase-fluid-flow simulator that is widely used in large-scale reservoir applications. Checks of numerical consistency and accuracy are performed against one commercial reservoir simulator. Emphasis is placed on describing the influence of mudcake buildup on the mud-filtration process. We approach the latter problem by introducing an effective-flow-rate function that describes the evolution in time of the rate of invasion of mud filtrate into rock formations. Parametric representations of the flow-rate function are derived on the basis of previously published laboratory experiments of mud circulation. A sensitivity analysis quantifies the influence of several geometrical and petrophysical parameters on the spatial distribution of mud-filtrate invasion away from the borehole wall. These parameters include relative permeability, capillary pressure, permeability anisotropy, dipping layers, and degree of hydraulic communication between adjacent layers. Our simulations reveal the character of invasion profiles in complex geometrical environments taking place under realistic petrophysical conditions. We show that standard pistonlike descriptions of mud-filtrate invasion, commonly used in well-log interpretation, can lead to inaccurate interpretations of wireline measurements. An example is presented of the use of our simulation technique by calculating the sensitivity of borehole electromagnetic induction measurements to specific conditions of mud-filtrate invasion in a vertical well.

Visualization for pore pressure prediction

Joanne Wang, Duane Dopkin and Huw James (Paradigm Geophysical) discuss how visualization and interpretation of multi-disciplinary data volumes can improve risk assessment of predicted overpressures. Seismic data transformations are used routinely by geoscientists to enhance geometric features and physical property descriptions of the subsurface. These transformations can range from the application of one-dimensional operators to migrated and stacked seismic amplitude data to the application of complex transforms that make use of multiple dimensions (e.g. amplitude versus angle) or multiple data inputs (e.g. seismic inversion procedures). They can be extended with the application of linear or non-linear operators (e.g. neural networks) to relate the resultant elastic properties (e.g. impedance) to other rock properties or reservoir conditions making use of petrophysics and rock physics data. While these transformations exploit the dynamic properties of seismic data, other transforms make use of the kinematic properties of multi-offset seismic data to estimate or predict subsurface conditions. Pore pressure predictions and transformations that make use of seismic velocity measurements, for example, have had a huge impact on drilling safety and the economics of drilling design and well construction. The pore pressure models derived from the integration and careful calibration of wireline, petrophysical, seismic velocity and field test measurements provide the data needed to make critical pre-drill stress and overpressure predictions in order to secure a safe and economic well program. Because most exploration and development projects incorporate many data transformations, a heavy burden is often placed on the geoscientist and drilling engineer to integrate a broad range of data volumes and models. Although automated procedures (e.g. PCA analysis, neural network classification) are available to facilitate multi-volume integration, high-end visualization technologies and strategies often provide the most effective and informative data integration vehicles. The multi-disciplinary pore pressure prediction and transformation process that integrates seismic, well log, petrophysical, field test data with structural frameworks and directional well paths can return a wide range of deliverables (outputs) that are natural for creative co-visualization and concurrent interpretation by geophysicists, geologists, and drilling engineers. These co-visualizations are often the most effective way to understand the ‘interplay’ or dependencies of one transformation with another.

Resistivity Measurements at the Bit Provide Real-Time Formation Evaluation Before Invasion

