Production Logging Tool Research Articles

Flow Profiling Gas Wells With Distributed-Temperature-Sensing Data

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 103097, "Successful Flow Profiling of Gas Wells Using Distributed-Temperature-Sensing Data," by D. Johnson, SPE, J. Sierra, SPE, J. Kaura, SPE, and D. Gualtieri, Halliburton Energy Services, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September. Distributed-temperature sensing (DTS) coupled with a temperature/pressure simulator was used to determine flow profiles from multilayered commingled reservoirs in gas wells. Quantitative individual-layer contributions to gas-flow rates and main water entries were determined, which in turn, helped engineers evaluate production conditions, track individual-layer recovery, identify problem zones, and plan remedial actions. Introduction DTS can provide continuous real-time flow information for the entire wellbore. However, DTS analysis is complex, and there is a current lack of user-friendly interpretation software. Production optimization requires continuous production information of each layer to design and plan preventive or remedial actions. A production-logging tool (PLT), the popular flow-allocation solution, is a snapshot-type survey. Also, PLT results from low-rate or unstable-downhole environments can be misleading. Other methods such as mixed-fluid signatures (e.g., gravity and salt content) are quasicontinuous, but their application is restrictive, requires special contrasting fluid properties, and cannot handle more than three layers. Background It is recommended that the reader review Appendix A in the full-length paper. The discussion shows unpublished work previously developed by the authors and provides the develop-mental work conducted on the transient analytical/numerical wellbore-temperature and -pressure model. This model was used to perform temperature analysis for flow allocation and fluid identification. One of the first successful applications of this model with actual DTS data was in low-rate oil- and water-producing wells and achieved a good match between DTS data and simulated temperature. Temperature in Gas Wells Gas production from a single reservoir was used as a simple example in material-balance calculations. While pressure-transient analysis in gas wells is considered simple (if one uses the pseudo pressure approach), wellbore hydraulics in gas wells, sometimes considered complicated, can be simplified by accounting for temperature changes related to frictional and Joule-Thomson effects (JTEs). The global trend when producing dry gas is to produce multiple small or low-productivity reservoirs commingled in a single well to allow for exploitation of gas that was not considered economically feasible to produce. This scenario can lead to differential depletion, cross-flow, and water breakthrough, which can impair gas production and under-standing of reservoir dynamics. These scenarios offer many conditions for use of DTS data for better quantification of flow rates and fluid types from individual reservoirs. JTE. The JTE is the phenomenon whereby fluid that is subjected to a pressure change experiences a change in temperature. The JTE is a cooling of produced gas or a warming of produced water caused by pressure drop during flow through formation, perforations, and wellbore.

New Logging Tool Enhances Multiphase Production Analysis

A new multifunction production logging (PL) platform is producing quantifiable results in complex triphasic flow regimes. At 25 ft long, the system takes the place of a conventional PL tool string five times as long. The Schlumberger Flow Scanner tool, unlike its predecessor, features close integration of its 17 sensors in an 11-ft-long sonde so that true dynamic flow characteristics can be obtained at any point in the well. The new system is designed to operate in wellbore diameters ranging from 2 7/8 to 9 in. and under environmental conditions up to 300°F and 15,000 psi. This technology is particularly valuable in deviated and horizontal multiphase wells, where phase behavior is extremely variable and complex. To obtain an accurate picture of the dynamic flow regime at any point in the well, it is necessary to scan the full diameter of the wellbore. The new logging tool does this mechanically, electrically, and optically. (Fig. 1). Run eccentered in open or cased holes, the tool finds the low side of the hole thanks to gravity. Then an articulated sensor arm is deployed that spans the wellbore, providing five equally spaced measurements of flow velocity, direction, and phase fraction. Together, these measurements provide three-phase holdup, which is defined as the dynamic phase fraction at any point in the wellbore. Holdup differs from produced volume fraction, or cut, because the phases travel at different velocities. Other tool sensors measure pressure and temperature, hole diameter, and instantaneous tool orientation. To analyze a production interval properly, one must understand exactly what is happening at each spot in the wellbore. Previous PL methods interfered with the flow regime they were trying to measure, and typical phenomena such as heavy-phase recirculation resulted in ambiguous data with gaps over critical intervals. In addition, interpretation could take months and involved dozens of specialists examining data from several log passes. In contrast, the new logging tool was designed using computational fluid-dynamics simulations to optimize its shape and minimize any flow perturbations. A real-time graphics display and processing workflow makes preliminary interpretation possible with a single logging pass. One or two additional passes at different logging speeds can enhance overall accuracy.

