Combining Magnetic and Gyroscopic Surveys Provides the Best Possible Accuracy

A survey program is designed for every well drilled to meet the well objective of penetrating the target reservoir and avoiding colliding with other offset wells. The selection of the wellbore survey tools within the survey program is limited in number and accuracy by the current surveying technologies available in the industry. This article demonstrates how a higher level of accuracy can be achieved to meet challenging well objectives when the accuracy of the most accurate wellbore surveying technology individually is not sufficient.This highest level of wellbore positioning accuracy to date is achieved by combing two wellbore positions of the same wellbore trajectory. The first wellbore position is calculated using the latest technology of magnetic Measurement-While-Drilling (MWD) Definitive Dynamic Surveys (DDS). The accuracy of the MWD DDS has been enhanced by correcting potential error sources such as misalignment of the survey package from the borehole, drill-string magnetic interference and limited global geomagnetic reference and accelerometer sensor accuracy. Further, the MWD DDS inclination accuracy is improved using an independent inclination measurement from the Rotary Steerable System (RSS). Hence the first position is derived from magnetic MWD DDS after applying In-Field Referencing (IFR), Multi-Station Analysis (MSA), Bottom Hole Assembly (BHA) sag correction (SAG), and Dual-Inclination (DI) corrections. A Second wellbore position is calculated using the latest technology in Gyro-measurement-While-Drilling (GWD).The results and comparisons of multiple runs are presented. The highest accuracy of wellbore positioning had been proven in successful case studies by penetrating a very small reservoir target on an extended reach well that was unfeasible using either the most accurate enhanced MWD DDS or the latest GWD technology. The presented case study shows how the wellbore objectives of penetrating the tight target reservoir had been confirmed by Logging-While-Drilling (LWD) images and interpretation of the subsurface team. This gave the highest accuracy of the wellbore position accuracy to date while drilling assured placing the well with higher confidence to maximize reservoir production without colliding with nearby offset wells.In reservoir sections, the wellbore survey accuracy limits boreholes' lateral and true vertical depth spacing, constraining reservoir production. In the top and intermediate sections, wellbore survey accuracy limits how close the well can be drilled in the proximity of other offset wells. This directly impacts the complexity of the directional work and the cost per drilled foot. This technique unlocks the potential to improve the wellbore positioning accuracy significantly. It demonstrates the highest wellbore positioning accuracy achieved to date when compared to the latest magnetic MWD surveys after correcting all known errors compared to the GWD.

A survey program is designed for every well drilled to meet the well objective of penetrating the target reservoir and to avoid colliding with other offset wells. The selection of the wellbore survey tools within the survey program are limited to the current accuracy available to the industry. A newly developed wellbore survey technique has proven to have superior accuracy compared to the current standard measurement-while-drilling (MWD) surveys with in-field referencing and multi-station analysis (MSA). In almost every drilling bottom hole assembly (BHA), there is an MWD survey tool to survey the wellbore while drilling. Accuracy of the MWD surveys has been improved over the years by correcting potential error sources such as misalignment of the survey package from the borehole, drillstring magnetic interference, limited global geomagnetic reference, and gravity model accuracy. This new positioning technique takes the accuracy of MWD surveys to the next level by combining surveys from two independent survey packages. The second survey package is installed inside the rotary steerable system (RSS). Surveys from both packages are retrieved while drilling. Results have been obtained from multiple runs worldwide, enabling comparisons between the new technique and standard MWD