Real-time formation evaluation with today's conventional horizontal drilling techniques is limited by the distance between the bit and resistivity measurements. Logging-while-drilling (LWD) sensors reach the formation long before wireline measurements, and so generally view it before wellbore degradation, but not before some invasion has occurred. Rapid invasion, called spurt, may mask true resistivity in some formations. The solution to this problem is to relocate logging measurements to the bit itself. A new LWD resistivity tool improves and simplifies formation evaluation by allowing geologists to visualize and log the formation around the wellbore before mud invasion or wellbore damage has occurred. The tool is normally run as a near-bit stabilizer on a rotary bottomhole assembly or just above the motor in a steerable assembly. It makes five formation evaluation resistivity measurements and an azimuthal gamma ray measurement. One resistivity measurement uses the bit as part of the measuring electrode to provide the earliest possible indication of a change in formation resistivity. This real-time correlation capability leads to rig time savings during searches for casing or coring points, in effect allowing immediate "geostopping." The top of a reservoir can be cored without danger of drilling up the interval first. At-the-bit resistivity also allows the fastest detection of pore pressure anomalies. Four additional resistivity measurements are high-resolution focused electrode resistivities. One measurement uses a ring electrode to make an azimuthally averaged resistivity that is accurate up to 20,000 ohm-m. The other three use button electrodes to make azimuthal resistivity measurements that scan the borehole as the tool rotates. Together the ring and three button electrodes give four depths of investigation with identical vertical resolutions. Conventional 2-MHz LWD resistivity measurements are limited to environments favoring induction-type settings; that is, resistive mud (i.e., fresh or oil-based mud) and conductive rock. The solution to this problem is a high-resolution, focused electrode resistivity that provides accurate Rt measurements for the first time in "laterolog" environments of high formation resistivities and salty mud. An example is carbonates, where 2-MHz tools are inherently less accurate. This high resistivity measurement has excellent vertical resolution, allowing evaluation of beds as thin as 3 in. and detection of beds as thin as 1 in. Multiple depths of investigation of the button measurements, in combination with the focused electrode resistivity measurement, allow evaluation of permeable beds from early-time invasion detection. The array of three button electrodes provides azimuthal resistivities that scan the borehole as the tool rotates. These measurements form the basis for advanced processing and interpretation of full-bore resistivity images (see Fig. 1), introducing the potential for fracture detection, dip determination, and improved formation evaluation and characterization. The technical leap that allows measurements to be made at the bit is a wireless telemetry system that sends data from sensors near the bit to the measurement-while-drilling (MWD) tool up to 200 ft. behind the bit, bypassing the intervening drilling tools. Data sent to the MWD system are then transmitted to the surface in real time using mud-pulse telemetry. Resistivity at the bit is measured by attaching the tool directly to the bit and driving an alternating electric current down the collar, out through the bit, and into the formation. The current returns to the drillpipe and drill collars above the transmitter. In water-based mud, returning current is conducted from the bit, through the mud, into the formation, and back to the bottomhole assembly. In oil-based mud, which is an insulator, current returns through the inevitable but intermittent contact of the collars and stabilizers with the borehole wall, leading to a qualitative indication of resistivity. Formation resistivity is obtained by measuring the amount of current flowing into the formation from the bit and normalizing it to the transmitter voltage. Although drilling with at-the-bit measurements is still in its infancy, petrophysical measurements near the bit provide numerous benefits for geologists, petrophysicists, and drillers and extend the range of conditions under which it is possible to measure formation resistivity accurately while drilling. SI Metric Conversion Factors ftx3.048* E-01=m in.x2.54* E+00=cm *Conversion factor is exact.

Predicting Gas, Oil, and Water Intervals in Niger Delta Reservoirs Using Gas Chromatography

Formation evaluation experts usually have little difficulty in interpreting wireline logs to assess the type of reservoir fluid (oil/gas/water) in sand-shale sequences. This assessment is usually accomplished by a combination neutron-density tool that detects low hydrogen and low electron densities typical of gas zones, and the repeat formation tester (RFT), which uses both the pressure gradient and sample acquisition techniques to evaluate reservoir fluid. In the Niger Delta, however, many of the sands exhibit a poor neutron-density response to gas, and RFT testing has been largely eliminated because poor hole conditions commonly result in stuck tools. Oil fingerprinting of residual hydrocarbons from sidewall core extracts can provide an independent means of identifying eservoir fluid type. In conjunction with the Nigerian National Petroleum Company, we completed numerous chromatographic analyses on solvent extracts of sidewall core samples from various wells in the Mefa field, offshore west Niger Delta. Oil fingerprints of sidewall core extracts clearly reflect the type of hydrocarbons in the reservoir. Fingerprints of oil-saturated sands are typical of topped (C15+) whole oils, whereas fingerprints of hydrocarbons extracted from the gas-dominated sands show an abbreviated hydrocarbon distribution more typical of gas condensates. Fingerprints of extracts from water-productive intervals show a further abbreviated signature, suggesting that higher molecular weight hydrocarbons did not migrate into these intervals. These signatures are distinct and intact despit poor sample preservation due to prolonged storage of up to 3 yr. Additional applications of this technique include the reevaluation of older wells that lack modern wireline measurements, but have sidewall or conventional core material available, and in thin or low-permeability sands that may not yield definitive RFT or wireline-log responses. Application potential for this technology is worldwide and includes the Gulf Coast of the United States, Canada, Indonesia, and Papua New Guinea.

