fax 01-972-952-9435. AbstractThe measurement of continuous real-time inclination provides near instantaneous calculations of the build-up rate tendency of a bottom hole assembly in both rotary and slide drilling modes. The addition of an azimuthal measurement now allows for the calculation of wellbore position with this continuous data. The true nature of the wellbore curvature in slide/rotate directional drilling with steerable systems is lost when using the typical 90-foot survey interval. Continuous surveying shows this effect. When wellbore position is calculated with the continuous surveys, a significant positional discrepancy from the stationary surveys can occur.A study was conducted using both stationary and continuous survey data from over 20 wells in Nigeria, Angola, the Gulf of Mexico, the North Sea and Indonesia. The objective was to determine the magnitude and scope of TVD positional error caused by the different slide and rotate curvatures between stationary surveys on a wide range of wells. These curvatures are not reamed out as commonly thought. They can still be seen in continuous gyro surveys taken after drilling has finished. This positional effect is not a function of the sensor accuracy, but it is a result of the environment in which surveys are measured. We show that in a horizontal well the effect can accumulate up to plus/minus 25 ft TVD. The implications of these results are far reaching. Survey positions are used in creating structure and reservoir maps, which are used in determining reserves and recovery efficiencies, and in turn for making field management decisions.This paper highlights the results of the field studies. A review of rotary steerable system operations shows that the effect is much less than with steerable motors, but can still be of concern.A low-cost solution for effectively determining when to slide and rotate with respect to the stationary survey is presented. This procedure results in a positional accuracy that can be maintained without changing survey data management practices.

We introduce a sector-based inversion method to improve the petrophysical interpretation of logging-while-drilling density measurements acquired in high-angle and horizontal wells. The central objective is to reduce shoulder-bed effects on the measurements. This approach is possible because of a recently developed technique to accurately and efficiently simulate borehole density measurements. The inversion-based interpretation method consists of first detecting bed boundaries from short-spacing detector or bottom-quadrant compensated density by calculating their variance, representative of the measurement inflection point, within a sliding window. Subsequently, a correlation algorithm calculates dip and azimuth from the density image. Depth shifts that vary azimuthally and depend on relative dip angle, together with the effective penetration length of each sensor, refine previously selected bed boundaries. Next, the inversion method combines sector-based density measurements acquired at all measurement points along the well trajectory to estimate layer-by-layer densities. In the presence of standoff, the method excludes upper sectors most affected by standoff to reduce inaccuracies due to borehole mud. To verify the reliability and applicability of the inversion method, we first use forward simulations to generate synthetic density images for a model constructed from field data. Results indicate that inversion improves the interpretation of azimuthal density data as it consistently reduces shoulder-bed effects. Inversion results obtained from field measurements are appraised by quantifying the corresponding integrated porosity-meter yielded by inversion methods in comparison to standard techniques that use simple cutoffs on field-processed compensated density. Integrated porosity-meter of inverted synthetic density measurements increases by 4.6% with respect to noninverted field measurements. Also, integrated porosity-meter obtained from inversion results that include only bottom sectors improved by 65.4% with respect to that calculated with field-compensated, bottom-quadrant density measurements.

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Directional drilling is accomplished by causing a mechanical or hydraulic deflection of the bit during drilling. Predicting BHA behavior prior to drilling and taking survey check-shots while drilling is common practice because understanding the directional tendency of a BHA is critical to successful well placement. It has been suspected that different modes of drilling cause a near instantaneous change in the size, shape and centerline position of the borehole and, thus, change BHA tendencies. This is not backed up by continuous MWD inclination data which shows a long transition between the slide/rotate zones. Since examining a wellbore to accurately determine these effects is impractical, a logical approach would be to set up a directional drilling process where the wellbore could be dissected and examined. Precise measurements of the wellbore centerline, diameter or circumference can be made under laboratory conditions and compared to field sensor measurements to determine the accuracy of the field measurements in terms of wellbore position, tortuosity and rugosity. Schlumberger developed a directional drilling test capability utilizing concrete blocks placed sequentially and drilled horizontally. The blocks can be positioned to accommodate changes in wellpath. They are sealed to allow mud flow during the drilling and then broken apart for extensive laser measurements and scans. The blocks are tagged to allow surveying to maintain a 3D coordinate system to millimeter accuracy. Chevron and Schlumberger conducted a series of drilling tests to evaluate wellbores drilled with positive displacement motors (PDM’s). The blocks were drilled with slide/rotate sequences with up to 10 deg/100ft curve rates. Multiple MWD directional surveys were taken and compared to the actual position of the wellbore from the lab measurements. This paper discusses the TVD accuracy of the well as a function of different survey spacing and its impact on horizontal well placement. Changes in touch points of the BHA within the varying hole diameter of the slide/rotate sections are also discussed. Metrics are proposed for managing wellbore quality in terms of tortuosity and rugosity along with their impact on the wider drilling community.

The Delaware Basin of west Texas and southeast New Mexico has seen a resurgence of drilling activity reflecting advancements in horizontal drilling, hydraulic fracturing technologies, and the industry's focus on oil assets. The targeted reservoirs include the Delaware Mountain Group sands, Bone Spring tight sands, and the Avalon and Wolfcamp shales. These formations represent a series of multiple-stacked transgressive sequences comprised of naturally-fractured, low-porosity interbedded carbonates, clastic sands, and shales. Formations are composed of varying amount of quartz, calcite, dolomite, kerogen, illite, albite, and pyrite. This mix of minerals leads to grain densities that vary from 2.5 g/cc to 2.7 g/cc and pose a major challenge when estimating porosity, water saturation, and net pay. A grain density uncertainty range of 0.2 g/cc can increase the error bars on porosity by 6 porosity units and dramatically impact resource estimation. Therefore, an uncalibrated petrophysical interpretation in this complex environment leads to large uncertainties in calculated values. Addressing the grain density issue requires a clear understanding of the mineralogy from core XRD and availability of geochemical logs. Additionally, a high quality logging suite including a triple-combo, NMR, spectral GR, dipole sonic, imaging logs, and geochemical logs are needed. These are analyzed by using calibrated mineral models, mudlogs, drilling parameters, comparison with core data, and production tracer data to deliver a reliable interpretation to be used for production forecasting. If the logging suite consists of only triple-combo and Spectral GR logs, analytical techniques in conjunction with mineral modeling can be used to estimate total organic carbon content (TOC) and porosity but such methods yield higher uncertainty in petrophysical parameters. This paper describes a case study on a complete logging and interpretation program. A workflow is presented based on mineral modeling of both pilot holes and laterals wells depending on the available data. One key lesson learned in this exercise is to understand the accuracy and precision of each measurement and plan ahead for redundancy as operational constraints can pose a challenge when relying on only one technique or technology for interpretation. Our results show that default uncertainty bounds for the logging suite may need to be changed and the error bars have to be widened to account for log repeatability. Comparing the rotary cored depths and the resistivity imaging tools indicate issues with depth control that can be attributed to tool string motion and cable tension. Imaging logs showed many drilling induced fractures in the target intervals but formation testing with straddle-packers in the pilot did not provide any successful pressures or formation fluid samples due to the low permeability and lack of a natural fracture network in the near-wellbore region. However, we were able to successfully induce fractures in multiple zones using a micro-frac tool and the results compare favorably with geomechanical logs. Logging while drilling (LWD) measurements in the lateral showed significant lithology variations is compared and validated with production tracers.