Non-magnetic collars must be strong, tough, and corrosion resistant to withstand dynamic drillstring loads while also providing robust housings for measuring and logging-while-drilling (MWD/LWD) tool electronics. This paper describes a materials solution to problems related to the corrosion of drill collars in hostile well conditions. Typical nitrogen-strengthened chrome-manganese drill collar alloys are at risk of early retirement or downhole failure due to pitting, stress corrosion cracking (SCC), and sulfide stress cracking (SSC). Tool non-productive time due to increased maintenance, repair, overhaul frequency, and premature removal from service increases operating costs. The results of laboratory trials in conditions representative of active drilling basins show the differentiated performance of a chrome-nickel stainless steel and nickel-based alloy 718 relative to more common chrome-manganese stainless grades currently in wide-spread use. The pitting resistance, SCC resistance, and SSC resistance of both chrome-nickel stainless and nickel grade were found to be significantly better under wide ranging conditions and confirmed the capacity of both alloy systems to outlast incumbent drill collar grades.

The present work focuses on the stability of drill strings in vertical wellbores. The first rigorous treatment of stability of drill strings for vertical wellbores was presented by Lubinski (1950) and his equation is till most widely used in the industry. Cunha (2004) stated that since Lubinski (1950) used power series to solve differential equation governing the stability problem, and the terms of power series become very large for long drill strings, therefore, after a certain length, the calculations may lead to inaccurate results. Mitchell and Miska (2011) stated that analytical solution for infinite-length drill string is used for deep vertical wells in the industry. The subject studied in this study is of great importance in designing the bottom hole assemblies in deep and ultra-deep vertical wells to eliminate problems associated with instability of drill strings. The study includes Finite Element Method (FEM) solution of critical sinusoidal buckling force for 5 different drill collars with 21 different lengths starting from 1000 ft. up to 25000 ft. The main objectives of the study are to see the difference between post-buckling behavior of slender-dominated long hanging drill strings with stiffness-dominated short hanging drill strings in vertical wellbores; to investigate the effect of flexural rigidity of drill collars on decrease of the critical buckling forces as a length parameter of the drill string; and to see the behavior and amount of decrease in the critical buckling forces as the length of the drill string increases. And, it is showed that critical buckling force decreases as the depth of the well increases according to FEM solutions, although, analytical solution gives only a fixed critical buckling force for a specific pipe independent from the length. Also, it is showed that post-buckling behavior of slender-dominated long hanging drill strings with stiffness-dominated short hanging drill strings in vertical wellbores are different.

Severe vibrations in drilling systems and bottom-hole assemblies can be caused by cutting forces at the bit or mass imbalances in downhole tools such as mud motors. Vibrations can lead to reduced drilling performance, poor measurement quality and reduced reliability. Models are important to understand the phenomena and predict loads. So far models are established that calculate the dynamic behavior of the drilling system from a global point of view: The drilling system is modeled with simplified geometry and placed in the drilling environment under consideration of the wall contacts with the borehole and the fluid properties. Global models are typically used for optimization of drilling parameters such as the rotary speed or the flow rate with respect to estimated dynamic loads. Global models are not suitable for detailed modeling and analysis for optimization on a tool component level. A system-approach is established to overcome the limitations. A method is developed to connect a detailed 3D-model of a downhole tool with the model of the drilling system and the bit that is placed in the global drilling environment. The method enables new insights into the behavior of downhole tools that can be used to optimize downhole tools with respect to their reliability and their performance: Dynamic loads on tool components such as probes and pockets can be calculated to optimize the tool design and increase reliability. The probe design can be optimized to reduce the dynamic loads on sensor components and significantly increase the measurement quality. In a case study the method is validated with measurements. Herein, torsional eigenfrequencies and corresponding mode shapes which are localized to the bottom-hole assembly as well as the resulting tool stresses and loads are considered. The impact of a dampening tool to mitigate torsional vibrations is discussed. In a second example the capability of the method to capture lateral vibrations under consideration of wall contacts and mass imbalances is shown. The method is used to optimize the design of a downhole tool to decrease the dynamic loads at sensor components that are placed in a probe. The system-approach of the method allows to efficiently simulating the vibrational behavior of tool parts in an arbitrary detail and in a global drilling environment. The new method enables improved tool design for performance and reliability and increased measurement quality.