surveys from both an enhanced accuracy and true wellbore placement point of view. A proposed error model is based on both the theoretical improvements in accuracy and the empirical proof from the data analyzed. The improved accuracy while drilling assures higher confidence that the well placement will maximize reservoir production and avoid collision with nearby offset wells. In reservoir sections, the wellbore survey accuracy limits the lateral spacing, and this constrains the reservoir production. In top and intermediate sections, wellbore survey accuracy limits the well plan, and this affects how close the well can be drilled in proximity to other offset wells. This directly impacts the complexity of the directional work and the cost per drilled foot. The new technique unlocks the potential to significantly improve the wellbore positioning accuracy.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 175539, “Magnetic Referencing and Real-Time Survey Processing Enable Tighter Spacing of Long-Reach Wells,” by Stefan Maus, SPE, Magnetic Variation Services, and Jarod Shawn Deverse, SPE, Surcon, prepared for the 2015 SPE Liquids- Rich Basins Conference—North America, Midland, Texas, USA, 2–3 September. The paper has not been peer reviewed. Wellbore position is computed from survey measurements taken by a measurement-while-drilling (MWD) tool in the bottomhole assembly (BHA). The MWD tool uses accelerometers and magnetometers to measure the Earth’s gravitational and geomagnetic fields. Knowing the direction of these two fields and using them as a frame of reference enable drillers to calculate inclination and direction (azimuth) of the wellbore. Local high-resolution in-field referencing (IFR) models have been produced for the Permian Basin that significantly improve the accuracy of MWD azimuth measurements. Ellipse of Uncertainty (EOU) Numerous error sources are associated with MWD-survey measurements, and each error source contributes in some form to the magnitude of uncertainty that propagates along the computed wellbore trajectory. The Industry Steering Committee for Wellbore Survey Accuracy (ISCWSA) developed a framework for quantifying the magnitude of uncertainty. The Operator’s Wellbore Survey Group (OWSG), an ISCWSA subcommittee, continued development on the original error model and published a set of instrument-performance models that enables the computation of EOU for specific surveying methods. This consolidated set is referred to as the OWSG set of tool codes. Fig. 1 illustrates the difference between EOUs for standard MWD vs. advanced corrections using MWD with IFR and corrections for sag (MWD+IFR1+SAG). Generally, one can see that the large uncertainty of standard MWD can be reduced by 11 to 38% by use of IFR, while further applying multistation analysis (MSA) can reduce the uncertainty by 50 to 61%. As shown in Fig. 1, vertical uncertainty can also be reduced by advanced survey-correction methods. Bending of the BHA brings the accelerometer out of alignment with the inclination of the wellbore trajectory. This effect can be corrected for by applying corrections for sag. IFR The objective of IFR is to use local-magnetic- field measurements to produce an accurate 3D magnetic reference model for the drilled volume. The most cost-effective method is to use aeromagnetic surveys, which have been used for more than 50 years to map geology and tectonic features. Earlier IFR methods used fast Fourier transforms or equivalent-source techniques on planar 2D grids. A recent analysis showed that these grid methods can lead to significant errors in the declination and dip reference values because they assume that the crustal magnetic anomalies are entirely contained within the grid. A superior approach is to tie the grid into the global crustal field inferred from satellite measurements and represent the solution in terms of global high-degree ellipsoidal harmonic functions. The IFR method used by the authors first produces an accurate baseline magnetic field for a given reference date. This baseline for the reference date is supplied as an IFR model together with an IFR calculator to the drilling engineer. The baseline can then be extrapolated to any desired drilling date using the main field model embedded in the IFR calculator.

