One of the predicaments of traditional well testing is the requirement of shutting-in a well to conduct a pressure buildup test for the purpose of obtaining well and reservoir properties. This deterrent factor is more prominent in prolific wells due to loss of revenue and problems associated with crossflow or when bringing a well back on production. Moreover, in case of commingled reservoirs, conventional buildup provides only average values of permeability, skin, and pressure. An innovative periodic well testing technique named WTPL (Well Testing by Production Logging) has been developed in which a cyclic wave function is imposed in the wellbore by modulating the flowrate. The analysis of the acquired rate function and the resulting pressure wave then provides formation characteristics such as permeability and skin in the vicinity of the well. This technique eliminates the disadvantage of shutting-in a well and maintains the production with a modulating periodic pattern. In addition, the WTPL can be easily applied to commingled reservoirs to estimate the individual permeability and skin for each layer. This effort has also resulted in the development of a downhole flow modulation tool capable of creating the cyclic flow patterns needed for the new testing method. Introduction In developed fields, a pressure buildup test is the main tool for monitoring well productivity (permeability and skin) and reservoir pressure. However, operators are reluctant to perform such a test as it involves shutting-in their producing well. Shutting-in results in loss of revenue and in some wells with hydrate problems or excessive water production, it also could be difficult to bring the well back on production. Moreover, closing a well for a pressure buildup test might damage the near wellbore by asphaltine deposits or by water crossflow from higher pressured zones to more depleted layers. Another limitation of a conventional buildup test is in its application to commingled reservoirs where it only provides a total permeability-thickness and an average skin value. Usually, permeability is then distributed between different layers based either on small-scale permeability measurements (mainly from cores) or on the flow profile derived from interpretation of the results from production logging testing, PLT, (with questionable uniform skin assumption). In both cases, such a distribution can result in erroneous reservoir characterization. In addition, in case of significant skin contrast between layers, the total permeability-thickness can be underestimated. This paper introduces a new well testing method named "Well Testing by Production Logging" (WTPL) which does not require shutting down the production in order to obtain formation permeability and skin. WTPL imposes short periodic variations of flowrate which result in similar cyclic pressure variations. The resulting reservoir response is recorded bottomhole using a PLT string. The amplitude ratio and phase lag of the pressure relative to the flowrate can then be analyzed to provide formation properties such as permeability and skin factor. A specific flow modulation device was developed to generate periodic bottomhole rate and pressure oscillations. This tool can be combined with standard production logging tools and can be configured for both production and injection wells in several casing/tubing sizes for both high and low flowrates. In commingled wells, it can be sequentially deployed above each producing zone to provide permeability and skin values for each layer. Field examples provided in this paper will describe the application of this technique in detail. The formation properties obtained through this method are also compared with results derived from analysis of traditional pressure transient tests.

Proper characterization of a producing well has significant impact on asset management. Production schedules from different wells and further infill drilling in a field depend on the effectiveness and the pattern of the production drive mechanism. Whether the reservoir displays partial aquifer influx or is waterflooded, the flow profile of produced/injected water as well as the reservoir pressure, permeability, fluid saturations, and formation compaction are useful to properly evaluate the overall sweep efficiency. This information is more crucial in a field with multi-layered reservoirs having different permeability, pressures, and structure. Data acquisition should be scheduled and compared to baseline data such as a baseline pulsed neutron capture, production, or compaction logs. There should also be plans to monitor specific wells over the life of the project to observe and optimize the reservoir performance, characterize the reservoir response, and in the case of waterflooded reservoirs monitor the performance of the waterflood. Multi-rate multi-zone production logging and pressure transient testing are two excellent methods to achieve these goals. Introduction Production in Mars field in the Gulf of Mexico began in 1996 and peaked in June of 2000 at 208,000 B/D of oil and 217 MMscf/D of gas. The deepwater Mars field is a prime candidate for secondary recovery since the predicted primary recovery has limited aquifer support. Monitoring the waterflood with cased hole logs is critical to improving the performance and increasing the overall volume recovery of the Mars field. The ability to acquire carbon oxygen data for monitoring sea water injection and sigma data for reservoir fluid changes, combined with multi-rate production logging and testing is essential in reducing unnecessary risks of well intervention. Many of the Mars wells produce from multiple reservoir layers so multi-rate production logging and well testing surveys are valuable methods to estimate the layer flowrates, pressures, permeabilities, skin factor of individual layers, and distance to and type of boundaries. A surveillance logging program has been conducted in the Mississippi Canyon Block 807 area since 2004 with initial baseline surveys to monitor and to optimize the production performance of the field and to inspect the waterflood progress. This approach allows reservoir characterization without requiring zonal isolation. It also helps to evaluate where the waterflood has influenced pressure maintenance. The results of the multi-rate multi-zone (MRMZ) production logging and testing combined with saturation trends confirm and provide valuable data for the reservoir modeling. Another benefit of the step-rate production testing is the evaluation of the layer contribution to the total production. This data together with estimated individual reservoir layer pressures helps to determine oil reserves and assist in waterflood management. The data acquisition for these wells is being conducted in realtime to optimize the stabilization times for each test period. Thus, the required data is being acquired without recording unnecessary information or conversely, not obtaining sufficient data. The combined pressure transient testing and the MRMZ production logging of several of the wells tested in the Mars field will be described in detail to illustrate the monitoring technique and to show the time-lapse changes occurring in the Mars field. The flow pattern of the produced water, the reservoir sweep, the reservoir pressure profile, permeability, skin damage, and fluid saturations will be provided and discussed in detail to highlight the results of the time-lapse monitoring of the reservoir. Both the waterflooded and the non-waterflooded case studies will be discussed. While pulsed neutron capture and formation compaction logs are mentioned as surveillance tools, they are not discussed in detail.