ERD wells are commonly associated with major challenges for installation of casing and liner strings. These wells typically present high torque and drag parameters that jeopardize getting strings to total depth. In an attempt to optimize production, a major oil company in Angola decided to re-enter the study well in early 2016. A sidetrack was opened in the 9 5/8-in. casing, and drilling continued in the 8 ½-in. hole and penetrated the target zone in the highest location. Then a 7-in. production liner was run. To reach the target zone, 5,583 ft of 8 ½-in. hole was drilled and deviations varied from 45° to 87°. This trajectory was a challenge for subsequent running of 7-in. liner. Torque and drag (T&D) models showed liner rotation at total depth (TD) was not possible, and a surge model indicated likelihood of mud losses while running the liner. Liner hanger technologies became a very important phase of well construction, and service companies developed advanced liner hangers to overcome hostile well environments. In this case study, the short time available from the planning to execution phases and the current oil market conditions made it imperative that the right equipment, service, and technology were available in country. To achieve the ideal working parameters and get the liner to bottom, a thorough assessment needed to be performed to ensure risk mitigation. This paper presents summarizes steps considered during planning for the 7-in. liner run including a detailed engineering analysis that enabled the operator to make the best decisions based on the available resources. The paper will also discuss lessons learned and best practices captured during the job that will be used for subsequent liners in similar wells. The case study well was planned as a sidetrack from an existing well that had been shut in because of low performance. The main well had been drilled and completed as a single gravel pack in 2007. The objective of the sidetrack was to penetrate the reservoir organized complex in the structurally highest location to access reserves and optimize production. A constrained initial production was estimated at 6035 BFPD. An operations overview of the complete intervention is as follows: Set a 8 ½-in. whipstock in existing 9 5/8-in. casing at 8,400 ft and mill the window. Drill an 8 ½-in. hole section to 13,923 ft MD / 6,657 ft TVD. Run and cement 7-in. liner. Displace the hole with completion fluid. Perform cement bond logs and hand the well over to completion. The 8 ½-in. hole was drilled as shown in Fig. 1 and Table 1 . The well trajectory offered a challenge to get the 7-in. liner to bottom and to achieve a good cement bond in the production section. Figure 1 Well trajectory for case-study well Table 1 Geometric features of case-study well Measured depth at whipstock point 8,400 ft TVD at whipstock point 5,279 ft Deviation at whipstock point 78.25° Length of 8 ½-in. hole 5,583 ft Measured depth at TD of 8 ½-in. hole 13,983 ft TVD at 8 ½-in. hole TD 6,695 ft Maximum deviation in 8 ½-in. open hole 86.9° Maximum dogleg severity in 8 ½-in. open hole 5.21°/100 ft at 8,933 ft MD The operator and the liner hanger service company used proprietary simulation tools during the planning phase to predict possible issues for running the liner. The simulation considered main aspects, such as well trajectory and the influence of the whipstock installed in the 9 5/8-in. casing. All analyses were performed and maximum working parameters were defined and included in the well program. The operator also considered possible limitations that using standard equipment available in country might impose on well life. The final management decision was to proceed with the plan presented.

Wellbore instability resulted in the largest percentage of non-productive time (NPT) during drilling stage in oil industry. Wellbore instability during drilling includes: wellbore pack-off, excessive torque and drag, blowout, stuck pipe and other related well problems. Many studies assumed that wellbore instability problems were due to physical and chemical interactions between rocks and drilling fluid; and neglected impact of drillstring vibration on wellbore stability. Drillstring vibration is usually mitigated while drilling not for wellbore stability issues; but to prevent drillstring fatigue and downhole tools failure by not exceeding vibration operation limits for drillstring. This work aims to develop a new approach studies the impact of drillstring vibration on wellbore stability by analyzing different rock failure mechanisms can happen to wellbore due to drillstring vibration; and computing drillstring vibration limits (acceleration values) that can collapse wellbore. Rock failure mechanisms and drillstring dynamic behavior while vibration was studied to understand consequences happened due to drillstring collision with wellbore. Authors innovated a new model to predict drillstring vibration hotspots values that can collapse wellbore. Results show that drillstring vibration can collapse wellbore by three failure mechanisms: a- when drillstring vibration applies stresses above rock strength, rock compressive failure will take place; b- if drillstring vibration applies repeated cyclic loads on rock continuously; rock fatigue will occur; c- when cyclic loads on rock are not strong enough to cause rock failure; rock fatigue will reduce rock strength and lead to rock shear failure. Model computes drillstring acceleration values that can fail wellbore by these failure mechanisms; and calculates mud weight needed to prevent rock shear failure before and after reduction in rock strength due to rock fatigue. Model outputs must be compared with drillstring vibration operation limits; and the lower value must be used as a boundary limit for drillstring vibration while drilling to prevent wellbore collapse and drillstring failure. These will make model results used as an early detector for harmful drillstring vibration shocks on wellbore.