Wellbore surveying is critical while drilling in order to assure the drilled well is following the plan and is penetrating the geological target. Additionally, wellbore surveying is the key to allowing a well to be drilled safely, avoiding other wells drilled in the same field, and optimizing reservoir production. Standard wellbore surveying accuracy is increasingly inadequate for optimizing the well placement in real time to maximize the reservoir recovery due to maturity of the field. The other disadvantage of the standard wellbore surveying often requires running an additional wellbore surveying tool to improve the accuracy in order to manage the collision avoidance with nearby wells in the same field, introducing unwanted time and costs. Hence, this article presents the advanced wellbore surveying technology that is successfully implemented in offshore fields of Abu Dhabi to overcome the limitations of the standard surveying accuracy without compromising rig time. Magnetic measurement while drilling (MWD) surveys are common standard and utilized in every directional well in this operation. To overcome the standard accuracy limitation, advanced survey correction to the magnetic MWD surveys is introduced. This includes in-field referencing to provide a higher resolution magnetic reference to calculate a more accurate well direction, correction to the effect of the steel components in the bottom hole assembly on the magnetic MWD surveys, correction to the errors associated with survey sensors calibration, and correction to any misalignment between the survey tool and the wellbore. Correcting the surveys in real-time while drilling is the key to placing the well accurately and to avoid offset wells in the close proximity. The details of the corrections methodology are discussed. Advanced magnetic survey correction procedures in real-time are outlined and mapped out. Finally, results of improving the magnetic surveys while drilling in placing the wells and minimizing the collision risk of offset wells are presented. This advanced survey technology allows drilling previously un-drillable wells in these offshore fields, and the allowance for increased density of wells in the reservoir gives the operator opportunity to maximize production recovery and extend the life of reservoir. Higher accuracy of wellbore surveys is an increasing requirement in mature fields to safely allow more accurately placed wellbores with the required production rates. This allows for improved well placement along the trajectory facilitating adjustment at control points and landing points to maximize the hydrocarbon production. In addition, it allows controlling the probability of collision with any nearby wells. The enhanced wellbore surveying accuracy is achieved by advanced magnetic survey corrections in real time. This is controlled by a stringent novel process and communication protocol in order to meet the accuracy objectives.

Wellbore position calculations are typically performed by measuring Azimuth and Inclination at 10 - 30 m intervals and using interpolation techniques to determine the borehole position between the survey stations. Input parameters are, Measured Depth (MD), Azimuth and Inclination, where the latter two parameters are measured with the MWD tool in a stationary mode (non-rotating). Output parameters are the geometric coordinates; True Vertical Depth (TVD), North and East. To maximize the exposure of a production well to the reservoir, horizontal wellbores are frequently being drilled. Furthermore, to maximize the production of hydrocarbons from these wells, their relative position within the reservoir is critical. Improving the accuracy of the Inclination measurement and thus reducing the uncertainty of the calculated TVD value will increase the confidence in wellbore position. The NaviGator ™ ∗ geosteering tool or the AutoTrak ™ ∗ rotary steerable system are frequently used to optimize the position of horizontal wellbores within the reservoir. Both these geosteering tools use a Near Bit Inclination sensor (NBI) to help the directional driller perform directional changes smoothly and accurately. Unlike traditional directional sensors the NBI sensor is capable of accurately measuring inclination while being rotated. Consequently NBI measurements can be performed continuously during drilling. The measurements can be used to more accurately calculate the wellbore trajectory. Results in the paper demonstrate that the NBI sensor is more accurately measuring inclination than other directional sensors in a horizontal well. Also, by continuously measuring the inclination during rotation, some error sources are reduced, resulting in improved TVD accuracy. Introduction The most common directional module of a Measurement While Drilling (MWD) tool (Figure 1) consists of three uni-axial accelerometers and a tri-axial magnetometers. The axes are orthogonal with respect to one another and are capable of resolving the measured local fields into three dimensional components. The directional module of an MWD tool is located within the MWD collar itself and is typically found between 15 – 20 m behind the drill-bit, depending on the design of the Bottom Hole Assembly (BHA). Due to the geometry of the BHA and the drilling parameters, the MWD collar can be exposed to a bending effect causing the directional sensor package not to be parallel to the axis of the borehole. The effect of the BHA bend on the accelerometers/inclination measurement can be predicted and more or less compensated for. The unfavorable distance between the bit and the directional sensor has led to the development of near-bit survey sensors to enable rapid responses to inclination changes while drilling. FIGURE 1: Directional MWD. (Available in full paper) FIGURE 2: NaviGator. (Available in full paper) FIGURE 3: AutoTrak. (Available in full paper) Geosteering tools such as Baker Hughes INTEQ's Reservoir Navigation Tool (RNT) NaviGator and Rotary Closed Loop System (RCLS) AutoTrak employ near-bit inclination sensors. These sensors are typically located 1 – 4 m behind the bit and provide accurate near-bit inclination measurements in addition to the data from the directional module located further back in the BHA. The NaviGator (Figure 2) is a combination of a steerable mud motor with the following MWD sensors; azimuthal gamma ray, multiple propagation resistivity and inclination.

