Theorectically, the perforation shot origin time T 0 affects the accuracy of the inverted velocity structure, and therefore the accuracy of subsequent microseismic event locations. The origin time can be obtained from perforation timing measurements or estimated from the picked arrival times. In order to investigate the role of origin time in velocity calibration, we designed two inversion procedures. In procedure A, T 0 is calculated during the Occam's inversion while T 0 is set to its true value in procedure B. A grid search locator is applied on both inverted models to produce two locations. We constructed three synthetic P-wave velocity models and add normally distributed random noise to the synthetic arrival times of all models. The noisy synthetic data are piped through procedure A to obtain location A and through procedure B to produce location B. Graphical analysis show that location A is closer to the true shot location than location B although both are close to each other. If we remove the data noise and repeat the test, location B is closer to the true shot than location A. It was observed that the inverted location A is better in terms of the distance from the true location if using noisy data and location B is better if using noise-free data. This indicates that uncertainties due to data noise cause our inconsistent observation and implies that perforation timing measurements are not necessary and may actually result in a less accurate velocity model.

A new generation crossed-dipole acoustic-logging tool acquires data that can be utilized to calculate shear anisotropy. This new tool, the WaveSonic™ tool, was designed using a systems approach so that tool functions such as transmitted pulse shape, center frequency, amplitude and duration are programmable from the surface. Additionally, the tool design is robust enough to allow drillpipe conveyance if well conditions warrant. It can also be combined with other logging tools and is "double-ended", allowing it to be located at any position in the logging tool-string. Shear data can be collected in orthogonal X-Y directions and oriented by a navigational package using data from a four or six-arm caliper device run with the WaveSonic tool. From these measurements, shear slowness anisotropy can be determined, as well as the direction of the fast shear slowness. These slowness values provide input to a model that calculates maximum and minimum principal stresses and their orientations. Information about principal stresses can be instrumental in optimizing completion and stimulation design. In cases where natural fracture information is desired, crossed dipole data can be used to help detect and orient such fracture systems. Introduction The WaveSonic crossed dipole sonic tool is an entirely new wireline sonic tool design.1 The design engineers and scientists were given the luxury of designing the tool "from the ground up", without being required to incorporate legacy features from other tool platforms. The key mechanical design requirement was physical strength, so that the crossed dipole sonic tool could be positioned anywhere in the tool string, allowing extremely "heavy" tools, such as new generation pump-through formation test tools and nuclear magnetic resonance tools, to run in combination below (or above) this tool. The WaveSonic tool is the first acoustic waveform wireline logging tool designed robustly enough to allow drillpipe-conveyed logging operations, where necessary. The WaveSonic tool is composed of the following components: transmitter with associated control electronics, isolator, receiver array and main electronics. All tool functionality is controlled by a surface computer, thus eliminating the necessity to pull out of the hole to change logging parameters. One of the key features of this tool is the ability to control the frequency of the crossed dipole source, allowing flexural shear wave transmission in reservoir rocks having a broad range of shear slowness values. Dipole transmitters are of the "Bender Bar" variety. The "X" and "Y" dipole sources are mounted orthogonally at the same position of the tool, ensuring maximum utilization of all received waveforms for post-processing analysis. The receiver array consists of 8 receiver "rings" spaced 0.5 feet apart. Each receiver ring is comprised of four independent receivers that are matched for frequency response and oriented in the directions of the "X" and "Y" transmitters. Detailed shear anisotropy analysis necessitates matching of frequency responses of receivers over a broad band of frequencies. The tool transmitters (monopole, and X- and Y-dipole) are fired sequentially, and all 32 waveforms associated with each transmitter firing are digitized and sent uphole - real-time - for every 0.5 feet of log. The logging speed for crossed dipole acquisition is 30 ft/min (1800 ft/hour).

fax 01-972-952-9435. AbstractWith the increase in deepwater exploration and production and the advances in logging-while-drilling formation evaluation (along with the high rig costs) the wireline formation evaluation is often limited to only one drill pipe conveyed logging run. A new monopole and crossed dipole acoustic logging tool was designed for the drill pipe conveyed environment. The robust mechanical design does not limit this sonic tool to the bottom of the tool string. NMR and pump-through formation testing tools can be located in the logging string below this tool on drill pipeconveyed logging, or e-line conveyed logging.This tool was designed utilizing a systems approach and most of the functions of the tool are surface programmable. For example, the pulse shape, duration, amplitude, and frequency of the on-depth crossed dipole bender bar sources is programmable. Likewise, the level of the monopole output signal is also surface selectable. The digitization of the 96 waveforms of data per depth sample is programmable for number of samples, sampling interval and waveform compression. With 96 waveforms per depth sample, a logging speed of approximately 1800 ft/hr (30 ft/min) can be achieved with a quad-combo logging suite acquiring sonic data at two samples per foot.Case histories from a variety of formations demonstrate the tool's capability to obtain monopole P wave data, monopole refracted shear data, crossed dipole flexural wave slowness, and anisotropy.The following representative formations are included in the case histories: • near-zero porosity carbonate with refracted shear wave slowness and flexural wave slowness of less than 100 µsec/ft • poro-plastic Gulf Coast sandstones and shales with flexural wave travel times exceeding 700 µsec/ft • formations with natural fractures that are detectable by the cross dipole flexural wave slowness and confirmed with open hole image data • a shale section with approximately 650 psi of stress anisotropy About the Authors Calvin Kessler, is the Business Development,