A statistical method for litho-facies identification

In this paper a procedure for the estimation of the lithological description of the stratigraphical formation by wells is described; in this procedure the results of wireline measurements and a litho-facies database are combined. The litho-facies are defined from log values and histograms and are translated into gaussian distributions. In order to optimise type lithologies we have used the discriminant function referred to as the Bayes rule. In addition, several logic rules have been applied in order to discriminate between different litho-facies (test of shale volume and bore hole conditions). The wireline logs used are density, sonic transit time, gamma ray, spontaneous potential and resistivity. The litho-facies groups represented in this database are sandstone, calcareous sand, shaly sand and shale. The procedure has been applied to two wells in a fluvial environment (sand-shales series). The results have been compared with drilling rates, cutting descriptions and Dipmeter information. For each level a lithological column can be produced with a computed probability. The examples are used for the study of sequences and facies in the Tertiary formations in the foreland Chaco basin of Bolivia (latitude 19–20°S).

Theory and Implementation of a Borehole Caliper Measurement Made While Drilling

Summary Like comparable wireline measurements, measurement-while-drilling (MWD) formation-evaluation tools are dependent on the borehole condition. Because of this dependency, the borehole size must be known for appropriate borehole corrections to be made to porosity measurements. This paper describes caliper measurements that can compute the effective diameter of a uniform or nonuniform borehole with nonmechanical means. The basis for the caliper measurement is a gamma/gamma density sensor that uses asymmetric detector placement to define the borehole size. The derivation of the caliper is presented with field log comparisons.

Real-Time Pore-Pressure Evaluation From MWD/LWD Measurements and Drilling-Derived Formation Strength

Summary Traditional pore-pressure interpretations in tertiary undercompacted shales have been based on empirical relationships between a particular measurement (such as resistivity) and pore pressure in pounds per gallon. It is well-known, however, that the measurements are responding to the "excess" porosity in the shale rather than to the pore pressure directly. A new technique is illustrated in which all available measurements are first characterized in terms of this excess porosity and lithology with measurement-response equations. This allows a mathematical minimization technique to solve simultaneously the various measurement-response equations for this porosity and lithology on a foot-by-foot basis. A conventional compaction porosity/effective-stress model is then used to determine the additional pore pressure caused by this excess porosity. The result is a single pore-pressure estimate that is independent of the number of measurements and that has an accuracy that improves with the total number of measurements used in the interpretation. The interpretation can be performed at the wellsite in real time by use of rate of penetration (ROP), measurement while drilling (MWD), and logging while drilling (LWD) measurements or after drilling by use of these measurements in conjunction with wireline measurements.

The Use of Wireline Pressure Measurements to Refine Reservoir Description, Main Body B Waterflood, Elk Hills Oil Field, Kern County, California

The Main Body B, one of five large Stevens sand reservoirs at Elk Hills, occupies the eastern half of the 31S anticline. Early in the production history of this reservoir, the Elk Hills unit initiated peripheral water injection to maintain reservoir pressure. Water injection has proceeded at a rate approximately equal to the voidage created by oil and gas production and has moved water upstructure creating an oil bank. Bechtel Petroleum Operations Inc., the current unit operator, drills five to ten new wells each year to fully exploit this oil bank. In 1985, the unit added wireline pressure measurements to the open-hole logging programs of these infill wells for the purpose of evaluating the net effect of injection into and production from the Main Body B reservoir. A typical well provides the opportunity to obtain 8-10 pressures from the Main Body B. To date, the Unit has measured wireline pressures in more than two dozen wells. The wireline measurements have shown a broader than expected range of formation pressures (1,600 {plus minus} psi to 4,200 {plus minus} psi). The pressures show that this is a layered reservoir with little vertical pressure communication between some of the layers. In some partsmore » of the reservoir, wireline pressures indicate horizontal continuity of the layers between wells and in other areas pressure differences between adjacent wells may indicate faults or cementation barriers. Permeabilities calculated from the sampling drawdown are the same order of magnitude as brine permeabilities obtained from core and show that higher-pressured layers of the reservoir have lower permeability. These observations fundamentally alter performance evaluation of the Main Body B waterflood.« less