A survey program is designed for every well to meet the well objective of penetrating the target reservoir and avoid colliding with other offset wells. The selection of the wellbore survey tools within the survey program is limited in number and accuracy by the surveying technologies available in the industry currently. Quality Control QC measures are regularly in place to ensure the wellbore surveys’ accuracy is validated. However, wellbore surveys often delivered without conducting the full QC measures and sometime are delivered with failing QC measures. This increases the risk of missing the survey program's objective and more critical escalates the risk of the well collision with other wells. Hence, quality control of survey correction is a key to the success of the overall objectives of the well construction. As automated survey-correction software is becoming commonplace among oil and gas operators it is important to consider its use in relation to the overall well risk management strategies. This paper is presenting the latest developed automation workflows to strictly guarantee the quality control and quality assurance of the wellbore survey while placing the well in real-time. Automated Survey QC and correction platforms go a long way to reduce gross error or human related errors with algorithms and machine to machine data transfer protocols. Automated survey QC and correction platforms can be key components in robust risk management solutions for well construction. When implemented appropriately, they allow quick and automated quality check and corrections on wellbore trajectory position which is critical in Anti-Collision and tight target wells. Even though the correction platform is automated it still requires clarity and confidence in the algorithms. This can be achieved with features that are easily accessible, clear, and understandable to inexperienced users. In addition, there should be readily reachable domain experts who can confirm and further interpret the results quickly and clearly, especially when well objectives are in peril of not being met. In this paper, automated survey QC and correction enablers are detailed. How quality control of survey correction are automated, strictly controlled and easily auditable. Additionally, case studies of well construction risk management are presented as well as the successful proof of eliminating human/gross error and non-compliance are demonstrated. The wellbore position is calculated using wellbore surveys. The fact the surveys inherit errors due to tools and environment, the quality of surveys must be ensured and corrected in real-time. The presented technique automates the survey QC and correction process in real-time with a main objective to minimize the risk of colliding with another well or missing the production zone targets while being part of a robust risk management structure.

Various methods, often referred to as in-field referencing (IFR) techniques, are used to enhance the performance of traditional magnetic measurement while drilling (MWD) well-bore surveys. Simulation and field data studies of effects commonly not accounted for, like the fact that the geomagnetic field varies with depth, indicates an unrealistically high level of confidence in the IFR techniques, especially when run in conjunction with multi station corrections (MSC). The SPE wellbore position technical section (WPTS) is currently recommending the use of the standard MWD error model weighting functions, which do not reflect a horizontal east-west singularity associated with combined IFR-MSC surveys. The WPTS is further recommending the use of geographically dependent IFR azimuth uncertainty figures, which average globally to 0.22º (1σ). The WPTS average is supposed to account for all errors that corrupt an IFR survey, not only those affected by the IFR correction itself which, according to WPTS, have an average of only 0.18º (1σ). The WPTS figures do not account for the additional uncertainty generated by geomagnetic depth variation. Simulations show a global uncertainty of 0.38º (1σ) from this error source alone. Geomagnetic depth corrections are possible, but not commonly applied, and are far from error free; residual errors after correction exceeding 30% appear to be common. The study described here indicates an underestimation of the real wellbore position (IFR based) uncertainty of 50% or more, a fact that represents a potential safety hazard to both human life and equipment of which the industry needs to be made aware.

