Measurement While Drilling Tool Research Articles

Calibration of accelerometer and magnetometer sensors of MWD systems in directional drilling application

Measurement while drilling (MWD) tools include accelerometers, magnetometers and temperature sensors. The accuracy of these sensors are highly important in measuring inclination and Azimuth angle parameters in a directional well. These factors can increase costs when drilling a directional well. During the past years, many efforts have been made to increase the accuracy of these tools. Accuracy of accelerometer and magnetometer sensors are influenced by scale, bias and non-orthogonal errors. Considering that MWD systems work in a wide range of temperatures (for example 0 °C–150 °C), the temperature parameter should also be added to the factors affecting the errors. Here, after making a sample of MWD tool, a method to calibrate the tool using mathematical model based on total field calibration algorithm, least square method and the transfer matrix is presented. Calibrated parameters at ambient temperature are calculated with acceptable speed. Then, a method for calculating temperature coefficients in the desired range is provided. Compared to the case where temperature coefficients are not considered, the obtained results show a significantly increased accuracy of Inclination and Azimuth parameters through the use of these coefficients.

High Temperature Inertial Navigation Sensors, Electronics and Packaging for reliable 300°C Operation

Conventional oil and gas drilling measurement while drilling (MWD) systems are typically designed to operate at temperatures <200°C. To increase the efficiency of drilling unconventional geothermal wells, downhole MWD tools are needed that can operate in the unique thermal challenges encountered in enhanced geothermal systems (EGS). GE demonstrated a 300°C downhole navigation system. The system utilizes GE’s internally developed state-of-the-art MEMS multiple ring Gyroscope (MRG), and a high temperature gyroscope control and readout application specific integrated circuit (ASIC). The MRG, ASIC and associated high temperature, high reliability packaging were integrated to demonstrate the performance and functionality of the gyroscope across the temperature range from room temperature to 300°C. Specialized long-term capable high temperature test platforms were developed to enable the characterization and testing of the gyroscope system and utilized to validate application-relevant lifetime capability.

Deep Convolutional Network Improves Completion Design

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201545, “Completion Design Improvement With a Deep Convolutional Network,” by Liwei Li, Nasser Nasrabadi, and Timothy Carr, SPE, West Virginia University. The paper has not been peer reviewed. Maximizing stimulated natural and hydraulic-fracture networks is a primary concern for economic production from a horizontal shale gas well. Geomechanical facies and preexisting fractures in each stage are identified based on similarities in formation characteristics. This often requires analyzing large volumes of drilling, logging-while-drilling (LWD), and measurement-while-drilling (MWD) data. In the complete paper, the authors develop a methodology that calculates mechanical specific energy (MSE) using real-time drillstring acceleration signals. Introduction The Marcellus Shale Energy and Environmental Laboratory (MSEEL) aimed to improve stimulation efficiency by collecting, integrating, and analyzing real-time LWD and MWD data. In addition, engineered completions were combined with fiber-optic distributed-temperature-sensor and distributed-acoustic-sensor data. To reduce issues with data quality measured using surface sensors, advanced MWD and LWD tools are proposed to collect data close to the bit. In the analysis of nonstationary data such as drillstring vibration measurements, the conventional Fourier transform is limited to frequency spectrum without time information. To address this problem, new signal-processing methods have been developed to provide frequency features localized in time. Deep convolutional neural networks (CNNs) are a promising approach for image classification. Feature extractions can be performed by adding convolution and pooling filters, reducing spatial resolutions, and increasing depth to build a deep learning network. The authors propose a decision chart that labels rock laterals using calculated MSE values and interpreted natural fracture intensities to improve stage-by-stage perforation efficiency. The borehole-imaging tool is used to achieve a cost-effective solution. This tool collects both high-resolution acoustic amplitudes and triaxial accelerations.

Auto-Calibration and Fault Detection and Isolation of Skewed Redundant Accelerometers in Measurement While Drilling Systems.

