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.

A method is described for combining multiple wellbore surveys to obtain a single composite, more accurate, well position. Established methods for defining the wellbore position, and its associated uncertainty, rely upon accepting the position obtained from the most accurate survey instrument used in each section of the wellbore. This position is then assigned an uncertainty based on the information from this single survey instrument run. Today, when a modern wellbore is constructed, each section may be surveyed for position many times using one or more magnetic, gyroscopic or inertial survey instruments. By statistically combining the wellbore positions obtained from all of the survey instruments run in a given section of the wellbore a new position, designated the ‘Most Accurate Position’ (MAP), is calculated. The main advantage of the MAP is that its uncertainty is smaller than the uncertainty of any of the constituent surveys. The major benefits of this technique will be to facilitate the drilling of smaller targets at greater distances, allow the drilling of new wellbores in closer proximity to existing wellbores while maintaining accepted safety clearance rules, and improved reservoir delineation. Describing Well Position The wellbore trajectory is defined as a series of surveyed points in three-dimensional space typically described in a North, East and Down reference system. These points are joined together to form a continuous trajectory using a geometrical calculation method1. Most magnetic or gyroscopic survey instruments in use today provide a survey point that is referenced to measured [or along hole] depth that is obtained from the driller's pipe tally, or from a wireline spooling measurement. The survey instrument provides inclination (hole angle) and azimuth (direction) measurements. When these parameters are used to calculate trajectory with an assigned survey depth, the horizontal displacement [or North and East coordinates] from the origin, and the vertical depth [or Down coordinate] from the elevation reference can be derived. Alternatively, some inertial survey instruments measure displacement in three-dimensional space from a known initialization point, and from which all of the above parameters [including depth] can be obtained to achieve the same purpose. Wellbore Position Uncertainty Wellbore survey requirements are typically driven by the need to guide the well to a geological target, to avoid other wells, to ensure that property boundaries are respected, and to record the position of the wellbore for future reference. In order to visualize and quantify our ability to hit a target or avoid colliding with another well, position uncertainty is assigned to wellbore trajectories. This position uncertainty represents our modeled knowledge of the collective errors arising from both the intrinsic performance limitations of the survey sensors and those induced by the operating environment2. This uncertainty is defined as a statistical confidence region with an associated confidence level. In three dimensions the confidence region is most often depicted as an ellipsoid3 because ellipsoids are the constant value contours of the three-dimensional Guassian probability density function. Such a confidence region is commonly referred to as an ‘Ellipsoid of Uncertainty’ (EOU). The EOU is used in target analysis, for example, by reducing the size of the geological target by the size of the EOU to define a drilling target. In this fashion, the geological target will be achieved if the wellbore penetrates the drilling target. Likewise EOUs are used to assess collision risk by considering the proximity of the EOUs from adjacent wells.

Improvements in the quality of wellbore directional surveys using multistation analysis and geomagnetic referencing are demonstrated, with case studies to illustrate the benefits to drilling projects. Multistation analysis is a technique that provides compensation for drillstring magnetic interference. The benefits of multistation analysis can be further improved when used in conjunction with geomagnetic referencing, which takes account of localized crustal effects in the earth's magnetic field. In recent years these improved magnetic surveying techniques have gained increased industry acceptance. Their practical application is delivering the capability to reach tighter drilling targets, and in some circumstances to dispense with the need to run gyro surveys. These techniques are providing tangible and cost saving benefits to help meet the demanding technical and economic needs of these projects. A series of well profiles for wells drilled on projects that use these techniques are presented, each of which use individually mapped local crustal magnetic field models and different drilling assembly configurations. Treatment of each of the major magnetic surveying error sources is discussed, and the effect on surveyed well position when compared with independent overlapping gyro surveys is presented. The benefits from this real-time drilling surveying process also demonstrate the value of the "drilling correction" as a means of drilling more accurately to plan, with a reduced need for correction runs, or post-drilling changes to the planned well trajectory. Introduction Modern directional drilling operations depend on magnetic surveying instruments to provide confirmation that the positional objectives of the well, and hence the drilling target, have been met. These Measurement While Drilling (MWD) instruments are deployed in the bottom hole [drilling] assembly (BHA) in order to provide real-time surveyed position feedback to the driller, and minimize time taken for surveying overall. Magnetic survey tools are robust, relatively easy to calibrate, maintain and run, and their performance is well known and modeled to a common standard in the industry1. Today, the difficulty in making accurate magnetic survey measurements is largely driven by uncertainty caused by two major error sources, declination reference error and interference caused by drillstring magnetism. A growing body of work in the area of geomagnetic referencing2,3, has provided a direct improvement to the reference error problem. Concurrent advances in the treatment of drillstring magnetic interference compensation, particularly with the use of multistation analysis4 have also brought further improvements to magnetic survey accuracy. Experience has now shown that when geomagnetic referencing and multi-station analysis are combined in a robust manner, well positioning accuracy approaching that previously only provided by gyroscopes, can be delivered. A series of case studies based on survey management services provided to BG Group, ChevronTexaco and TotalFinaElf Exploration UK from several geomagnetically disparate North Sea fields are presented to demonstrate the real and practical cost savings achieved using these techniques.