The objective for drilling development wells is to penetrate the target reservoir, maximize recovery, and ensure maximum production. Determining accurate true vertical depth (TVD) in real time is essential to achieving these objectives in thin reservoirs. Ideally, encountered different formation tops while drilling should match the reservoir structure model within a reasonable accuracy; however, during drilling operations, formation tops frequently become shallower or deeper without any logical reasons. This article presents the causes of this uncertainty and provides a solution to the drilling operations problem in real time. The majority of the drilling bottomhole assemblies (BHAs) consist of drive systems containing a positive displacement motor or rotary steerable system (RSS) and measurement-while-drilling (MWD) tool. The MWD tool includes the survey package that measures the inclination and direction of the wellbore, and a similar package is installed within the RSS. The technique, introduced in a massive field in the Middle East, uses the two survey packages within the same BHA to reduce the TVD uncertainty. Additionally, it increases the survey frequency without impacting rig time and mathematically reorients both survey packages to the center of the wellbore. Results obtained by implementing this technique for the first time in the region are encouraging. The main factors affecting calculating TVD while drilling are measured depth, measured inclination, and survey frequency. The presented technique successfully minimized the errors associated with the measured inclination and errors associated with TVD calculation due to insufficient survey frequency. The presented advanced TVD survey management technique allows the well to be placed according to the plan and maximizes reservoir production. The accuracy of the calculated TVD using traditional MWD surveys is compared with that of this presented technique and shows a significant accuracy improvement. Consequently, when implementing this advanced technique, the formation tops are encountered as predicted by the reservoir structure model. Without implementing this technique, the encountered formation tops were found to be shallower in some wells and deeper in others due to the high uncertainty in the calculated TVD using the standard MWD surveys while drilling. This high uncertainty directly affects the correct well placement within the planned layers and negatively impacts the hydrocarbon production rate. The benefits of this advanced TVD survey management technique in real time are significant. This technique provides high-accuracy wellbore positioning and TVD while drilling with well trajectory corrections being made available to accurately penetrate the target. Additionally, the advanced technique reduces the ambiguity in the different formation tops while drilling to enhance the reservoir production recovery, and eliminates the costs associated with drilling longer sections required to penetrate the target zone.

Optimizing lateral well spacing is a challenging problem that has significant economic consequences. The intent is to drill the fewest number of horizontal wells that will effectively maximize reservoir drainage. Successful field development requires spacing horizontal wellbores at an optimum distance that minimizes overlapping drainage areas without stranding reserves. There are many variables that must be considered when determining lateral spacing such as hydraulic fracture geometry and reservoir properties. However, a variable that is often overlooked is wellbore positional uncertainty. It is common to ignore the contribution that inaccurate directional surveying has on lateral wellbore spacing. The purpose of this paper is to demonstrate how inaccuracy in standard directional surveying methods impacts wellbore position and to recommend practices to improve surveying accuracy for greater confidence in lateral spacing. Standard directional surveying by measurement while drilling (MWD) is subject to numerous error sources which can be estimated by the Industry Steering Committee on Wellbore Survey Accuracy (ISCWSA) error model (Grinrod 2016). These error sources are quantified and modeled as three dimensional Ellipsoids of Uncertainty (EOUs) which provide drillers a mechanism for measuring positional uncertainty associated with the wellbore trajectory. The ISCWSA error model can be used to predict the statistical distribution of wellbore positions in order to gain an understanding of how far actual well paths might deviate from the surveyed position. Furthermore, some of the greatest error sources represented in the error model can be significantly reduced using In-Field geomagnetic Referencing (IFR) and Multi-Station Analysis (MSA) in order to improve the accuracy of the MWD surveys (Maus 2015). Performing advanced survey management analysis to raw MWD data and correcting identified systematic errors in real-time improves the accuracy of the well placement as the wellbore is drilled. In order to reliably determine the most optimal lateral well spacing, positional uncertainty should be considered and applied to reservoir simulations and production models. Furthermore, applying IFR and MSA survey corrections to standard MWD surveying can improve horizontal wellbore positional accuracy by 50 to 60 percent (Maus 2015), thus leading to better decisions for optimizing field development and maximizing wellbore value.