The present study designed skewed redundant accelerometers for a Measurement While Drilling (MWD) tool and executed auto-calibration, fault diagnosis and isolation of accelerometers in this tool. The optimal structure includes four accelerometers was selected and designed precisely in accordance with the physical shape of the existing MWD tool. A new four-accelerometer structure was designed, implemented and installed on the current system, replacing the conventional orthogonal structure. Auto-calibration operation of skewed redundant accelerometers and all combinations of three accelerometers have been done. Consequently, biases, scale factors, and misalignment factors of accelerometers have been successfully estimated. By defecting the sensors in the new optimal skewed redundant structure, the fault was detected using the proposed FDI method and the faulty sensor was diagnosed and isolated. The results indicate that the system can continue to operate with at least three correct sensors.

Bending Rules With High-Build-Rate Rotary-Steerable Systems

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 177898, “Bending Rules With High-Build-Rate RSS,” by Imran Tipu, Eman Alawadhi, R. Kumar, Batyr Amanov, Mohamed A. El Gebaly, A.M. Al-Hammadi, A.M. Bin Shamlan, and Ali M. Danche, Abu Dhabi Company for Onshore Petroleum Operations, and Sukesh Ganda, Rajan Dua, and Nour Hariri, Schlumberger, prepared for the 2015 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 9–12 November. The paper has not been peer reviewed. This paper explores the applications, benefits, and value of a high-build-rate rotary-steerable system (HRSS) capable of delivering dogleg severity (DLS) greater than 18°/100 ft. The application of this technology has led to an estimated savings of 40 days. Other benefits include better hole cleaning and smoother wellbores, leading to less wellbore tortuosity and improved post-drilling trips with drilling, logging, and casing assemblies. Introduction Traditionally, steerable motors were used to drill an 8½-in. long-radius curve section requiring DLS of 6–7°/100 ft to land the well in the reservoir. Drilling long-radius curves required drilling through problematic and unstable formations and would require approximately 1,000– 1,200 ft of vertical-section length to reach the target entry (TE). In another drilling scenario, sidetracking from a cement plug, the first run was always with a steerable motor with a measurement-while-drilling (MWD) tool to the sidetrack and then 100–150 ft followed by a second run of a rotary-steerable system (RSS) and logging-while-drilling (LWD) tools. When sidetracking from a whipstock, though, the first run was with a motor and MWD tool, a gyro shot to the sidetrack, and then 150 ft, followed by a second run of the RSS LWD bottomhole assembly (BHA). The long-radius wells were kicked off in the Shilaif formation, and the well profiles require DLS of 6–7°/100 ft through the Shilaif and Maudud formations, 4.5°/100 ft through approximately 700-ft measured depth of Nahr Umr, and finally 6–7°/100 ft through Bab to reach TE.

Magnetic Referencing and Real-Time Survey Processing Enable Tighter Spacing of Wells

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.

Design and Algorithm Verification of a Gyroscope-Based Inertial Navigation System for Small-Diameter Spaces in Multilateral Horizontal Drilling Applications

In the recent years horizontal drilling (HD) has become increasingly important in oil and gas exploration because it can increase the production per well and can effectively rework old and marginal vertical wells. The key element of successful HD is accurate navigation of the drill bit with advanced measurement-while-drilling (MWD) tools. The size of the MWD tools is not significantly restricted in vertical wells because there is enough space for their installation in traditional well drilling, but the diameter of devices for HD must be restricted to less than 30 mm for some applications, such as lateral drilling from existing horizontal wells. Therefore, it is essential to design miniature devices for lateral HD applications. Additionally, magnetometers in traditional MWD devices are easily susceptible to complex downhole interferences, and gyroscopes have been previously suggested as the best avenue to replace magnetometers for azimuth measurements. The aim of this paper is to propose a miniature gyroscope-based MWD system which is referred to as miniature gyroscope-based while drilling (MGWD) system. A prototype of such MGWD system is proposed. The device consists of a two-axis gyroscope and a three-axis accelerometer. Miniaturization design approaches for MGWD are proposed. In addition, MGWD data collection software is designed to provide real-time data display and navigation algorithm verification. A fourth-order autoregressive (AR) model is introduced for stochastic noise modeling of the gyroscope and the accelerometer data. Zero velocity and position are injected into a Kalman filter as a system reference to update system states, which can effectively improve the state observability of the MGWD system and decrease estimation errors. Nevertheless, the azimuth of the proposed MGWD system is not observable in the Kalman filter, and reliable azimuth estimation remains a problem.