Interpreting Wireline Measurements in Coal Beds

Interpreting Wireline Measurements in Coal Beds

Casing Corrosion Evaluation Using Wireline Techniques

Abstract Corrosion control in the oil industry is a matter of economics. Up to 1% of the over-all operating costs could be saved through corrosion management. All too often, this is not considered and corrosion monitoring only occurs on a need to know basis, after an unscheduled shutdown or actual casing failure. Corrosion management involves casing inspection and periodic monitoring, corrosion rate prediction and cathodic protection evaluation. Today's corrosion wireline logging tools offer a technique to predict and detect potentially disastrous corrosion problems. Current wireline measurements utilize electromagnetic, flux leakage, ultrasonic and mechanical techniques. They can predict, detect and delineate corrosion in the form of metal loss, holes, pits, and mechanical deformation. Furthermore, external problems can be distinguished from internal ones, These measurement systems will be briefly described along with examples of multiple measurement diagnostics. Introduction Corrosion control in the oil industry is essentially a cost containment exercise; the likely cost of a failure being balanced against the expenditure on a corrosion control program. The oil and chemical processing industries, which have to live with their corrosion problems, have a better record of corrosion control than most. In oil production, some 3% of the over-all operating costs can be attributed to corrosion. Up to one third or this could be saved through a planning scheme involving corrosion detection, evaluation and management in downhole casings. This generally involves three areas: casing inspection and periodic monitoring, corrosion rate prediction and corrosion protection evaluation. These can be accomplished through the application of current wireline measurements in addition to corrosion protection techniques. All too often, corrosion is not considered during the planning stages of a field. Most corrosion programs result from an adverse inspection report, an unscheduled shutdown or an actual failure. Cathodic protection systems of both surface and downhole tubulars are becoming the only realistic solution to a field's corrosion problems. Simply pm, monitoring casing corrosion is a function of dollars and cents. Today's corrosion logging tools offer oil companies the best chance of detecting and correcting the potentially disastrous effects of corrosion. These wireline measurement systems consist of three basic principles. Electromagnetic Tools Cathodic Protection Profile Tool Location of anodic corrosion cells - a device to evaluate external casing corrosion cell activity and determine cathodic protection needs. Flux Leakage Tool Localized corrosion - a high resolution flux leakage and eddy current multi-pad device to evaluate the extent of internal and external localized pitting and holes. Multifrequency Electromagnetic Thickness Tool General wall loss - electromagnetic device which determines wall thickness, inner diameter and casing wall electromagnetic properties measurement. Ultrasonic Tools Acoustic Corrosion Tool General wall loss - an acoustic device which determines wall thickness, inner radii and internal roughness, using eight fixed ultrasonic transducers. Borehole Televiewer Casing wall imaging - a high-resolution acoustic imaging device to evaluate internal surfaces and determine pipe geometry. Mechanical Tools Mechanical Calipers Inner wall loss - a multifingered mechanical caliper system with, 16 to 60 fingers to evaluate inner pipe wall for wear or deform

Total Organic Carbon Content Determined From Well Logs

Summary Total organic-carbon (TOC) content present in potential source rocks significantly affects the response of various well logs. This paper discusses and illustrates well-log anomalies caused by TOC as observed on various wireline measurements, including resistivity (or conductivity), acoustic, nuclear (density and neutron), gamma ray, natural gamma ray spectra, and pulsed neutron [sigma and carbon/oxygen (C/O) ratio]. Field examples of these well-log responses in open and/or closed wellbores are presented from several countries. Several correlations between TOC and individual and/or combinations of various logging responses are also reviewed.

Neutron porosity measurement while drilling

A measurement-while-drilling (MWD) neutron porosity tool has been designed that is superior to wireline porosity tools in several respects. Longer sample periods and greater porosity sensitivity reduce the statistical uncertainty in the MWD porosity measurement. Most of the borehole effects that perturb the measurement (salinity, mud weight, and borehole size) are reduced or nonexistent because the drill stem virtually fills the hole during drilling. Formation effects, lithology, and salinity changes, are comparable to or less than those for the wireline measurement. A sophisticated computer model was used to develop the initial design for this instrument and to estimate its response characteristics. Simulated response data are compared with experimental data to demonstrate the validity of the model. The response characteristics are superior to those of the wireline device.< <ETX xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">&gt;</ETX>

Automatic Determination of Lithology From Well Logs

Summary A procedure combining modern wireline measurements with a lithofacies data base has been developed to produce an automatic lithologic description of the formations crossed by a well. The database lithofacies are defined from petrographic knowledge and translated in terms of log responses. The assignment of depth levels to a lithofacies is done with the data base and with a discriminant function (Bayesian decision rule). External knowledge can be taken into account by use of artificial intelligence methods. A confidence factor is produced for each result. Logs currently in the data base are the density, neutron, sonic transit time, gamma ray, photoelectric cross section, and concentrations of thorium, potassium, and uranium. Major lithofacies groups represented in the data base include sandstones, limestones, dolomites, shales, coals, and evaporites. These are subdivided by introducing cement and special minerals and by considering porosity ranges. The construction of the data base is a critical step. It is largely empirical and requires careful calibration against intervals with well-known lithologies (e.g., from cores). The data base can be tuned to local conditions. The procedure has been tested in several environments and compared with cores and mud log descriptions. A detailed lithologic column can be produced at the wellsite and used in decision making. The results can also serve as input for further geologic studies of facies and sequences or for quantitative evaluation of formations.