Decades of field development in onshore Abu Dhabi fields has resulted in significant operational challenges in planning and drilling new wells. These highly congested fields pose a high risk of well collision due to inherent range errors in the accuracy of well survey measurements obtained during the life of individual fields and reservoirs. The study discusses a methodology for improving and normalizing the accuracy of legacy wellbore survey data to aid successful planning of recent multilateral drain hole strategy and how real time data corrections can aid in accurate wellbore placement. Multilateral wells are risked by higher collision issues for having target areas in separate azimuths from single surface location (SL). Proposed wells were subjected to lower Separation Factor (SF) due to high density of wells. In the study area, survey data of existing vertical and horizontal wells in upper and lower reservoirs in the proposed well path were studies and plotted in well sections and maps in Geological model. Well anti-collision runs of proposed lateral holes with offset wells were done in drilling planning softwares. A notional model study carried out with one of the proposed triple lateral wells in ADNOC Onshore with nearest offset wells with MSA and SAG correction resulted in collision risks being reduced by 52% and hence qualifying with the minimum SF required for safe drilling. Recent reservoir development strategy in an Abu Dhabi Onshore field is to drill trilateral wells targeting multilayered reservoirs to maximize production while optimizing sweeping efficiency. Well survey quality management with In-Field Referencing (IFR), Multi Station Analysis (MSA) and SAG Correction are the primary steps to be applied to MWD survey measurements to reduce the well collision risk. The normal well anti-collision study with nearest offset wells is mandatory as per standard drilling practices and with densely populated wells in one of the giant Abu Dhabi Onshore fields, it is becoming challenging to meet the minimum separation factor (SF>2) required by the company policy. A survey correction in all legacy wells followed by real time survey correction in triple lateral wells will add a significant value concerning collision issue in the proposed triple lateral campaign. With growing number of wells in highly congested fields, Pad drilling coupled with advance survey management technique will result in high value addition for future drilling campaigns without having collision risks and hence pave the way for future infill development strategy without subsurface space constraint.

Cano Limon is a prolific oilfield located in Colombia's s Arauca Department (Llanos Basin), with the bulk of the oil produced from Eocene Mirador and the Upper Cretaceous sands. Long tangent profiles in this application often necessitate changes to the casing design. As a result, operators employ borehole enlargement while drilling on rotary steerable systems (RSS). However, challenges like excessive vibration and bottomhole assembly (BHA) instability arise when bit/reamer cutting structures encounter formations with varying mechanical properties. High magnitude/frequency vibration often leads to cutter block, measurement while drilling (MWD), RSS, or drill bit failure. Fluctuations in torque can lead to overtorqued connections or even twist-offs, significantly increasing well construction costs. Various strategies are commonly executed to mitigate the risk of premature BHA trips due to shocks and vibrations (S&V). These include meticulous BHA design, bit-reamer matching, development of parameter roadmaps, and real-time optimization. Torsional vibration mitigation (TVM) tools integrated into the BHA offer a cost-effective solution to address S&V risks. Engineered to withstand the impact of vibration-induced energy loss, such technologies streamline operations without necessitating alterations to drilling plans or dedicated on-site supervision. The TVM tool made its debut in Cosecha's 8½ in. × 9½ in. underreaming operation, marking a successful initial deployment. Following its validation in vibration dampening and isolation, this technology was subsequently utilized in Chipiron's 8½ in. × 9½ in. BHA. Featuring a patented pressure-compensated telescoping mechanism, the TVM effectively absorbs torsional oscillations and vibrations stemming from stick-slip occurrences, excessive engagement of the bit or reamer, and inconsistent weight transfer. Its dampening mechanism leverages a telescoping action to mitigate abrupt variations in weight or torque, while vibration energy is dispersed across a spring stack calibrated to meet application-specific demands. Consequently, the underreaming RSS restores both torsional and axial stability. An offset well experienced 50% on-bottom time accompanied by high or severe levels of stick-slip. Conversely, a nearby well featuring a strategically positioned TVM within the underreaming RSS BHA observed a significant reduction in torsional vibration to just 7%. Moreover, the subject well achieved a 40% longer interval, alongside notable improvements in rate of penetration (ROP). Notably, no instances of overtightened connections were reported at the surface in the subject well, contributing to a reduction in cycle time. Vibration intensity correlates with BHA failures. A comprehensive strategy is crucial for addressing vibration-related issues. The TVM tool demonstrates cost-effective and reliable vibration reduction. By minimizing the BHA's exposure to detrimental S&V, TVM enhances the mean time between failures, improves drilling efficiency, and lowers construction costs. Further research is warranted to optimize TVM placement and configuration for specific applications.