Designing and Testing of New Rotary-Steerable System for Use Onshore

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 173093, “Designing and Testing a New Rotary-Steerable System (RSS) for the Onshore Drilling Market,” by Andrew Gorrara, SPE, Shona Grant, Tore Kvalvik, SPE, and Stig Bakke, 2TD Drilling, and Peter Clark, SPE, Chevron, prepared for the 2015 SPE/IADC Drilling Conference and Exhibition, London, 17–19 March. The paper has not been peer reviewed. While rotary-steerable systems (RSSs) dominate the offshore directional-drilling markets, the land-based markets are still dominated by conventional directional-drilling tools. This paper presents a new RSS that is being designed and tested specifically for the onshore markets. The new tool is a short RSS that is designed to deliver a buildup rate of 15°/100 ft. It achieves this by the movement of two eccentric shafts relative to one another within the tool. Introduction For directional drilling to be successful, it is important that the drillers have information on the orientation of the tool while they are drilling so they can best align the wellbore orientation to the reservoir target. Commonly, this is achieved with a measurement-while-drilling (MWD) tool that is typically 50 ft or more behind the drill bit. In some cases, these measurements are supplemented with some form of near-bit inclination reading. A further improvement would be to have both inclination and azimuth measured close to the bit and integrated into the drilling tool’s directional response, thereby enabling precise well placement without the need to project and correct continually from the MWD tool that lags considerably behind the drilling tool. This is the method adopted by the RSS described in this paper. In many cases, a downhole positive-displacement motor will be used with the RSS to increase rate of penetration (ROP) and reduce casing wear by minimizing string rotation. The RSS described in this paper was designed to be driven directly by the topdrive or with a mud motor. Three prototypes of the new RSS have been designed and tested so far. The first prototype (Prototype A) successfully demonstrated dogleg-severity capability of 15°/100 ft. The second prototype (Prototype B) was designed to evaluate the efficiency of the selected motor-gear design in moving the eccentric shafts when applying significant side loads. The third prototype (Prototype C) was a complete rotary-steerable tool that verified all aspects of the design, culminating in the drilling of directional holes in concrete blocks. This paper describes the development of Prototype C, covering design, manufacture, and the drill tests that verified the 15°/100 ft dogleg performance through concrete-block drilling. The paper also covers the subsequent design improvements made before manufacture of the field-test prototypes (Prototype D) and the planned environmental and endurance testing of Prototype D before field testing.

Efficient Drilling of Ultra-HP/HT Wells in the Gulf of Thailand

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 25392, “Efficient Drilling of Ultra-HP/HT Wells in the Gulf of Thailand,” by Joy Araujo, Schlumberger; Keittipong Kaotun, PTTEP; and Panupun Dumrongthai and A. Adrian, Schlumberger, prepared for the 2014 Offshore Technology Conference, Houston, 5–8 May. The paper has not been peer reviewed. A new measurement-while-drilling (MWD) tool has been designed that can operate reliably at 200°C and 207 MPa, providing real-time direction and inclination surveys, azimuthal gamma ray, annular and internal pressure while drilling, and shock and vibration measurements. An operator in the Gulf of Thailand used this new MWD technology to drill wells in ultrahigh-pressure/high-temperature (HP/HT) reservoirs without the need to stop operation because of temperature limitations. Savings of ½ day per well have been achieved. Introduction Offshore drilling in the Gulf of Thailand increasingly challenges logging operations, with temperatures greater than 200°C. Hundreds of wells need to be drilled per year in this environment to fulfill long-term gas contracts. High efficiency is required in such a high-volume operation. Existing commercial MWD and logging-while-drilling (LWD) technologies are only capable of operating up to 175°C, with an inherent decrease in reliability at higher temperatures. In the planned ultra-HP/HT projects, the bottomhole assembly (BHA), which includes an MWD tool for directional and inclination measurements in real time, will be pulled out of the hole once the circulating temperature reaches 175°C. Then, a new BHA, without measurement tools, will be used to continue drilling to total depth. This “blind” drilling section could be several hundred meters long, introducing risks associated with well control and well collision. The main limiting factors in having MWD/LWD tools operating in these ultra-HP/HT environments are the downhole electronic components. Industry research studies show that plastic-encapsulated components have a life expectancy of approximately 1,000 hours at 150°C; this drops to less than 100 hours at 175°C. Ceramic-encapsulated components last longer at 175°C, but they are bigger and heavier than their plastic counterparts. Because space is restricted in these tools, the best compromise yields a mix of both ceramic- and plastic-encapsulated components. To find a solution to this industrywide problem, significant effort was made over the last decade to develop custom electronics that can withstand high downhole temperatures. The newly developed MWD tool equipped with these novel electronics components was deployed in ultra-HP/HT wells. In these wells, the real-time measurements were necessary to drill the sections with operating temperatures greater than 175°C. It allowed minimization of drilling risks, enabled proper well placement, and improved drilling efficiency by eliminating one run.