Evolution of Offshore Seismic Exploration: ABSTRACT

True offshore seismic exploration had its inception in 1947. Although considerable work had been done prior to this in coastal estuaries, wetlands, and inland waterways, the methods used were adapted almost entirely from the conventional land operations. The first tentative ventures into the real offshore environment indicated that radical departures from land procedures were required in the following areas: (1) cables and receivers, (2) positioning (surveying, navigation), and (3) seismic energy sources. Leroy Paslay's continuous tow streamer cable and the replacement of the velocity-responsive geophones with pressure-sensitive hydrophones were significant early breakthroughs. At first, line positions were determined by land-based optical surveying methods, and shot locations were marked with buoys placed by wire-line distance measurements or triangulation. As work progressed farther offshore, a number of radio location systems were adapted or developed to provide positioning without the need for marker buoys. The present satellite and inertial navigation systems and the projected development of the new Global Positioning System represent continuing developments in this area. Dynamite and other chemical explosives were exclusively used as seismic sources for a number of years despite their many disadvantages. Development of suitable non-dynamite energy sources was mandated by the advent of the common reflection point method, and the Lamont-type air gun has become the most popular present-day source. Concurrently, the vessels used were progressively upgraded from converted shrimp boats to surplus air-sea rescue vessels and then to the currently popular 165 ft mud boats. Individually, these developments may appear to be only evolutionary. In the aggregate, however, they represent a major revolution when compared to our first timid ventures of the late 40s. End_of_Article - Last_Page 602------------

Carbonate Porosity Versus Depth: A Predictable Relation for South Florida

This study examines the porosity of limestones and dolomites in the South Florida basin. Porosity data are derived from borehole-gravity measurements and from suites of acoustic, neutron, and density logs. Both types of wire-line measurements sample large volumes of rock relative to petrographic methods and can be examined at vertical scales approaching those of aquifers and hydrocarbon reservoirs. Investigation depths range from the surface to about 18,000 ft (5,500 m) and span the transition from high-porosity near-surface carbonate sediments of Pleistocene age to much denser Mesozoic carbonate rocks with porosities of only a few percent. Carbonate porosity in the South Florida basin was affected by a variety of diagenetic processes. However, a number of factors that could complicate porosity-depth relations are of limited importance in southern Florida. The basin contains little clastic material; present depths of burial are about equal to maximum depths of burial; the influences of tectonism, geopressures, and hydrocarbon accumulations are minimal. Curves of porosity versus depth, reflecting large-scale porosity-loss processes in the subsurface, are derived for a composite carbonate section and for carbonate strata of different ages and compositions. The decrease of porosity with depth for a composite carbonate section representing a wide range of depositional environments and subsequent diagenetic histories can be characterized by the exponential function ^phgr = 41.73e -z8197/ (ft) [^phgr = 41.73e-z2498/ (m)], where ^phgr is the porosity (%) and z is the depth below ground level (feet or meters). Average porosity is reduced by a factor of two in a depth interval of about 5,700 ft (1,740 m). Carbonate strata of different ages that are buried to equal depths show no systematic porosity differences. This implies that the effect of time on porosity in these rocks is probably subordinate to that of burial depth. The data also show a faster than expected rate of porosity decrease with depth for rocks of Eocene age and younger. If it is assumed that the decrease in the volume of evaporites in these rocks indicates less saline pore fluids, porosity loss in shallow-water carbonates may be inversely related to the magnesium content of pore waters. Dolomite porosity is lower than limestone porosity in the near surface, but does not decrease as rapidly with depth. Below about 5,600 ft (1,700 m), dolomite is more porous than limestone. It is hypothesized that most dolomitization occurred relatively early and either reduced original porosity or selectively favored lower-porosity limestones. With continued burial, dolomite was more resistant than limestone to associated porosity-reducing effects.