Development and First Field Application of a Gel/Cement Water-Shutoff System

Summary Water production in northeast Syria has increased significantly in recent years. As a result, costs per barrel of oil have increased and the field's production is currently constrained by the facilities capacity. Production logging tool (PLT) surveys, combined with a reservoir study, showed that good-quality sands were not properly swept by the water, probably because of poor connectivity in the reservoir. It was anticipated that these unswept sands could contribute to production if the watered-out sands were shut off. A newly developed gel/cement has been used to shut off the watered-out sands in a cost-effective manner. The gel/cement system combines the properties of two shutoff techniques: Cement for mechanically strong perforation shutoff. Gel for excellent matrix shutoff. The gel, used as "mix water" of the cement, will be squeezed into the matrix, creating a shallow matrix shutoff. The cement will remain in the perforation tunnel as a rigid seal. This system showed superior shutoff performance in the laboratory compared to normal cement squeeze techniques. Selective perforation of the hydrocarbon zones will re-establish the oil production. The shutoff zones can be reopened later in the well's life when artificial lift has been installed. The system was tested in the field in two wells. In the first field trial, 84 m of perforations (gross) was squeezed off with the gel/cement in a single attempt. After reperforation of the top and the middle zone, the well produced at a strongly reduced water cut (i.e., 25 to 33% compared with 60 to 62% before the treatment) and an increased oil production (i.e., 3,000 BOPD compared with 1,000 BOPD before the treatment). The oil production declined to 2,000 BOPD over a year; the water cut gradually increased over that period to 56%. In the second well, full shutoff was achieved but oil production could not be resumed for reasons that are not fully understood.

Integrating Advanced Production and Image Logging in a High-GOR Horizontal Well

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 93473, "Integration of Advanced Production and Image Logging in a High-GOR Horizontal Well With Assessment of Remedial Actions," by A.A. Al-Fawwaz, SPE, and H.K. Mubarak, Saudi Aramco, and M. Zeybek, SPE, Schlumberger Oilfield Services, prepared for the 2005 SPE Middle East Oil & Gas Show and Conference, Bahrain, 12-15 March. Production logging in high gas/oil ratio (GOR) horizontal wells is difficult because of complicated multiphase-flow regimes in long undulating wellbores. Accurate diagnosis of gas-entry points is important to understand well performance and the reservoir dynamics and characterization and, if possible, to plan remedial shutoff action. This paper summarizes a case study of a high-GOR horizontal well from which oil production decreased significantly because of gas entry. An integrated production-logging tool was used to detect gas-entry points and determine the flow profile. Introduction Increased gas production can reduce oil-well performance significantly. Generally, a drop in reservoir pressure or gas break-through could cause an increase in GOR. Detecting gas-entry intervals, in the case of early increases in GOR, provides valuable information for understanding reservoir dynamics and optimizing well placement. Well-performance evaluation is crucial for maximum productivity and choosing well trajectories. The integration of reservoir and geological data yields a more accurate characterization. Conventional production-logging tools, developed for vertical wells, often do not perform well in horizontal wells because multiphase flow in horizontal sections is highly segregated. In this case, high-GOR production began during the first year. Detection of gas-entry intervals was the primary objective. An integrated production-logging tool string, including a gas-holdup optical-sensor tool, was run. The tool detected gas and oil entry accurately. The integration with static data from openhole and image logs showed coherent results by identifying high- and low-permeability facies where the gas entries were observed from high-permeability zones crossing the wellbore. A fine-grid numerical-simulation model was developed with a commercial simulator to assess remedial-action plans. Gas/Liquid Flow and Integrated Production-Logging Tool String It is known that, generally, oil/water flow regimes in horizontal wells are stratified. It is important that fluid-flow regimes be understood for interpretation and measurement accuracy. Fig. 1 shows the flow regimes in horizontal wells having gas/liquid flow. Mostly stratified or wavy-stratified flow regimes are observed when the deviation is 90° or greater. However, the stratified-flow domain is limited when the deviation is less than 90°. Plug or slug flow becomes dominant at this deviation, indicating the complexity of the flow. Considering the small changes in well deviation and fluctuations in the well performance, real-time gas-holdup measurements during each pass would improve the results.