Unique System for Underbalanced Drilling Using Air in the Marcellus Shale

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 171024, ’Unique System for Underbalanced Drilling by Use of Air in the Marcellus Shale,’ by Chris Maranuk, SPE, Ali Rodriguez, SPE, Joe Trapasso, SPE, and Joshua Watson, SPE, Weatherford, prepared for the 2014 SPE Eastern Regional Meeting, Charleston, West Virginia, USA, 21-23 October. The paper has not been peer reviewed. Air drilling has become popular in the Marcellus and Utica shale reservoirs because of its higher rate of penetration (ROP) and less resulting formation damage. A unique drilling system incorporating the use of downhole mud motors, electromagnetic (EM) measurement-while-drilling (MWD), and air hammers has been specifically designed and ruggedized to address downhole shock and vibration encountered in air drilling. Use of this system has resulted in significant reduction of nonproductive time (NPT). Introduction While seeking alternatives to increase ROP and reduce drilling costs, a few operators in the northeastern US implemented batch-drilling practices from pad locations. This provides an attractive alternative by allowing multiple wells to share the same surface location, effectively reducing footprint and environmental impact. Common well design uses streamlined well construction, where low-cost rigs can drill the tophole sections and larger, more-expensive rigs drill the curve and lateral sections. The typical well plan incorporates surface, intermediate, curve, and lateral sections that, combined, may exceed 18,000 ft. The lateral sections are the most critical and range between 2,000 and 8,000 ft, depending on formation and well geometry. The goal for close-proximity-well design is to minimize well-to-well interference and maximize reservoir exposure. Air drilling provides a significant decrease in hydrostatic pressure over common mud types, resulting in an increased ROP. Additionally, significantly better hole cleaning can be achieved because of the high air velocities used to drill the well. Finally, mud- and cuttings-handling costs can be reduced because there are no chemicals to absorb and no cuttings-cleaning requirements on virgin formations. Early tests of this application proved it to be a viable option for the Marcellus and the Utica fields. Initially, hammer bits were used for air drilling, but significant challenges involving directional control emerged as well-plan trajectories became more advanced. The development of ruggedized mud motors and MWD tools capable of handling these challenges, and the use of specialized fluid-control systems, eventually allowed more-conventional bottomhole assemblies (BHAs) to be successful when used for air drilling.

Multidisciplinary Collaborative Concept Aids Challenging Deepwater Operations in Brazil