Offshore fields in Saudi Arabia are being developed based on optimum use of onshore drilling rigs. Rather than developing the field completely from offshore platforms, it is developed partially from man-made, interconnected drilling islands. Extended reach wells (ERWs) are necessary for optimum surface location use and maximum reservoir contact. As the wells increase the step-out, challenges arise not only during the drilling phase but also while running liners to target depth (TD). Wellbore geometry, hole instability issues and torque and drag forces, restrict the ability to deploy the liner to planned depths, setting technical limits to the oil and gas production potential. The main challenge of running liners through extended lateral sections is the lack of hookload to push the liner to TD, and the ability to rotate the drill pipe without rotating the liner. As more extended reach deployment becomes common practice, it is necessary to implement new running liner practices and tools that rotate the drill pipe above the liner, to break the frictional drag and make more surface weight available, to deploy the liners or completions to TD. This paper outlines the problem faced when deploying 7 in. liners in ERWs through 8½ in. hole lateral sections, and the solution using an innovative rotatable friction reduction tool, which allows the rotation of the drill pipe without transmitting torque to the liner. A case study is presented showing the main challenges, pre-job engineering calculations, field implementation, final results and lessons learned. Ultimately, the new rotatable friction reduction tool was a key component in the deployment of the longest 7 in. liner run in Saudi Arabia so far.

Jar technology has been around in the oil industry for several decades and its basic principles have remained primarily the same. As the oil industry moves forward in the exploration and development of unconventional hydrocarbon reserves, the demand for tougher, more reliable, and safer tools is more critical. Deeper wells and more complex well geometries are pushing the drilling envelopes, requiring tools to be engineered not only to withstand higher stresses downhole, but also to provide higher levels of safety on the rig floor. Through the engineering of simple but ingenious features, this paper describes how jar technology has been taken to a higher level. A jar has been designed acknowledging the most important features required in the current demanding drilling scenarios. The industry is not only looking for safer and more reliable tools, but also tools that will provide higher firing loads to increase the levels of success of freeing a drill string during a stuck pipe incident. The loads delivered during the first hours of a stuck pipe event can significantly improve the chances of retrieving the drill string safely to surface. The design features employed in this new technology maintain the same operating procedures of standard designs, but have increased the torque, tensile, and pressure ratings of the tool. In addition, current technology can suffer damage from excessive internal pressure build up when the over-pull rating of the tools are exceeded; particularly in deepwater applications where heave can be a contributing factor. A device has been engineered to protect the tool if such a condition is reached. The new jar also features a modular safety mechanism that will eradicate the use of the traditional safety collars eliminating the potential hazards of dropping objects on the rig floor. This paper will provide an overview of the innovative technology, plus review the initial field trials. Testing and field trials will demonstrate how this technology is a true step change, matching the growing demands of the drilling industry.