Combining meawiernent, simtilafion,..m. dbnaging technologies into an integ@ted program .can help operators achieve the best hydraulic f~cture treatment possible. Hydrocarbon production can be signi@iMy increased when fractures tire extended to the planned length, and fracturing fluid is.rektined within t& zone of interest. Fractures that briali out of zbne incfesse the risk of excess water "production with the hydrocarbon. Consequefitly, the ability to select suitable operational parameters for hydraulic fracturing is critical to job SUCCS.3S.An evacuation of formitkiii piopeiti& and potenfib amiem to hydraulic fracttiijng can bc made with three-"" "dimensional (3D) simulatiori to integrate data tzken from wirelirie logs, wzveforni sonic-logs, and.microfrai measurements. In-situ stress "orietitationis determined by use of a downhole extensonieter, oriented cores, mrelastic stmin rccovefy (ASR)"measnrements, and -" borehole imaging logs.-Sidewall cores. can be taken perpendlculzr to wellbore walls without distorting-the. borehole or the core tafcen; orientation of the cores can be determined with imagingReferences at the erid of the paper. 575 logs run after coring. Nat@ tka@rres can be viewed with a downfrole video csmera lowered into the well on fiberoptic cable."Effectiveness of fracture &eatmerrts may be evalnated with vsrious gamma ray logging techniques aod production Iogiiorgparirig expectsd production to scturd zonal contribution. Refried procedures that re:nlt from 'after-fiat-analysis can be,used to-pkm field development for optimal reservoir drainage.

Costly lost circulation, crossflows, and underground blowouts result in mud losses, wasted rig time, often ineffective remediation materials and techniques, and sometimes lost holes, sidetracks, abandoned wells, relief wells, and lost petroleum reserves. In early 1996, a service company initiated a project to review conventional remediation materials and methods, search for more effective remedies, and field-test new solutions. The project has led to the development of several novel lost-circulation material squeeze systems (LCMSS). These LCM squeeze systems were applied in wells after conventional materials/methods failed, and they successfully cured lost circulation, increased the ingerity and frac gradient (FMW) of weak zones (formations with low mechanical strength), sealed high-pressure water and gas zones, safely allowed deeper drilling, and stopped underground blowouts. Data from these field tests show encouraging trends and prospects not only to save costs associated with drilling trouble, but also to reduce normal exploration and production costs for casing, liners, drilling/completion fluids, rig time, poor primary cementation, remedial cementing, and water production. Introduction API data1 in Table 1 indicates that lost circulation occurs in a significant percentage of wells. In some areas lost circulation occurs in 40 to 80% of wells. Several operators in such areas asked for new solutions to reduce or eliminate lost-circulation trouble, which can cost an additional several hundred thousand dollars to several million dollars per well. These unplanned costs were the result of wasted rig time, unsuccessful remedies, and many thousands of barrels of mud lost to various types of weak zones. Some operators needed to plug and seal these weak zones to stop crossflows that had led to underground blowouts (uncontrolled subsurface flow of oil, water, or gas). The preferred solution was to plug and seal the flow's exit point in the well (weak zone) and then either densify the drilling fluid to overbalance the flow influx point (high-pressure zone) or to plug and seal the flow influx zone. Other operators requested LCMSS for the following tasks:The treatment had to withstand certain EMW (Equivalent Mud Weight) squeeze pressures to allow an increased mud weight to overbalance deeper, higher pore-pressure zones when drilling resumed.The seal had to last for as much as several weeks of drilling until the next casing seat depth was reached.The plugging seal had to withstand both negative (swab) and positive (surge) pressures applied during drillpipe trips, casing runs, etc.The treatment needed to allow higher pump rate mud displacement and the accompanying higher equivalent circulating densities (ECDs).The treatment needed to eliminate the waiting periods after the maximum squeeze pressure was obtained to allow immediate washout of excess LCMSS in the hole and pressure testing for the improved formation integrity.The treatment had to eliminate an unplanned drilling liner.