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 151186, ’Upgrading the Real-Time Drilling-Optimization Culture in Brazil's Challenging Deepwater Operations: The Utilization of a Remote and Rigsite Multidisciplinary Collaborative Concept,’ by Augusto Borella Hougaz, Danilo S. Gozzi, Isao Fujishima, and Klaus L. Vello, Petrobras, and Sandro Alves, Ian Thomson, Raul Krasuk, SPE, and Frank Buzzerio, Baker Hughes, prepared for the 2012 SPE/IADC Drilling Conference and Exhibition, San Diego, California, 6-8 March. The paper has not been peer reviewed. In Brazil, deepwater well-construction activity has increased significantly since the first major presalt discovery in the Santos basin in 2006. The creation of a multidisciplinary drilling-optimization group, integrated with the operator’s drilling team in 2008, and the introduction of a highly specialized downhole-drilling-dynamics measurement-while-drilling (MWD) tool changed the drilling-optimization concept in Brazil. This new optimization concept pioneered the remote (off-the-rig) downhole drilling-parameters surveillance in deepwater operations. Introduction A novel real-time optimization drilling service was implemented in 2008 with the major deepwater operator in Brazil in the Santos basin. Throughout the implementation and execution of the real-time optimization service, the importance of not only knowing where (wellbore placement) and what (formation evaluation) you are drilling but also how you are drilling, which is mainly driven by the integration between operator and service company, became apparent. After 3 years, it was clearly observed that the higher the integration between service company and operator was in a proactive and collaborative environment, the higher the drilling performance was. Today, in the deepwater Santos basin presalt environment, the real-time optimization drilling service is already part of the drilling program in almost every well, from the top hole section to the reservoir section. Real-Time Drilling-Optimization Team In 2008, to answer the “how” questions in the Santos basin, a new culture of real-time optimization arose with the concept of a multidisciplinary optimization team from the service company acting in collaboration with the major operator in Brazil in an integrated manner to achieve superior performance. To accomplish effective remote and rigsite real-time drilling optimization, it is important to use a highly specialized downhole drilling-dynamics MWD tool that records and transmits real-time dynamics data (e.g., stick/slip, lateral vibration, whirl, and axial vibration) and downhole drilling parameters (e.g., weight on bit, torque, revolutions per minute, and bending moment), which allows for a better judgment of the down-hole conditions while drilling and better support for adjusting the surface drilling parameters to optimize operations, in a continuous feedback cycle (Fig. 1).

Quantifying Drillstring-Integrity-Failure Risk: Real-Time Vibration Measurements

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 147747, ’Quantification of Drillstring-Integrity-Failure Risk Using Real- Time Vibration Measurements,’ by Yezid Arevalo, SPE, and Ashley Fernandes, SPE, Schlumberger, prepared for the 2011 SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, 20-22 September. The paper has not been peer reviewed. Traditional vibration measurements target improving downhole-tool reliability. This effort targeted the effects of vibration on the complete drillstring. Failures associated with drillstring vibration continue despite current measurement sophistication. These failures represent a very significant amount of lost time and are targeted with a proposed solution that is based on real-time measurements of drillstring vibration to estimate an ongoing drillstring-integrity risk for use as a guideline to improve decisions while drilling the well. Introduction The understanding of vibrations has improved, recognizing the random nature of downhole vibrations because they often are highly dependent on factors intrinsic to formation and borehole characteristics, which cannot be modeled practically or measured with sufficient detail in real time. These recognized limitations continue to highlight the importance of real-time measurements to manage drilling parameters in an effort to optimize drilling results and manage drilling-integrity risks. When the risk of drillstring-integrity failure is recognized in a drilling project, it is common to implement advanced vibration-measurement devices to assist the understanding of the drilling-dynamics behavior in real time. Often, the interpretation of these data is complex and requires expert real-time support and follow-up to obtain the desired results of mitigating vibration-related integrity failures. Without appropriate resources, critical data can be ignored easily and not be acted upon, leading to failures and lost time. Downhole-Vibration Measurement The measurement device used to quantify vibration severity was a multiaxis vibration chassis (MVC)—a four-axis shock-measurement tool. The first axis refers to the strain gauges and associated electronics used for torsional measurements. The remaining three axes refer to a system comprising the vibration-acquisition board and three offboard accelerometers. The complete system is mounted on a special chassis in the measurement-while-drilling (MWD) tool. The three accelerometers are mounted in a mutually orthogonal arrangement along the centerline of the MWD tool. The vib-x sensor measures axial shocks, while the vib-y and vib-z sensors measure lateral shocks in orthogonal directions. The mounting arrangement is designed to ensure that the chassis experiences the same vibrations as the MWD tool. Also, an independent accelerometer is mounted on the MWD tool and normally is used to establish a risk level based on the count of shocks that peak above 50 g. A high risk of tool failure is considered when a level above 10 counts of shocks higher than 50 g is measured. This sensor also registers the highest shock peak within the data-point transmission interval. This information enables identifying situations in which single events of high acceleration can increase the risk of drillstring or downhole-tool failure, because these measurements may not be recorded by a root-mean-square (RMS) measurement that provides an average measurement.