The newest generation of production logging tools consists of multiple sensors in multiple locations around the wellbore that incorporate 12 resistivity and capacitance probes and six spinners. The capacitance array tool (CAT™) determines the water, oil, and gas holdup in the wellbore. The resistivity array tool (RAT™) determines the holdup of hydrocarbons and water. Likewise, the spinner array tool (SAT™) consists of six bowspring mounted micro-spinners that enable the measurement of the velocity profile. These new tools provide a detailed examination of the flowing fluids in all types of wells, including highly deviated and horizontal wellbores, that is not available with the traditional center sample tools because of the wellbore conditions, especially with fluid segregation. With these 30 measurements, a system of quality control and processing was developed to enable both experienced and non-experienced engineers to determine whether or not the data was correct and valid. A quick analysis tool was developed to enable the field engineer and company representative to enter raw values from the two holdup devices and calibration values, and to determine the holdups from the two sensors. Similarly, entering the raw spinner counts, cable speed, and estimated spinner slopes into the quick analysis tool will provide an estimate of the velocity profile for the SAT spinners and the other spinners that are run. This quick analysis tool graphically shows the holdups and velocity in an easy-to-understand presentation for people who are not production logging (PL) experts. After the raw data in the field is validated, a complete analysis is provided. This analysis includes horizontal, vertical, and 3D images of holdup and velocity profiles; continuous displays of flow profiles; and a complete flow analysis consisting of the split of oil, gas, and water rates at both downhole and surface conditions. This PL data can be presented in standard log formats, spreadsheets, and other methods as needed. This process can be modified by either the service company or customer. Several examples are provided that show the capabilities of the new logging tools and the interpretation method used to determine the results. Introduction Phase segregation occurs in many wells, including those with little deviation from vertical; the lighter phases migrate to the high side of the wellbore, and the heavier phases migrate to the low side. In highly deviated and horizontal wellbores, traditional PL sensors, which are center sample tools or have single point measurements, may not provide the most accurate data as a result of the wellbore and well flowing conditions. These PL tools measure fluid properties, such as velocity, density, capacitance, temperature, and pressure. Tool position, or more accurately sensor position, may lead to incorrect interpretations regarding the flow environment of the well. New PL tools have been developed to help address the issues in deviated or horizontal wells. These new tools include two types of holdup measurements, capacitance and resistivity, as well as multiple velocity measurements. These new tools will be referred to as Production Array Logs (PAL) to distinguish them from the standard PL logs. These tools provide a relative bearing measurement that enables the location of each sensor to be determined. The velocity tool also includes an inclination measurement to aid in the analysis of the PAL data. The holdup tools have 12 measurement probes, and the velocity tool has six spinners. These tools, when run in conjunction with the standard tool string, provide multiple measurements around the entire wellbore. The interpretation of each tool individually is complex and, when combined with the other PAL measurements, the complexity increases dramatically. A new interpretation process was developed that combines the benefits of the newer sensors and addresses problems caused by the deviated and horizontal wellbores in the standard PL interpretation procedures.