Imaging technologies in oilfield applications

In this paper, we describe some recent imaging technologies developed by Schlumberger for oilfield downhole multiphase flow production logging (PL) and cross-well electromagnetic (EM) survey applications. FloScan Imager (FSI™) has been introduced as a 3-phase oil/gas/water flow PL tool for deviated and horizontal wells. FSI sensors can map fluid velocity and holdup profiles along a vertical diameter of the wellbore at every survey depth, enabling a robust estimate of the individual phase flow rates in complex flow regimes. The cross-well EM survey is based on cross-borehole induction logging technique and provides resistivity distribution at a reservoir scale. It is a useful tool for reservoir management and is most effective in dynamic fields where fluid saturations are variable in time and space. The tool can be used to identify (water or steam) flooded and bypassed regions. By monitoring changes in the resistivity spatial distribution with time, cross-well EM survey is very effective at mapping inter-well temperature and structure. Some field examples are shown for both FloScan Imager PL tool and cross-well resistivity imaging survey.

The Option Value of Acquiring Information in an Oilfield Production Enhancement Project

In many industrial applications, the option to acquire information instead of simply waiting for conditions to improve can add considerable value to projects. As one example, most oil wells require periodic “workovers” to maintain production at satisfactory levels, and acquiring up-to-date information on the reservoir using a production logging tool (PLT) generally improves the efficiency of such workovers. This article presents a case study of oil production enhancement in which Bayesian analysis is incorporated into a real options framework to determine whether the additional cost of acquiring information is justified. This case is different from most applications of real options in that there are two main sources of uncertainty: the oil price and the reservoir. Bayesian analysis was used to update the reservoir model, using the PLT data together with prior knowledge about the reservoir. The updated reservoir model was then incorporated into a real options valuation framework.

Jotun 4D: Characterization of fluid contact movement from time-lapse seismic and production logging tool data

Time-lapse (or 4D) seismic is a reservoir monitoring technology that has matured to the point where it can be considered a reliable reservoir surveillance tool. By analyzing differences of multiple seismic surveys acquired over a producing reservoir and by integration with conventional reservoir monitoring tools, 4D seismic data can provide valuable insight on dynamic reservoir properties such as fluid saturation, pressure and temperature. Many published case studies demonstrate that 4D seismic technology can optimize reservoir management and improve production efficiency. In this paper we describe the application of time-lapse seismic methods to the Norwegian North Sea Jotun Field to determine the extent of the oil-water contact (OWC) movement during the first three years of production.

Incorporating technical uncertainty in real option valuation of oil projects

Real options are a way of valuing projects such as oil fields, which involve irreversible investment decisions subject to uncertainty. Whereas discounted cash flow (DCF) analysis is based on fixed estimates of costs and revenues, and a predetermined development scenario, real options focus on project flexibility (e.g., being able to defer starting a project, or conversely, to accelerate its development, etc.). Early applications concentrated on flexibility to overcome uncertainty on financial parameters and tended to ignore uncertainty on technical parameters (such as recoverable reserves). In some cases, companies can reduce the latter by acquiring additional information and sequentially updating parameter values and then the estimate of the project's value. This paper addresses the question of how to evaluate the option to acquire more information. The natural way to incorporate the new data is by Bayesian analysis. Choosing a multivariate normal framework for this analysis considerably simplifies the computations but this distribution has symmetric upper and lower tail dependence. To overcome this limitation, we have developed a novel form of Bayesian updating based on Archimedean copulas. We present a case study on production enhancement that shows how to combine Bayesian updating and real options. In this study, the oil company has the option to gather information from a production logging tool (PLT) before carrying out a workover.

Interpretation of Horizontal-Well Production Logs: Influence of Logging Tool

Summary This paper investigates the disturbance of horizontal-wellbore flow conditions by a production-logging tool and its influence on well-bore flow-rate and pressure measurements. An analytical model is used in the investigation, and single-phase liquid flow is assumed. It is shown that the influence of the production-logging tool manifests itself in low-conductivity and high-rate wells; this effect may be ignored if the dimensionless well conductivity exceeds 500 and the Reynolds number is lower than 100,000. Results indicate that production logs in low-conductivity horizontal wells may not display low-permeability zones along the well.