Abstract This paper provides a review of recent technology advancements and addresses practical considerations associated with drill pipe and drill stem components for extreme drilling applications. Ultra-high torque double-shoulder rotary connections are often employed in these applications potentially complicating proper design and material selection for cross-overs, top-drive subs, pup joints and other accessories These new connections often employ materials with higher strength requirements than the standard API connections they replace. The paper outlines recommendations for material strength and design parameters for various drill stem accessories. High-performance connectors' impact on BHA design is also addressed. Weight tapered drill string designs with double-shoulder connections can result in mismatched connection bores or ID's. Guidelines to accommodate this mismatch along with supporting finite element modeling results are presented. Proper hardband selection, application and maintenance are essential to successfully and safely drill world-class UD, ER and deep-water projects. Hardband system trends for critical applications are highlighted, and recent hardband casing wear and tool joint protection test results obtained using an advanced hardband wear machine are discussed. Due to the dramatic increase in oil prices the industry has seen a re-emergence of deep and ultra-deep drilling projects that encounter H 2 S gas. The paper provides initial results from a study of the effect on S-grade drill pipe samples to various H 2 S exposure concentrations, representing typical conditions when circulating a gas kick to surface. The surge in critical drilling has led to an increasing trend of drill stem friction heating failures. The paper includes characteristic features of these failures along with case histories and prevention methods. High-speed telemetry (wired) drill pipe has been successfully deployed on critical drilling applications in various parts of the world. The paper provides an update on this exciting technology and reviews recent case histories. Material Requirements for Drill Stem Components and Accessories A drill string consists of many components. In addition to the drill pipe that is manufactured from upset and heat treated tubes with specified minimum yield strength (SMYS) values ranging from 75,000 psi to 135,000 psi or up to 150,000 psi and higher for the new ultra-high strength drill pipe with friction welded tool joints that are generally machined from forgings with a SMYS of 120,000 psi there are drill collars, heavy weight drill pipe, cross-overs, top-drive saver subs and pup joints. Proper material selection for each component is critical to insure safe drilling operations. API specifications require material with SMYS of 120,000 psi for tool joints. API specifications permit lower minimum yield strength values for other drill stem components, see Table 1. Make-up torque values for connections machined on these other components with lower yield strength than the drill pipe tool joints must be adjusted down to account for the lower strength levels. If rig personnel are made aware of the lower make-up torque values and utilize these lower values when running the various components the string can be operated safely. Of course, these miscellaneous components can create a weak link in the string limiting maximum working torque for drilling operations. Often times the weaker components are only run near the bottom of the drill string where working torques are lower and the maximum surface drilling torques are not restricted by the weaker component. The situation can be further compromised with some of the newer proprietary connections that utilize tool joints with minimum yield strength values of 130,000 or 135,000 psi.

Abstract Applications such as close tolerance casing design and expandable liners, often necessary for deepwater and subsalt well construction, require underreaming to ensure adequate reservoir diameters. However, underreaming generates uncertainty sometimes, particularly in hard formations. Instead of direct real-time verification, reliance is placed on indirect indicators such as increased standpipe pressure or drilling torque. The uncertainty as to whether the desired wellbore-diameter is actually delivered exists until a calliper is run. Subsequently, a correction run may still be needed, hence additional cost. This paper explains a design process to solve these problems. An explanation of a novel technology illustrates how it verifies and detects variations in underreaming diameter in real-time. A telemetry system alerts the user if there is a significant difference between planned and actual diameters and prompts a check of operational parameters such as WOB, drilling fluid pump rates or RPM, if needed, repeat underreaming in the uncertain interval. A comparative evaluation was made of the drilling dynamics of underreamers and the root cause analysis of NPT. For example, bit only RoPs are higher than underreaming RoPs and in a combination BHA the bit tends to out-drill the underreamer. Not only does the underreaming have limited cutter contact with the wellbore and limited hydraulics, BHA modelling shows these limitations are worsened by wall-side forces and bending moments which are concentrated at the underreamer. The design process sought to improve traditional technology by considering RoP, improved underreaming BHA stability and generate a more balanced cutting action. CFD (Computational fluid dynamics) show how a novel configuration of nozzle distances and orientations improves cuttings evacuation and reduces particle residence times. In conclusion, a drilling engineering risk table presents 20 underreaming applications and is used as a benchmark for a comparative evaluation of underreaming risk types. Introduction Oil and gas companies are exploring and developing reserves in more challenging basins such as those in water-depths exceeding 6,000 ft (1830m) or below massive salt sections. These wells have highly complex directional trajectories with casing designs including 6 or more well sections. Known as 'designer' or 'close tolerance casing' wells, such wells have narrow casing diameters with tight tolerances and have created a need to enlarge the wellbore to avoid very small diameter reservoir sections and lower production rates (Figure 1 PPFG). In other applications such as cemented solid expandable liners, underreamers are required to provide the tolerance for tubular expansion to occur or for increased cement sheath. The tolerances between the enlarged well-bore and the expanded tubular are very close. Therefore, the bottom-hole assemblies that are needed to drill or complete these wells routinely include devices to underream the well-bore. In this way, underreamed hole size has become an integral part of well construction and there is now an increased dependence on underreaming to meet planned wellbore diameters across the industry (Ref 2).