A new logging tool that is will identify the free point in drill collars, drill pipe, tubing, or casing has been developed and field tested. The tool is commercially available in the wireline service sector for drilling support and well abandonment operations. Unlike previous free point methods, which used strain measurements of the pipe obtained as a series of stations with and without the application of pipe stretch or torque at each station, this new method is simply overlay of two logging passes. The first logging pass is recorded with the pipe in a neutral weight condition, and the second logging pass is recorded with tension or torque applied to the pipe. The tool utilizes the property of steel called magnetostrictive effect. When a mechanical stress is applied to the steel, the magnetization of the material is modified. Thus when torque or tension is applied to the pipe that is free to move, their magnetization will change. If the pipe is not free to move their magnetization will remain the same. The tool has been successfully tested in steel alloys that have minimal magnetic properties. This new logging tool has many advantages over legacy free pipe determination methods. First, from a rig safety standpoint, the application of pipe stretch, or torque is applied only once for a few minutes for the logging pass. With legacy free point methods numerous stationary measurements were required, with the pipe being stretched/torqued at each station. Since determination of free point is a comparison of two logging passes, real time operations and 24/7 satellite communications allow remote based operator and service company pipe recovery experts to be involved with the well site decisions. While this new technology uses a comparison of two logging passes, well site operations is not dependent on a pipe recovery expert with extensive hands on experience to be on location, or delays waiting for pipe recovery experts to arrive on location. This benefit is extremely important with the aging of the industries workforce. The small diameter logging tool is run centralized, and does not require weight bars added to the tool for slip engagement, this shortens the length of the tool string and simplifies e-line rig up procedures. Introduction Previous generation free point tools utilized strain gauge measurements which detected the stretch or rotation of the drill sting when the free point tool was mechanically anchored in the drill sting and force applied to the pipe. The determination of the free point required many stationary measurements over the estimated stuck point region with the drill string in a neutral condition and then again with either tension, or torque being applied during each recording. Mechanical slip engagement of the strain gauge sensor in the vertical and azimuthal planes is critical. This method often requires many hours of rig time and the talents of a highly skilled free point logging expert. The tool utilizes the property of steel called magnetostrictive effect1. When a mechanical stress is applied on steel material; the magnetization of the material is modified. When torque or tension is applied to the pipe that is free to move, their magnetization will change. If the pipe is not free to move their magnetization will remain the same.

This paper discusses a new, innovative tool, namely a hydraulic jar with a mechanical lock developed to run on wireline cable. The discussion addresses (1) the role and value of wireline jars in electric line operations, (2) technical features of the new wireline jar system with comments on its operation, and (3) a brief review of several of the many successful field applications. Getting stuck during a logging operation can add significant cost to a well. The new wireline jar has proven to be remarkably effective in freeing stuck wireline tools and preventing costly fishing operations. Freeing the tools also provides the opportunity to complete the required data acquisition as the instruments have historically not been damaged by jarring. In addition, the use of the wireline jarring method described in this paper allows operators to run relatively inexpensive free-fall wireline tools in areas that previously ? due to sticking problems ? have gone straight to drill-pipe-conveyed operations or logging while drilling (LWD) methods. A multi-conductor jar, called the LockJar®, has been in use for more than four years. The jarring system utilizes a proprietary-design LockJar and Enhancer, both of which remain passive until such time as they are needed. The LockJar can be pulled, without triggering, as hard as desired for durations shorter than the tool's time delay. Slacking off the string resets the LockJar so that it can be pulled again. Experience with this new technology has also led to discovery of valuable best practices for handling stuck tools, which has increased the number of freed tool strings. Among these best practices is the use of properly placed standoffs, particularly in inclined sections of wellbores. Experience with this new technology began in the GOM but the technology has quickly spread around the world to locations that experience problems with sticking during logging. In the GOM, several examples can be cited including a job where the LockJar was activated over 20 times in six different intervals; and still the well was successfully logged. This well was the very first in the field that was logged without a fishing job. Successes described in this paper include an example from the US Rockies and in Brazil and other international locations, such as West Africa, where the LockJar also freed tools on their very first run. Introduction Within wireline logging operations, it had generally been accepted that key seating was the primary reason for getting stuck. It was not known whether tension pulled on surface was actually reaching the top of the tool string because stress at the top of the string was not measured. Without this information, it was not possible to easily confirm whether the location of the sticking point was or was not up hole. The calculations required for determining the maximum pull available at the point in the well where the tool string was most likely stuck is time-consuming and tedious, adding to the overall time before activating a maximum pull. Thus, in many cases, by the time the location of the sticking point was determined, plenty of time to become more fully key seated had passed. With the introduction of the technology described in this paper, experience has shown that in most cases in wireline logging, the tools become stuck, not the wireline cable. This experience has led to the understanding that - similar to the case in drilling - the sooner one applies maximum overpull to the jars and toolstring after the toolstring becomes stuck, the better the chances of successfully freeing the tools. Fishing is costly at any time during well drilling and completion, including during logging operations. The costs in delays and in the value of lost or damaged equipment can easily run into the hundreds of thousands of dollars. Therefore, anything that contributes to freeing a stuck tool quickly and efficiently has the potential to save not only time, but money.