Water Injection Profile Modification in a Layered Reservoir With Polymer Treatment

Summary The main focus of this paper is the applications of polymer treatment in controlling injectivity and the improvement of the nearwellbore injection profiles. Reservoir high-permeability zones causing distortions of water injection profiles at the wellbore, and the possible existence of layer barriers, were identified with conventional investigation tools such as openhole logs, production logging tools, formation, and microscanners. A polymer screening procedure was put in place so that appropriate polymer formulations that can reduce fluid mobility in the high-permeability zones at the near-wellbore region can be identified. The use of these polymer formulations facilitated the improvement of wellbore injectivity profiles. The field performance of the polymer treatment program was ascertained by the use of a monitoring program that combined the application of the production logging tools and well-test analyses.

Novel Wax-Diverter Technology Allows Successful Scale-Inhibitor Squeeze Treatment in a Subsea Horizontal Well

Summary In this article we present field results from two scale squeeze treatments carried out on the same subsea horizontal well from the Strathspey field in the North Sea. The initial squeeze was a bullhead application of phosphonate scale inhibitor to control a sulfate scale problem in a horizontal well. Ten months after the initial treatment a second bullhead squeeze treatment was applied in two stages. This latter utilized a thermally degraded pelleted wax diverter to temporarily impair the injectivity in the heel region of the horizontal well thus allowing propagation of the second stage of the squeeze treatment into the midsection of the horizontal well. In this article we show the significance of production logging tool data to evaluate the location of deposited scale and water production prior to a squeeze treatment. These data were used to design a novel two stage squeeze treatment in which an initial squeeze slug was applied to the heel region followed by application of a pelleted thermally degraded wax diverter to prevent further loss of scale inhibitor to the heel region. The action of the wax diverter allowed a second scale inhibitor slug to be placed further along the horizontal section of the well. Details of the diverter selection and the squeeze design strategy implemented in this squeeze treatment will be presented. During the field treatment, physical (downhole pressure and temperature) data and chemical (nonradioactive tracers, inhibitor and ion concentrations) data were recorded. These data will be used to indicate the success of the diversion treatment by a comparison with the first squeeze applied to the same well 10 months previously. This is the first successful application of a thermally degraded wax diverter to a subsea horizontal well in the North Sea basin. The well was successfully treated with no process upset during flowback and no decline in well production while allowing the well bore to be protected from continued sulfate scale formation. In this article it is clearly shown that with the correct selection of both the scale inhibitor and diverter agent together with ulitization of all available information relating to the reservoir, it is possible to squeeze scale inhibitors into subsea horizontal wells without the need for intervention by expensive coiled tubing from a diving support vessel.

Well Testing and Interpretation for Horizontal Wells

The use of transient well testing for determining reservoir parameters and productivity of horizontal wells has become common because of the upsurge in horizontal drilling. Initially, horizontal well tests were analyzed with the conventional techniques designed for vertical wells. During the last decade, analytic solutions have been presented for the pressure behavior of horizontal wells. New flow regimes have been identified, and simple equations and flow regime existence criteria have been presented for them. The flow regimes are now used frequently to estimate horizontal and vertical permeabilities of the reservoir, wellbore skin, and reservoir pressure. Although the existing tools and interpretation techniques may be sufficient for simple systems, innovation and improvement of the present technology are still essential for well testing of horizontal wells in many reservoirs with different geological environments and different well-completion requirements.

Extended Reach and Horizontal Wells Experienced on the Statfjord Field

Statfjord field, the largest producing field in Europe, is located 200 km northwest of Bergen, Norway on the United Kingdom/Norwegian boundary. Statfjord field is being developed with three fully integrated platforms of concrete gravity based on Condeep design. The Statfjord field consists of four reservoirs: Upper Brent, Lower Brent, Dunlin, and Statfjord, which are developed separately. The overall objective for the horizontal and extended reach wells on Statfjord is to maximize the field recovery and accelerate production at a minimal cost. This is done by drilling extended reach wells to the far-away flanks of the field and drilling horizontal wells to drain fault blocks and erosion zones in the Brent reservoir and wedge zones in the Statfjord reservoir. To date, a total of 11 horizontal and extended reach wells have been drilled and completed on Statfjord field. The following have been key factors in drilling the horizontal and extended reach wells: well profile, torque and drag, equipment limitations, hole cleaning, hole stability, mud and cement programs, and surveying. To optimize the well profiles, extensive work has been put into simulating torque, drag, and ECDs. The well profiles are optimized with regards to drilling, completion, and workover, in addition to themore » reservoir targets. The completion is designed to be able to perform all future work through tubing. Factors like zone isolation requirements, well profile, casing program, logging/testing/perforating requirements, and sand production are considered when planning the completion. A 7 in. monobore completion string together with a 7 in. cemented liner is used to meet the completion objective. Several production logging tool, bridge plug, and perforation jobs have been performed on coiled tubing in horizontal wells on Statfjord field. Problems related to hole cleaning, well killing, fishing, and packer setting have been experienced during drilling and completion of the wells.« less