Nikaitchuq is the largest single-stakeholder development on the North Slope of Alaska. It is a multiyear, very shallow extended-reach drilling (ERD) project with more than 50 wells drilled from two sites, one of which is an artificial gravel island, targeting Schrader Bluff sands. A number of key drilling advances were implemented to reach the milestone of one million feet drilled as the scope of the development plan expanded to include new producer wells targeting a shallower sand, new in-fill multilateral producer branches, and a new extension plan targeting pay that is much more distant than the original development plan envisioned. The minimum slot distance of 8 ft and the increasing density of wells drilled drove the development of a systematic anticollision management plan. Significant economic value was conserved by explicitly forming shut-in/turn-on criteria for offset wells, managing surface conductor drift, controlling drilling parameters exiting the surface conductor through the kickoff, implementing a new surveying technique, and identifying and accounting for directional "deadzones." Abrasion wear occurs in the intermediate hole section bottomhole assembly (BHA) caused by high-angle well path geometry, often surpassing 85° inclination in tangent, combined with the presence of frequent hard stringers. The impact of wear has increased as the extended reach drilling ratio and directional difficulty index have increased year-on-year from 6.34 to 6.69, respectively. Well path geometry has progressed to limit the measured depth drilled through intervals where hard stringers are expected and to account for reduced directional performance at the later part of the hole section. The reduction of downhole tool repair costs and the elimination of downhole tool failures, ultimately leading to single-run, shoe-to-shoe drilling of a section 13,500-ft measured depth (MD) long—a record for Alaska—are the results of the focus on improving BHA design to limit wear. Multiple reentry laterals have been geonavigated in close proximity with the parent wellbore among offset producer grassroots wells. A point-the-bit rotary steerable system has been introduced to drill ahead and deviate from the bottom of the milling rathole, below the whipstock and window, eliminating a motor run and saving substantial rig time on each lateral. A sourceless density logging-while-drilling (LWD) tool was introduced to manage drilling risk through zones of depletion. These technical advancements demonstrate consistent improvement of the drilling learning curve over the course of 5 years drilling at Nikaitchuq. This will be the first literature that details the long-term drilling advances achieved in the project and a valuable technical reference for very shallow ERD wells where abrasion wear is a concern.

Modern drilling rig collects vast amount of valuable data through multiple systems in place. Small transducers such as pressure sensor, hook-load sensor, draw work encoder can significantly impact drilling performance when Artificial Intelligence (AI) and Machine Learning (ML) are applied to identify patterns. However, despite advancements in drilling technology, the traditional MWD survey has remained unchanged. As a result, well placement has not seen a significant improvement in True Vertical Depth (TVD) accuracy using MWD survey data alone. The paper aims to demonstrate the positive impact of compensating for the Stockhausen effect on TVD calculation when high-fidelity trajectory points are incorporated into the definitive survey listing. A total of 1,363 wells were processed with an algorithm capable of combining steering data (slide/rotating mode), rotary tendency, and continuous inclination. The algorithm calculated a new wellbore trajectory which included additional high-fidelity surveys. The new northing, easting, and true vertical depth (TVD) along the wellbore were estimated using minimum curvature method. After recalculating the new wellbore position, the difference between the TVD compensated for the Stockhausen effect and the TVD calculated using BHA Sag was determined at two critical points of interest for each well: the landing point (LP) and the total depth (TD). The TVD error quantification for each point of interest, namely landing depth and total depth, provided a valuable insight into the impact that the Stockhausen effect has on well placement in the vertical plane. At landing depth, a TVD variation between -16 ft to 10 ft was observed. Of this, 71% of the wells showed a TVD change less than 5 ft, while 24% had changes between 5 ft and 10 ft, and 5% exhibited a change of 10 ft or more. At total depth, a TVD variation ranged between -38 ft to 42 ft. Within this range, 46% of the wells had less 5 ft of TVD change, 27% showed a change between 5 ft and 10 ft, and 28% showed differences greater than 10 ft. There are still errors related to vertical position of the well that many end-users fail to account for when conducting analyses such as Collision Avoidance or evaluating tight pay zone. One such overlooked issue is the Stockhausen effect. While new MWD tools with advanced firmware capable of processing and combining multiple data offer the option to transmit continuous surveys while drilling, this technology faces challenges. The limited availability of these new tools and services delays the widespread adoption. Therefore, incorporating new algorithms along existing data appears to be a viable solution for addressing the "Stockhausen" effect.