Wellbore Surveying While Drilling Based on Kalman Filtering

Problem statement: Oil and gas are global fuels obtained primarily from drilling wells in underground terrestrial reservoirs. Vertical drilling is preferred because of its simplicity and therefore low cost, but subsurface targets can often be procured only by directing the wellbore along predefined non-vertical trajectories. For instance, directional drilling must be employed to reach locations inaccessible to the drilling rig, to side track an existing well (multilateral drilling), or to drill multiple wells from the same offshore platform (horizontal drilling). Approach: A complete knowledge of the wellbore direction and orientation during the drilling process is essential to guarantee proper directional drilling procedure. Results: Thus, besides the conventional drilling assembly, directional drilling operations require sensors to provide azimuth, inclination and toolface angles of the drill. These sensors are part of the Measurement-While-Drilling (MWD) tool, which in current technology is installed several feet behind the drill bit. In such systems, values for inclination and toolface angles are determined from accelerometer measurements at predetermined stationary surveying stations; these values are then incorporated with magnetometer measurements to deliver the azimuth angle. Values for inclination and azimuth angles at the current surveying station are combined with those from the previous station to compute the position of the probe. However, there is no accurate information about the wellbore trajectory between survey stations. Additionally, the magnetic field of the magnetometers has deleterious effect on the overall accuracy of surveying measurements. Conclusion: A method to provide continuous information about the wellbore trajectory has been developed in this study. The module developed integrates a Rotary Steerable System (RSS) and MWD tool into one drilling probe utilizing Inertial Navigation System (INS) technology. This is achieved by designing a reliable real-time low cost MWD surveying system based on MEMS inertial sensors miniaturized inside the RSS housing installed directly behind the drill bit. A continuous borehole surveying module based on MEMS inertial sensors integrated with other drilling measurements was developed using Kalman filtering.

Total-System Approach Through Wired-Drillpipe Technology

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 112742, "A Step Change in Total-System Approach Through Wired-Drillpipe Technology," by Vebjorn Nygaard, SPE, Mohammad Jahangir, SPE, Trond Gravem, SPE, and Eugene Nathan, SPE, Inteq; John Evans, SPE, Hughes Christensen; Mike Reeves, SPE, IntelliServ; and Henrik Wolter, SPE, and Sigve Hovda, SPE, StatoilHydro, prepared for the 2008 IADC/SPE Drilling Conference, Orlando, Florida, 4–6 March. The paper has not been peer reviewed. Increased oil and gas recovery requires drilling complex extended-reach wells with optimized reservoir exposure for improved production and minimum overall production costs. Introduction of wired-drillpipe technology has facilitated a step change in two-way data communication, resulting in high-speed data transmission providing greater volume, resolution, and quality of formation-evaluation data and drilling-dynamics data. Direct control of rotary-steerable tools has been enhanced to allow instantaneous programming changes and better use of dynamics data to enhance the decision-making process to address drilling-abnormality challenges, hole quality, gross rate of penetration, and bottomhole-assembly (BHA) reliability. The high-band-width technology was used while drilling two laterals in the Troll field in the Norwegian North Sea in 2007. Introduction The broadband network used in this telemetry drillstring enables an ultra-high-speed alternative to mud-pulse- and electromagnetic-telemetry methods. The network uses individually modified drilling tubulars to provide bidirectional, real-time, drillstring telemetry at speeds up to 57,000 bit/sec. This bandwidth, compared with existing technology, makes it possible to obtain large volumes of data from downhole tools (and other measurement nodes along the drillstring) instantaneously, expanding the quantity and quality of information available while drilling. The network uses a high-strength coaxial cable and low-loss inductive coils embedded in double-shouldered connections in each tubular joint to convey information. Currently available telemetry tubulars include various sizes of Range-2 and -3 drillpipe, heavyweight drillpipe, drill collars, and many BHA components. The network's bidirectional architecture allows simultaneous high-speed transmission of downhole data to the surface and commands from the surface to downhole devices, such as rotary-steerable systems (RSSs). Inserting a physical and electrical interface to the telemetry drillstring (an interface subassembly) makes existing measurement-while-drilling (MWD), logging-while-drilling (LWD) RSS tools fully compatible with the network, allowing high-bandwidth communication between all connected tools and a surface acquisition/control system. During 2006, the operator selected the West Venture rig, a semisubmersible drilling unit operating in the Troll field, for their first use of this drillstring-telemetry technology. The selected project offered significant drilling challenges and presented an opportunity to use multiple MWD, LWD, and RSS tools in combination with the network. Drilling activity with these technologies began in 2007.