An Operational Subsea Wireline System

This paper describes an operational subsea wireline system that is self-contained and flexible and offers a safe, economical, and proven method for riserless re-entry into any subsea well. The system discussed here was developed over a number of years and has been used to carry out a comprehensive range of wireline tasks from floating vessels in the North Sea. Although generally deployed from a diving support vessel (DSV), the system has been successfully used from a drilling rig to conduct wireline operations in a well, simultaneously with workover operations in an adjacent well, on a subsea template.

Well Testing and Analysis Techniques for Layered Reservoirs

Summary This paper presents new testing and analysis techniques to obtain individual-layer permeabilities and skin factors for layered reservoirs. The new multilayer testing technique consists of a number of sequential flow tests with a production logging tool that simultaneously measures the wellbore pressure and flow rate at the top of each layer. Two different analysis techniques are presented to estimate layer parameters. The first technique, which is the logarithmic convolution method, estimates the approximate values of parameters. The second technique, which is the nonlinear least-squares estimation method, improves the first estimates. It is shown that layer permeabilities and skin factors can be estimated uniquely from simultaneously measured wellbore pressure and flow-rate data that are acquired from all layers sequentially. It is also shown that these individual-layer parameters cannot be estimated from the conventional drawdown- or buildup-test wellbore pressure data. Several synthetic examples are presented to illustrate the application of multilayer testing and analysis techniques.

Interpretation of Pressure Buildup Test Using In-Situ Measurement of Afterflow

Summary The influence of after flow on transient pressure responsehas long been recognized in well test analysis. The type-curve approach based on the simplified model of aconstant wellbore storage coefficient has attempted to assessafterflow effects from pressure data alone. Theintroduction of a new generation of production logging tools thatcan measure bottomhole flow (BHF) and pressure (BHP)simultaneously allows the afterflow in the well to bemonitored at the surface. Consequently, the well test canbe more rigorously interpreted by using a new form ofvariable rate analysis, and the shut-in time required toallow the detection of a straight line on the appropriatesemilog plot [e.g., Homer, or Miller-Dyes-Hutchison(MDH)] is much reduced. The analysis of the pressureand flow data transmitted from the production loggingdevice may be carried out at the wellsite in real time so that the test can be continued until the desired objectives are achieved. A field example shows how continuous BHF measurement during the wellbore storage period can improve the interpretation of a short-duration build up test. Introduction The constant rate solution of the flow equation in aninfinite reservoir is the basis of the conventional analysisof well tests. Even if the reservoir is bounded, the analysis applies while the reservoir is infinite acting-i.e., untilthe pressure change reaches the outer boundary. For the conventional analysis, it is essential to maintain constantrate, and it is well known that this is difficult to achieve. The best way to maintain constant rate is to make it zero, hence the wide use of buildup tests. Because of the compressibility of the fluid in thewellbore, the BHF does not adjust instantly to thesurface flow after a change of rate is imposed at the wellhead. This phenomenon is called "afterflow" in a buildup testor, more generally, "wellbore storage effect. "Duringthis time, the sandface rate is not constant, and early datacannot be used in the conventional (i.e., Homer or MDH)analysis. Furthermore, outer boundary effects maydevelop before the wellbore storage effect disappears, inwhich case the conventional analysis does not apply. Hence, the necessity of interpreting early data. This interpretation is possible through a more generalsolution of the flow equation, with a variable sandfacerate as inner boundary condition. The rate can be obtainedfrom a direct measurement or by other means. The firstattempt known to us of direct measurement in a builduptest was presented by Gladfelter et al. The afterflow ratewas obtained by measuring the rise of the liquid level inthe wellbore. The analysis used a semilog plot of the"corrected pressure," which is the ratio of the pressure dropto the sandface rate variation. Another method is to estimate the sandface rate froma mathematical model. Van Everdingen and Hurstpresented an exponential function of time as an presented an exponential function of time as an approximation of the sandface rate. In the currently acceptedtype-curve analysis, it is estimated from the derivative ofpressure with respect to time, on the assumption that the pressure with respect to time, on the assumption that the wellbore storage coefficient and the surface rate areconstant. A comprehensive review of this technique ispresented in Ref. 4. presented in Ref. 4. Recently, wireline tools capable of simultaneousmeasurement of sandface rate and pressure (as well asfluid temperature and density) were introduced. The firstbuildup tests recorded with these tools in oil and gas wellsalmost invariably revealed abnormal situations such asvery long afterflow or backflow and phase segregationin the wellbore. Such observations justifiably may leadus to question the validity of sandface rate estimated frompressure data alone. We present an analysis of the pressure data alone. We present an analysis of the wellbore storage concept and show briefly how a direct sandface measurement could improve the type-curve analysis. Our main purpose is to propose a new analysis basedon simultaneously measured sandface rate and pressure. The technique makes use of a rate-convolved time function similar to the superposition time function of Odehand Jones. The wireline aspect of the measurement offers the possibility of analysis in real time. We presentthis analysis for a buildup test in a homogeneous reservoir. Shortly after the original presentation of this work, several authors presented more comprehensive applications of direct sandface rate measurements. Fetkovich andVienot introduced their rate-normalized type curves, Kucuk and Ayestaran used a deconvolution process toidentify the reservoir model, and Stewart et al. appliedthe rate-convolved time function in nonhomogeneous reservoirs. JPT P. 143