Typical well surveys are made once per stand, producing a 95-ft survey database; however, numerous things can take place in that 95 ft of pipe. Small changes in continuous inclination and azimuth lay hidden between traditional static survey stations. Processing these real-time measurements, in combination with traditional surveys, generates a definitive 10-ft survey list, resulting in an enhanced geometrical representation of the wellbore position. This enhanced wellbore positioning becomes increasingly significant in areas with high-anticollision risk. This type of survey processing was implemented in extended-reach drilling (ERD) projects in the Middle East. A comparison between the 95-ft surveys and the processed high-resolution surveys showed changes to 10 ft in the true vertical depth (TVD) measurements. Such shift in the TVD is important because it can result in having to revise planned trajectories to further minimize anticollision risk arising from the nearby TVD proximity with offset wells. This paper will present data to quantify the enhancement in TVD positioning using advanced survey processing in ERD projects in the Middle East, and its impact on minimizing anticollision risk.

This paper presents a case study of the detailed planning and BHA modeling used to improve performance in drilling deviated 24 inch hole sections and its implication to the on-going Ringhorne extended-reach-drilling (ERD) program. The paper describes the planning; modeling and results of the 24 inch drilling performance achieved in the longest extended reach well drilled to date in the Ringhorne Development, Offshore Norway. Ringhorne wells usually kick-off below the 26 inch conductor in 17-1/2 inch hole building angle from vertical to 65 degrees where 13-3/8 inch surface casing is typically set. This is not the case for the development with extended well targets where it came necessary to upsize the casing program with 18-5/8 inch surface casing. This requires a 24 inch deviated hole to be drilled from approximately 300 meters measured depth (mMD) to 70 degrees by 1000 mMD with casing point at approximately 1600 mMD to enable drilling to the reservoir targets at 1700 – 2000 meters true vertical depth (mTVD). The first 24 inch section was drilled using a 17-1/2" polycrystalline diamond (PDC) bit, rotary steerable system (RSS) and PDC hole-opener. Severe vibration problems were experienced while drilling through the Utsira sands near the base of the section causing a rotary steerable tool failure. This led to loss of angle and slightly earlier casing point than planned. The next 24 inch section was drilled using a two-run strategy including a 17-1/2 inch RSS to total depth (TD) before picking up a 24 inch hole-opener in a separate run. The first hole-opener run twisted off above the bottomhole-assembly (BHA) while drilling the massive Utsira sandstone and three subsequent hole opening runs were pulled due to poor performance resulting in a tapered casing string to be set. Because of the poor BHA performance and the associated drilling problems, the operator and the service company conducted an extensive analysis of offset drilling performance followed by a thorough modeling study to ensure success in drilling the long reach 25/8 C-12 (C-12) well from the platform. Due to the complexity of the well, no deviation from the well path could be tolerated and the casing shoe had to reach the planned depth. Time and depth based data, formation information and vibration measurements from the offset wells were evaluated using analytical software. These results were used to analyze various BHA's for stability. This investigation led to the development of a stable BHA configuration and selection of optimum bit properties, recommendation for parameter combinations and response plans for the formations encountered. A plan was developed that focused on drilling practices and parameter adjustments according to the formation. The result was a significant reduction of vibration that enabled the rig crew to successfully drill the 24 inch section following the well path and run the 18-5/8 inch casing to planned TD without incident.