Abstract Drilling ultra-deep (UD) wells places significant requirements on the drill string. Lengthy drill strings lead to high tensile loads which can lead to slip crushing of the drill string, hoisting capacity issues and drill pipe collapse capacity concerns at the blowout preventer (BOP). BOP shear rams may also have difficulty shearing today's high strength, high toughness drill pipe. BHA connection failures pose greater risk and cost at UD well depths. This paper analyzes the many challenges associated with drill string designs specifically for UD drilling. It presents emerging drill string technologies that are solutions expected to increase depth capability for the industry's continued advancement of deep drilling operations. Trend of Deep TVD Drilling Deep drilling trends in the United States (U.S.) and throughout the world are increasing. Since 1995, the number of U.S. wells drilled greater than a total vertical depth (TVD) of 15,000 ft has more than doubled (Figure 1). The number of annual, active U.S. rigs drilling greater than 15,000 ft TVD has nearly tripled (Figure 2). [1] The number of high pressure, high temperature (HPHT) completions in the U.S. has nearly tripled since 2000. [2] U.S. gas production from "deep" formations is also expected to double from 7% in 1999 to 14% by 2010. [3] During late 2005, the Knotty Head well in Green Canyon Block 512 was drilled to a total depth of 34,189 ft, the Gulf of Mexico's deepest well ever drilled. The 14–3/4 in. hole section was drilled to 24,085 ft and over 4 million ft or approximately 775 miles (approximately 1,250 kilometers) of drill pipe was tripped throughout the course of the well. The previous record well in the Gulf of Mexico was drilled earlier in the year to a total depth of 32,727 ft. [4] Many rig contractors are presently upgrading or building new jack-up, semi-submersible and dynamically positioned drill ship rigs capable of drilling to 35,000 ft total depth (TD). One rig contractor, in particular, recently contracted the manufacture of a U.S. $650 million dynamically positioned drill ship capable of drilling in 12,000 ft of water to well depths of 40,000 ft. [5] Wells to these depths will require substantial investment and the advancement of facilitating technologies for ultra-deep drilling (UDD). Extended Reach vs. Ultra-Deep TVD Drilling Enabling technologies and innovative techniques have contributed significantly to the industry's current ability to reach significant well departure distances, which is evidenced throughout extended reach (ER) projects around the world. Some of these technologies include: [6], [7], [8], [9] and [10] Use of sophisticated computer drilling simulators Advancements in drilling fluid technologies providing increased lubricity and improved cuttings transport, wellbore stability and formation damage resistance characteristics Drill string and casing friction reducing tools Drill pipe high torque tool joints and high friction factor thread compounds Intermediate drill pipe sizes such as 5–7/8 in. Improved hole cleaning procedures Casing floatation and liner rotation techniques Highly variable gauge stabilizers (H-VGS) and rotary steerable systems (RSS) Advancements in downhole measurement tool capabilities such as the introduction of pressure while drilling (PWD) tools and improved surveying and logging technology Development and use of drill string dynamics monitoring and mitigation systems New and improved rig and surface equipment While these technologies have contributed successfully in pushing the ER envelope to increase recoverable reserves, significant obstacles remain when drilling UD and deep directional wells of lower reach/TVD ratios generally not characterized as ER.

Abstract Oilwell drilling is often accompanied by self-excited stick-slip vibrations. This type of motion may also excite severe axial and lateral vibrations in the bottom hole assembly, causing damage to the equipment. This paper presents a fully coupled model for axial, bending and torsional vibrations, and an active control strategy for stick-slip vibrations. The proposed model includes the mutual dependence of these vibrations, as well as their related effects such as, bit/formation and drillstring/borehole wall interactions. The control strategy is based on optimal state feedback control designed to control the drillstring rotational motion. Simulation results are in close qualitative agreement with field observations regarding stick-slip vibrations. It is shown that the proposed control is effective in suppressing stick-slip vibrations once they are initiated. It is also demonstrated, that axial vibrations help in reducing stick-slip vibrations and the control effort. However, care must be taken in selecting a set of operating parameters to avoid transient instabilities in the axial and lateral motions. Introduction It is well known that stick-slip vibrations are detrimental to the service life of oilwell drillstrings and down-hole equipment. Large cyclic stresses induced by this type of motion can lead to fatigue problems. In addition, the high bit speed level in the slip phase can excite severe axial and lateral vibrations in the bottom hole assembly, which may cause bit bounce, excessive bit wear and reduction in the penetration rate. Stick-slip vibrations are self-excited, and generally disappear as the rotary table speed is increased beyond a threshold value. However, increasing the rotary speed may cause lateral problems such as backward and forward whirling, impacts with the borehole wall and parametric instabilities. Therefore, it is desirable to extend the range of safe drilling speeds. In order to achieve this, a proper understanding of the coupled dynamics of drillstrings is necessary. For this reason drillstring vibrations and ways to control them have received a lot of attention in recent years [1–8]. The control methods include operational guidelines to avoid, eliminate or reduce torsional vibrations as well as active control methods using feedback. Although most proposed control methods have been shown to be successful in controlling torsional vibrations, the effects of this control on bending vibrations have not been studied. In order to design and implement an effective control system, a coupled model is essential for identifying the critical speeds as well as predicting the behavior of the whole system [9]. Recently, the authors proposed a model that considers the full coupling between torsional and lateral vibrations of actively controlled drillstrings [10]. The proposed model was demonstrated to be quite realistic with respect to stick-slip vibrations, which were effectively eliminated through an optimal state feedback control scheme. In the current paper, this model is extended to include the effects of axial motion. The Weight-on-Bit (WOB) and Torque-on-Bit (TOB) expressions are more realistic since they are directly related to the axial and torsional motions. Simulation results show that axial vibrations have a positive effect in reducing stick-slip vibrations and the control effort. However, control of torsional vibrations may have negative effects in increasing axial and lateral vibrations. Therefore, care must be taken in selecting the operating parameters.