Rate Normalization of Buildup Pressure By Using Afterflow Data

Summary Field data indicate that in some instances signify cant after flow occurs after a well is considered shut in. Analysis method for after flow-dominated pressure buildup data is presented whereby the PD-TD model describing the transient behavior of the well can be directly obtained by matching a log-log plot of the rate-normalized pressure vs. time data to published type curves. The PD-TD model thus obtained allows a rigorous mathematical superposition analysis to be performed on the same data with results equivalent to those obtained from the normalizedtype-curve analysis. The work demonstrates that rate normalization must be based on total after flow rates, confirming with field data Perrine's assumption that total rate should he used in multiphase flow analyses. Dramatic changes in character are seen between the rate-normalized pressure vs. time and the conventional pressure vs. time log-log data plots for low permeability stimulated wells. Several field examples demonstrate the application of this simple and effective technique. Introduction Currently, wellbore storage type curves based on the assumption of a constant wellbore storage coefficient are used to evaluate after flow-dominated data from pressure alone. For pumping wells, the ability to calculate reliable buildup pressures and corresponding after flow rates, along with the wellbore storage coefficient variation with time, has been reported in several papers. More direct bottom hole measurements of after flow and pressure using production logging tools during pressure buildup tests production logging tools during pressure buildup tests have been reported recently by Meunier et al. In the U. S., wellbore storage effects often characterize pressure buildup tests because the majority of domestic wells are produced by rod pumps where after flow dominates during produced by rod pumps where after flow dominates during the buildup. This type of completion can result in long periods of wellbore storage during test situations even for periods of wellbore storage during test situations even for stimulated wells. The first attempt to use both pressure and after flow rate data was presented by Gladfelter et al in 1955. They suggested that the pressure rise after shut-in divided by the instantaneous change in rate caused by after flow should be plotted vs. the logarithm of shut-in time. This resulted in a modified Miller-Dyes-Hutchinson (MDH)buildup plot. The validity of this approach was confirmed by Ramey" in 1965, and extended by him to include wellbore unloading effects during drawdown testing. About this same time Wine stock and Colpitts proposed a similar rate normalization of pressure for proposed a similar rate normalization of pressure for drawdown analysis of gas wells when rates were monotonically declining during drawdown tests. Rate variations were not a result of wellbore storage effects but were more a result of a nearly constant wellbore pressure test condition. Their rate normalization of the pressure test condition. Their rate normalization of the pressure data was simply an attempt to make a constant pressure data was simply an attempt to make a constant rate analysis from essentially constant wellbore pressure data. A computer study by Lee et al. basically confirmed the validity of the Wine stock and Colpitts rate normalization analysis procedure. Additional discussion of the Gladfelter et al. and the Wine stock and Colpitts normalization methods was given by Ramey in 1976. Rate-normalized type-curve plots of the Gladfelter etal. and Wine stock and Colpitts example data show that after normalization virtually all the data were on the semilog straight line. Rate normalization linearized all the data in both instances. However, tests on low-permeabilityoil and gas wells with large negative skins often cannot be analyzed using their suggested rate-normalized pressurevs. logarithm of time plotting approach because the data may not reach the semilog straight line even after normalization. A simple method of analyzing after flow-dominated pressure buildup data is presented. The PD-TD model pressure buildup data is presented. The PD-TD model describing the transient behavior of the well may be obtained directly by matching a log-log plot of the rate-normalized pressure vs. time data to published type curves. The PD-TD model thus obtained allows a rigorous mathematical superposition analysis to be performed on the same data with results equivalent to those obtained from the normalized type-curve analysis. Drawdown Rate Normalization Equations Rate normalization techniques and procedures are best illustrated by first examining their application to drawdown data. Although the nature of the rate variation of drawdown data with time is different than that of after flow rate variation, the end result is the same. Also, draw down rate variations generally last much longer than after flow rate variations. The rate normalization equation given by Wine stock and Colpitts for a gas well drawdown analysis can be written as (1) JPT p. 2211

