This paper will describe a new method for improving Logging While Drilling (LWD) depth accuracy. Case studies that describe this technique will also be presented. It is generally accepted that using the Drillers depth measurement for LWD applications has been the most practical solution to a complex depth problem. The various sources of depth errors have also been described and quantified in the industry. Two of the main contributors to drillpipe based depth error are mechanical stretch and thermal expansion. Of these, the mechanical stretch is governed largely by the well profile, linear weight of the pipe, and the frictional forces that can be calculated using industry standard torque and drag calculations. The coefficient of linear thermal expansion of the drillstring components and the distributed temperature of the drillstring assembly at the time of measurement govern the change in length due to temperature. To compensate for these effects requires a series of algorithms that identify the mechanical condition of the drillstring at the time of measurement based on the operational drilling mode. Then, a standard torque and drag model is used to calculate the mechanical stretch, and a thermal expansion algorithm subsequently applies the temperature component of the depth correction. The results of these computations are a corrected logging depth, and an improved time to depth conversion file that can be used to recalculate the logging data. The results from case study data strongly support that; uncorrected standard LWD depth accuracy today is often at least as good as that provided by comparable wireline logs; and that LWD depth can be significantly improved using this technique. This new method for improving logging depth will lead to enhanced single well evaluation and the improved well-to-well correlation of reservoir features, and hence the value of the reservoir model. Drillers Depth LWD measurements are referenced to Drillers depth, and this is generally based on a listing of hand measurements made on each length of pipe lowered into the well. To provide a continuous depth for the log data, the movement of the block is tracked at surface, using a geolograph or drawworks encoder1 (figure 1). For each foot that the block travels up or down, it is assumed that the bit travels and equal distance out of or into the hole. Bit movement is only updated when the pipe is apparently "out of slips". In and out of slips is determined by software that monitors a hook-load sensor attached to the drilling deadline. As drillpipe is moved up and down in the well, the LWD depth tracking inevitably starts to deviate from Drillers depth due to errors in determining in and out of slips, depth sensor calibration errors and errors in the pipe tally itself. As a result, in practice the LWD depth is periodically adjusted to match driller's depth. Measuring the bit depth (and hence the LWD true sensor depth) at surface also neglects the changes in pipe length due to hole geometry, temperature and mechanical stretch. Surface depth measurements assume that the drill pipe is a rigid body and that any movement at surface is immediately translated into the equal movement of the bit down-hole, which may be several miles away. So even if it were possible to make a perfect depth measurement at surface, bit depth would still be in error.

The emergence of formation pressure measurements in the Logging-While-Drilling (LWD) market has highlighted the challenge of analyzing and interpreting the pressures acquired. The dynamic condition of the borehole and the freshly built mudcake add new variables to the problem and contribute in making the measurement more complex to interpret compared with measurements made by conventional wireline-conveyed methods. This paper presents several formation-pressure-whiledrilling case studies conducted in the North Sea. Formation pressure measurements were repeatedly performed under different well conditions and at different times after the bit penetrated the formation. The impact on the measurement of various parameters is analyzed, most notably, the time after drilling and changes in the measurement sequence. The results obtained with the formation pressure while drilling tool are compared to measurements performed with conventional wireline formation testers (WFTs) conducted at the same depths and at various times after drilling. Analysis of formation cores taken in the same intervals as the pressure tests were performed allows a better understanding of the while drilling-derived mobility measurements. Suggestions are made on how to improve the quality and accuracy of the measurements. Introduction Probe-type formation testers measure the pressure at the wellbore wall, the sandface, which, in oversimplified terms, is also the interface between the external mudcake and the formation. Fig. 1 is a sketch of this simplified view. Whether or not the pressure at the sandface is a good estimate of the true, far-field formation pressure depends on both the properties of the mud and the formation. If the filter cake is totally ineffective the formation tester will measure the wellbore pressure, whereas if the mudcake is perfectly sealing, given sufficient time, the tester should measure the true formation pressure. We are concerned here with the situation in which the mudcake forms a less than perfect seal allowing mud filtrate to leak into the formation resulting in a pressure drop from the sandface to the outer reaches of the formation. The radial change in pressure is primarily dependent on the sealing efficiency of the mudcake, the formation mobility and the difference between the wellbore and formation pressures. When the difference in pressure between the sandface and the formation pressure becomes significant, where the measure of significance depends on the application, the formation tester pressure is usually said to be supercharged. The degree to which the formation is supercharged is characterized by the overpressure, ?pS=psf-pf, where psf denotes the sandface pressure and pf represents the far-field formation pressure, (Fig. 1).1,2 Depending on the mud type and the reservoir fluids present, rock wettability and capillary pressure effects may also affect the sandface pressure measurement. It is not difficult to understand that the degree of supercharging depends at least on the history of the filtration rate from the moment the formation was first drilled, with the most recent history having the greatest effect, and, on the ability of the formation to accommodate the influx of filtrate, i.e., the degree of supercharging should be inversely related to the formation (total) mobility.2 Anything that inhibits the ability of the mudcake to seal the formation against filtration increases the supercharging effect; in particular, any action that limits the growth of mudcake or promotes the erosion of an established mudcake, such as, the scraping action of the bit and stabilizer blades and the mud circulation rate. It is known that even after a mudcake has had sufficient time to build to maximum resistance the ability to seal against invasion can be compromised by wiper trips.3