Multistation analysis is a technique that provides drillstring magnetic interference compensation to magnetic surveys. This technique is now in common use in the industry, and this case study data verifies the capabilities of the multistation technique to improve measurement-while-drilling (MWD) azimuth measurement quality and accuracy. This study quantifies a significant improvement to standard MWD surveyed position uncertainty using actual survey data from drilling assemblies used in more than one hundred and twenty runs in over thirty-five different wells worldwide. The use of multistation analysis, and the subsequent reduction in wellbore position uncertainty demonstrated can significantly reduce the overall surveying and drilling costs for the well, removing the need for correction runs and allowing for the penetration of smaller targets than previously possible with standard MWD surveying. This correction technique can be applied on a real-time basis at the point of surveying. Forecasting of the magnetization effects of the bottom hole assembly (BHA) using the same software, will also allow the driller to place the well more accurately. In some cases the use of multistation analysis with standard MWD surveys will enable the removal of one or more gyrocompass surveys from the survey program. This can reduce overall surveying time and cost, and the exposure of the BHA to additional stuck-in-hole risks that occur when running wireline surveying tools through drillpipe in extended-reach wells. The main analysis method is based on a direct comparison of MWD survey data before and after multistation correction, against independent overlapping gyro survey data. The results achieved by this study are translated directly into improvements in current industry standard error models, and this paper proposes a standard error model for multistation analysis corrected MWD survey data. Introduction Modern directional drilling operations depend on magnetic surveying instruments to provide confirmation that the positional objectives of the well have been met. These MWD instruments are deployed in the bottom hole [drilling] assembly (BHA) in order to provide real-time surveys to the driller, and minimize the rig time taken for surveying overall. Magnetic survey tools are robust, relatively easy to calibrate, maintain and run, and their performance is well known and modeled to a common standard in the industry1,2. The main difficulty in making accurate magnetic survey measurements today is largely driven by uncertainty resulting from environmental error sources. Amongst these, one of the largest is interference caused by drillstring magnetism. Drillstring magnetic interference is almost always present because of the desire to place the surveying instrument as close to the bit as possible, and to minimize the cost and impact of placing large quantities of nonmagnetic material in the BHA to magnetically isolate the sensor package. Measured Magnetic Field Components When the BHA is relatively well magnetically spaced, about 95% of the measurement obtained by the magnetometers comes from the Earth's main field. The remaining portion of the magnetometer sensor measurement comes from a combination of local crustal effects (or magnetic features trapped in the solidified Earth's crust), the disturbance field (or the effect of upper atmosphere magnetic effects in the magnetosphere, largely caused by solar activity), the presence of any cultural artifacts (or manmade external magnetic interference, such as from nearby drilling rigs, or other adjacent wells) and drillstring magnetic interference. Drillstring magnetic interference is characterized in two forms; remanent magnetism, which is where components of the drilling assembly are actively magnetized; and permeable effects, which is where the drillstring components have the capacity to be magnetized, and the magnetic field lines are ‘bent’ as they pass through the permeable material. All standard steel drillstring components such as drill collars, drillpipe, stabilizers, roller reamers, crossovers etc, can be magnetized. Even those components that are not initially magnetized, can become magnetized by the effects of the inspection process, laying in the yard or on the pipe deck next to other magnetized components, making up and breaking connections and also from the hammering that occurs during the drilling process itself.

Real time connectivity from the rig to the office is becoming the norm for many operations today. The real time operation support center (OSC) is the hub of these activities in town where domain experts, data interpretation experts, and drilling experts alike can be involved directly in data-centric collaboration and critical decision making. Having the ability to move the point of decision making from the point of data acquisition to the OSC intuitively provides the capability for more effective drilling optimization and the direct saving of non-productive time through risk mitigation. A series of real case studies that show the range and scale of measures, and the interpretive actions that can be taken to optimize drilling and minimize downtime. Direct improvements in drilling rate of penetration through advanced software modeling of drilling parameters will be shown. These cases involve both the reduction of shock and vibration to the drilling assembly, thereby transmitting more of the energy in the system to the bit face, as well as the direct rate of penetration improvements through balancing weight on bit and surface RPM for each drilling system. Other cases will demonstrate improved well placement in the reservoir through the combination of monitoring the drilling parameters in conjunction with the real time data from the formation evaluation downhole tools. Direct troubleshooting of downhole tool problems relating to changes in downhole conditions will also be presented, and in many cases this can save an unnecessary trip out of hole. Together, these case studies will show that significant value can be achieved by maximizing the effectiveness of the OSC, and by fully integrating real time quality and decision making procedures into all drilling operations. It can further be concluded from these case studies that this value can be measured, and can truly create a step change in performance. These improvements can be translated directly into lower cost per foot, and better hole quality, in addition to reduced lost in hole and therefore better equipment utilization.