Production Logging Tool Behavior in Two-Phase Inclined Flow

Summary Production logging tools obtained from three service companies were tested in one-, two-, and three-phase flow in an inclinable flow test facility. These tests were inspired by the often confusing production logs obtained in deviated wells. The experiments have shown that two- phase flow regimes in inclined pipes differ markedly from those in vertical flow at similar flow rates and that these flow regimes adversely affect production logging tool responses. The experiments performed, the behavior of the production logging tools, and a statistical analysis of the data are discussed. Introduction Production logging tools obtained from three service companies were tested in one-, two-, and three-phase flow in an inclined flow test facility at Marathon Oil Co.'s Denver Research Center. Flow rates were chosen to simulate downhole conditions in producing wells in the McArthur River field, where production logging is used extensively. Liquid flow rates ranged from 70 to 3,400 B/D (11 to 540 m3/d) and gas rates ranged from 0 to 7.5 Mcf/D (0 to 210 m3 /d) during the tests. To simulate the wide range of well deviations in this off- shore field, the pipe angle also was varied from vertical to 60 degrees from vertical. Production logging tool responses were measured over this range of conditions to understand tool behavior and to try to correlate measurements with actual flow rates. Flow patterns observed in multiphase flow in an inclined pipe were found to affect production logging tool responses dramatically. In gas/liquid flow in a slanted pipe, slug flow was the predominant flow regime, whereas in oil/water two-phase flow. a stratified flow was common. In both cases. the lighter phase would move rapidly along the upper side of the pipe, establishing a circulating current that caused downflow along the lower side of the pipe. We repeatedly observed this pattern even though the net flow of all fluids was upward. Because of this nonuniform flow profile in multiphase flow in inclined wells, responses of production logging tools that measure localized quantities do not represent volumetric flow rates, average densities, or holdups. In this type of flow situation, spinner-type velocity tools often indicate reverse flow, especially when they are not centralized. Density and capacitance tools tend to be immersed primarily in the denser phase in a multiphase flow situation, preventing them from indicating average flow properties. Capacitance tools also exhibited nonlinear calibrations in static fluids, which makes their response suspect in a flowing stream. Flow concentrating flowmeters were the best tools tested for flow-rate measurements because they force most of the flow stream through a turbine inside the tools. A film made during the testing of production logging tools illustrates the profound effect of inclined, multiphase flow on these devices. A 5-minute videotape version of this film is available from SPE.* We used multivariate regression analysis to correlate the responses of two of the tool strings with the flow rates of each fluid and with the deviation angle. These correlations were used to predict the fluid flow rates from specific sets of tool response. Correlations obtained, however, were not sufficiently accurate for use in production logging interpretation. Improvements in tool design will be necessary before this technique can be applied to field interpretations. The technique does appear valid for tools that measure average fluid properties across the pipe. JPT P. 2432^