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractVeslefrikk is a North Sea oil field in its tail-end production period where optimal well placement is critical for the drainage of the remaining reserves. This paper presents two case studies representing different challenges with respect to geosteering. In both cases a newly developed Directional Electromagnetic logging while drilling tool (D-EM) was used together with a fully rotated point-the-bit 3D rotary steerable system (RSS) to achieve proactive geosteering. The LWD tool was able to detect resistivity contrasts in any direction up to 5 m from the wellbore. In the first case the objective was to position a 570 m long horizontal well section 1-3 m below the top of the reservoir sand, thereby attaining maximum distance from the water level and ensuring that no attic oil was left behind. In the second case the challenge was to optimize the amount of oil filled sand along the 1100 m horizontal trajectory, while drilling perpendicular to the depositional direction in a fluvial channel system.The early detection of the sand to shale boundaries resulted in an increase of 10-15 % in the recoverable reserves for each well compared with conventional geosteering.The workflow setup for both cases included the use of a Web-based system for communication and data transfer. This ensured efficient decision-making involving geosteering specialists, wellsite geologists, and onshore company personnel.

Historically, acquiring borehole image logs and resistivity at the bit measurements of useable resolution have been difficult, if not impossible, when using oil-based drilling fluids. Conversely, in many applications, drilling objectives and other performance criteria prohibit the use of water-based fluids, which deliver logs of higher resolution. Azimuthal borehole images in oil-based mud systems are delivered by wireline conveyed ultrasonic measurements or azimuthal density measurements made while drilling. Higher resolution images have generally been out of reach in oil-based systems because the measurement technology used to deliver these services involves passing electric current through a conductive borehole fluid. Resistivity-at-bit devices used for geostopping and geosteering also rely on electric current transmission from the bit to the formation and are optimized for a conductive mud system. In many applications, drilling objectives and other performance criteria prohibit the use of water-based fluids, thus placing high-resolution images, resistivity-at-the-bit, and the high-value applications that these services can deliver out of reach of the reservoir evaluation and well placement teams. This paper describes the development and successful application of a conductive oil-based drilling fluid system that produces water-based logging quality and enhanced geosteering without sacrificing the performance advantages of invert-emulsion fluids. This unique system, employs an electrically conductive continuous phase that provides a high-performance fluid with a conductive mud, filter-cake and filtrate. The authors detail the development of the system, which included a yard test where fluids of varying conductivity were circulated through a test well with formation micro imager response determined and compared against measured conductivity. Further, the authors discuss the application of this new system on the Gullfaks South in the Norwegian sector of the North Sea, where the fluid was used to drill a highly deviated well through complex geological structures. In this application the fluid showed the drilling performance expected from an invert-emulsion oil-based fluid (i.e. high penetration rates, wellbore stability and low torque/drag). Results from formation micro image logs and resistivity-at-bit measurements taken using this fluid are presented and discussed. The authors also review lessons learned in the development and field application of this conductive fluid, and address current limitations and future developments. Introduction The use of finely detailed formation imaging logs is an increasingly critical component in evaluating the full potential of a field prior to initiation of the development phase. Over the years, a number of advances have improved the techniques and tools used to evaluate the potential productivity of a reservoir.1,2 Azimuthal image logging is aimed at acquiring detailed geological and petrophysical data of formations crossed by the wellbore. Acquisition and analysis of these images allow recognition and quantification of geological features, such as structural and sedimentary formation dip, sedimentary features, and the presence, orientation and type of fractures and faults. The level of detail available for subsequent processing, is driven primarily by the resolution and azimuthal coverage provided by borehole imaging devices.