3-D Finite-Difference Modeling for MWD Logging Development

This paper presents a 3-D finite-difference method (FDM) for analysis of electromagnetic measurement- while-drilling (MWD) tool response. The FDM is formulated with cylindrical coordinates, enabling accurate simulation of a cylindrical tool geometry. The algorithm allows the simulation of inhomogeneous media with arbitrary conductivity and magnetic permeability distributions. Material averaging is applied to both conductivity and magnetic permeability based on a mixture of harmonic and arithmetic averages. With the use of an irregular finite-difference grid, a complex MWD antenna with cavities and slots is accurately modeled. The system of linear equations is solved with the Lanczos decomposition method or the quasi-minimum-residual method, depending on the volume of output data. Our results show the 3-D FDM can accurately predict the tool response. It is shown that ferrite inserted in antenna slots increases the effective radiating length of the slots. The ferrite also helps reduce the eddy currents in the metal. However, it is not necessary to use ferrite with a relative magnetic permeability greater than 200 for the particular antenna geometry considered. For typical MWD tool spacings of 1 m or so, the field by a slotted antenna can be well approximated by that of a dipole antenna.

Improving Wellbore Position Accuracy of Horizontal Wells by Using A Continuous Inclination Measurement From a Near Bit Inclination MWD Sensor

Abstract 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.

Petrophysics of magnetic dipole fields in an anisotropic earth

Measurement-while-drilling (MWD) resistivity log data are often acquired in highly deviated or horizontal holes. The loop sensors are located on the drill collar and are approximated as magnetic dipoles. The conductivity of the earth in the vertical direction /spl sigma//sub v/ and horizontal direction /spl sigma//sub h/ are almost always different. When an MWD resistivity tool enters a new bed, the response is compared with the precomputed logs to aid in the determination of the location of the drill bit. The MWD tool response, however, is sensitive to resistivity anisotropy. An alternative method is used to derive analytical expressions for the Sommerfeld-type integrals. Numerical results give typical MWD tool response as a function of the inclination angle /spl theta/ the tool makes with respect to the axes of anisotropy and also as a function of the anisotropy index /spl kappa/=(/spl sigma//sub h///spl sigma//sub v/)/sup 1/2/.

The performance evaluation of MWD logging tools using magnetic and electric dipoles by numerical simulations

Traditional measurement-while drilling (MWD) logging tools use magnetic dipoles (coils) as transmitting and receiving antennas and operate at a fixed frequency. In this paper, a new MWD tool using electrical dipoles and using pulses as transmitting signals is investigated and its performance is compared to the coil-type MWD tool in the same formation using a numerical simulation technique. The performances of these two different tools are compared both in the time domain and in the frequency domain. A time-domain transmission-line-matrix (TLM) method is used to perform the analysis. It is shown that a pulsed electric-dipole type MWD tool is superior to a coil-type MWD tool in detection of formation boundaries in all the tested cases. It is further suggested that an MWD tool using electric dipole antennas may be more sensitive in practical applications.