High Temperature Geothermal Well-Logging Techniques in Japan: ABSTRACT

A high temperature geothermal well-logging system has been developed by Japan Petroleum Exploration Co., under the sponsorship of the Japanese government. The tools developed on this project are: Multi-Spacing Electrical-SP Log (equivalent to Lateral Log); Microspherical-Caliper Log; Side Wall Acoustic-Caliper Log (P-S Wave Sonic Log); Steering Tool (Azimuth, Hole Deviation and Inclination); Optical Borehole TV; Production Logging Tools (Temperature, Pressure, Continuous Flow and Caliper, and Borehole Sampler). The maximum operating temperature of these tools is 325°C and they can withstand pressures of 500 kg/cm2, by the use of TFE teflon insulator armored cable. The tools have been subjected to field tests over 50 geothermal wells, since 1978, and all except the Optical Borehole TV were successfully operated where bottom-hole temperatures were as high as 210 to 275°C. The side wall acoustic tool, which consists of P and S wave transducers, is very useful for the detection of formation fractures in volcanic rocks. The Optical Borehole TV could not be used where temperatures exceeded 150°C, because of heat radiation emitted from the mud and the holewall surrounding the down-hole probe, or when the tool was focused at the surface of the semiconductor imagesensor on the TV and the temperature of the image spot exceeded 120°C, even when placed in a Dewar bottle and heat sink assembly. Super high temperature (450°C) production logging tools, using mineral insulation cable, are under construction and will be in operation by the end of August 1982. They are: Absolute and 1-meter spacing differential Temperature Survey; Continuous Pressure Measurement; Continuous Flow and Caliper Measurement; High Temperature Microphone and Accelometer, with a wall set mechanism. The diameter of these tools is 2 inches and their maximum operating time is 30 hours at 450°C. They can withstand pressures of 500 kg/cm2. The success of this system is apparent from the summary of field results and the technical report of the super high temperature production logging tools. End_of_Article - Last_Page 972------------

A New Thermal Neutron Decay Logging System--TDT (TM) -M

Summary A new thermal-neutron decay-time logging system (TDT TM-M) has been developed to provide greater accuracy and increased statistical precision by improvement in the manner of detection of the rate of decay of the thermal neutron concentration. Its far-spacing detector can be used to provide a sigma measurement with a greatly reduced diffusion effect as compared with the standard measurement. Introduction Pulsed neutron capture logs provide measurements of the thermal-neutron decay-time constant (tau) or its inverse, the macroscopic capture cross section (sigma). These parameters are useful in differentiating between hydrocarbon- and water-bearing formations. Such logs are especially useful in detecting hydrocarbons in cased holes. Thermal neutron capture measurements typically are made by irradiating a formation with bursts of fast [i.e., 14-MeV (2.24 pJ)] neutrons and measuring the decay of the thermal neutron density in the formation. This is accomplished by counting the gamma rays emitted by formation nuclei during discrete time intervals, or gates, following each neutron burst. Today, the widely used pulsed neutron logging system (TDT TM-K) consists of a sliding-gate system in which three measurement gates are used. The first two gates are timed to detect the formation capture gamma rays, while the third measures the background gamma rays. The last 15 years have seen significant evolution in pulsed neutron capture logging. Improvements have increased logging speed and reduced statistical uncertainty. Laboratory studies have defined tool response and established correction factors. Dual detector systems are now available that allow estimation of porosity in addition to measurement of sigma. This latter feature permits stand-alone water saturation estimates with pulsed neutron equipment. In spite of this continual improvement, the increasingly stringent requirements on through-casing water saturation determination for monitoring and enhanced recovery programs have outpaced these developments. To meet these increased requirements on accuracy and precision, Schlumberger Well Services has developed a new generation of TDT tools--the TDT-M. Through improvements in neutron output, techniques for measuring and recording decay time, and data reduction, these goals can be met. TDT-M Tool Description and Features The dual-spacing TDT-M tool has a diameter of 43 mm (1 11/16 in.) and a length of 9.9 m (32.5 ft), including telemetry section, casing collar locator, and cable head. The pressure rating is 1150 atm (17,000 psi), and the temperature limit is 177 deg. C (350 deg. F). The static measure point is 2.1 m (83 in.) from the bottom of the tool. The telemetry section includes a gamma ray detector. The TDT-M tool is 15 cm (6 in.) longer than the TDT-K tool when the latter is combined with a gamma-ray tool. The TDT-M tool transmits counting-rate data in digital form to the surface from 16 time gates for each detector, in addition to gamma ray and casing collar signals. Tool status information also is transmitted to the surface. A downhole memory is used to store gate counts between telemetry transmissions. The telemetry system is bidirectional. Downward telemetry provides commands that are used to turn on the neutron generator and to change the gate timing program, as is discussed later. The surface equipment requires a computer for the determination of tau and sigma from each detector, as well as for the near/far counting rate ratio and other curves that may be recorded. Either a Cyber Service Unit (CSU TM) or a microprocessor panel CMP-A is required. The CMP-A TM also is used with the PLT-A TM production logging tool string. JPT P. 199^