Stratigraphic Control and Formation Evaluation of Horizontal Wells With MWD

Summary. Sandstone reservoirs in the Gulf of Mexico typically do not form horizontal planes, and a predetermined course for a horizontal well cannot ensure that the well path will remain within the producing interval throughout the horizontal section. Detecting approaching bed boundaries and fluid contacts early enough to make the changes necessary to keep the well path in the producing interval is an important technical issue during the planning and drilling of horizontal wells. The first two horizontal wells drilled in the Gulf of Mexico achieved this objective with measurement-while-drilling (MWD) resistivity measurements and with supporting computer modeling for bed boundary detection. Introduction MWD propagation resistivity measurements can effectively detect approaching bed boundaries several feet from the borehole if there is a significant resistivity contrast between the two beds. In the well planning stage, the MWD log response can be modeled from the horizontal-well plan and data from offset wells. During drilling, the modeled log response can be compared with realtime directional and log data to monitor and correct the path as necessary. Finally, the MWD log and directional data can be used in postdrilling evaluation (1) to perform a petrophysical evaluation of the well, (2) to determine actual reservoir geometry, and (3) to plan completion and production strategies. Case histories illustrate how a combination of MWD measurements can be used to plan horizontal-well paths, maintain realtime stratigraphic control of the horizontal-well path, and evaluate the reservoir without requiring deployment of openhole wireline logs in the horizontal section. Background Texaco Eastern E and P Region has produced gas and condensate from deep reservoirs in the East Cameron (EC) Block 265 field, which encompasses EC Blocks 265, 278, and 283 in the Gulf of Mexico, 195 nautical miles southwest of New Orleans (Fig. 1). Three prolific gas sands were recognized in the field area northwest of Platforms A and B; however, platform placement relative to the shallow subsurface geologic structures made conventional development drilling and production in these three sands difficult. Recent technological advances in horizontal-drilling techniques made it possible to consider extended-reach, horizontal, or near horizontal wells as viable economic alternatives for producing these reservoirs; however, none of these methods had been attempted in the unconsolidated sediments common to the Gulf of Mexico. EC Block 265 field production history indicated probable water coning in one of these large gas reservoirs. A horizontal well was designed for this reservoir to reduce water coning by extending the drainage radius and reducing pressure drop at the wellbore/sand interface. After the horizontal-well plan was developed and the associated engineering issues addressed, two problems remained: how to predict accurately when the drill bit crossed the boundary between the shale bed and the objective gas sand below, and how to determine the location of the wellbore within the objective hydrocarbon section as drilling progressed. A full-service MWD tool was chosen to supply directional, gamma ray, and resistivity data for use in well-path monitoring, correlation with offset wells, and formation evaluation. The use of MWD technology provided a critical advantage: MWD modeling capabilities made it possible to predict tool response, and these predictions could be used as a guide during drilling. With data from offset wells, resistivity values in the objective reservoir were modeled for a 2-MHz MWD dual propagation resistivity (DPR) response at 87, 90, and 93 degrees angles. During drilling, these models were used successfully m combination with real-time data for well-path monitoring, offset well correlation, and stratigraphic prediction. Why Drill a Horizontal Well? A typical Gulf of Mexico field development and production plan begins with producing hydrocarbons from the deepest known stratigraphic reservoir and proceeding upward until the shallowest pay sands are fully exploited. Considering the development from each individual platform, the EC Block 265 field followed this general rule. After development drilling ceased on Platform A and two initial Platform B wells were drilled, Texaco elected to use a 3D seismic survey to evaluate the potential of additional fault blocks and deeper reservoirs in the EC Block 265 field. Platform B, set in 173 ft of water, was strategically placed to avoid penetrating shallow gas hazards en route to deeper objectives. The major difficulty of this development plan was to drain the shallow gas reservoirs properly without causing significant water coning. A horizontal or near-horizontal well was determined to be the best way to open up sufficient reservoir drainage footage and to reduce or eliminate JPT P. 1134⁁

A case study in modeling a nuclear formation evaluation sub

Measurement-while-drilling (MWD) requires extremely rugged tools. These tools are called subs. The modular neutron porosity (MNP) sub is one of several modular formation evaluation MWD tools that can be joined together in various combinations at the wellsite. The design of this sub was based heavily on the results of Monte Carlo modeling. Modeling efforts for the MNP sub are discussed. All modeling for the MNP tool was performed using the MCNP code. Once the model has been developed, its credibility must be established by comparing model predictions with experimental results. This requires that experiments meet stringent criteria. Standard experiments use large tanks filled with carefully prepared rock matrices. Eleven such tanks were initially available. The model results are compared with measurements taken in these tanks. The model can be used to predict tool response to many situations not reproducible in a laboratory. High temperatures, high pressures, and pore fluids composed of liquid-gas mixtures are typical of conditions encountered in real oil wells that are difficult to reproduce in a laboratory. Tool design and the effects of design modifications can also be evaluated efficiently using the model. >