SPE Members Abstract A high pressure salt water influx was encountered while drilling a Deep Exploration well at 20,363 ft. Attempts were carried out to control this influx but the well killed itself. The fishing operations revealed the drill pipe to be plugged with salt balls. The paper describes and analyses the phenomenon paper describes and analyses the phenomenon that resulted in the formation of the salt balls which subsequently plugged the drill pipe and led to the killing of the well. pipe and led to the killing of the well. 2. Introduction The onshore exploration for gas in the Khuff formation of the Emirate of Abu Dhabi started in 1980. The first Khuff well was drilled in Bu Hasa field to a depth of 20,363 ft where a highly pressurized salt water influx was encountered. The bottom hole pressure build-up extrapolation indicated 21,080 psi at this depth with a bottom hole static temperature of 440F. A constant influx of salt water contaminated the mud during the killing operation and large quantities of salt were evident on the Shale Shaker screens. During the initial killing operations drill pipe parted at 11,860 ft. The killing pipe parted at 11,860 ft. The killing operations were continued by bullheading mud and fracturing the formation. An underground water flow from the drill pipe fish and down annulus into a thief zone was suspected. The well subsequently died and the top section of drill pipe was recovered. Fishing operations then proceeded and three sections of drill pipe were cut and recovered to a depth of pipe were cut and recovered to a depth of 12,882 ft. The fish was found to be plugged with balls of 99.9% Sodium Chloride identical in size and colour below 12,633 ft. The Investigations and analysis which have been carried out to determine the structure of the salt balls indicated that their crystallization may have been generated by cooling or thermal gradient effect enducing an over-saturation of the solution. 3. DESCRIPTION 3.1 WELL DESIGN: The formation of the salt balls occurred in the first deep Khuff well drilled onshore Abu Dhabi Emirate in the Bu Hasa field (Fig. 1). The first Khuff well was designed according to the information collected from the other Khuff wells drilled in the area. The well was designed with 10,000 psi pressure rating for casing scheme and psi pressure rating for casing scheme and wellhead configuration (Fig. 2). 3.2 STATUS and CONDITIONS OF THE WELL PRIOR TO THE KICK: The well was spudded in October, 1980. The 30", 20" and 13.3/8" casings were set without major problems. The 12.1/4" hole was drilled to a depth of 16,053 ft when a kick was experienced from the Jilh formation. Estimated formation pressure gradient was 0.72 psi/ft. psi/ft. A heavy 9 5/8" liner was successfully run and cemented with shoe at 15,800 ft (i.e. above the kick depth). P. 267

Abstract A magnetometer inclinometer system developed to orient mud motors and produce survey data, additionally provides data on magnetic field strength and inclination. Observations from field operation of this system have initiated a detailed investigation of magnetic conditions during drilling. An analysis of a field data set is used to support the belief that magnetic pole strength changes can be predicted. A procedure to quantify these changes is described. Introduction Magnetic interference can be defined as the compass error resulting from interaction of the earth's magnetic field and a field produced by one or more separate sources. In drilling operations, these sources can be categorized as follows: Magnetized steel sections in the drilling assembly. Adjacent casing strings or sidetracked drilling assemblies. Geological sources. Upper atmosphere disturbances. This paper concerns itself primarily with the first source, since its effect can be controlled by the correct selection of non-magnetic collar length and compass spacing. The application of classical magnetic theory, together with a better understanding of the changes in the magnetic properties of the drilling assembly as drilling progresses, predicts the ability to analyze specific drilling assemblies and make good estimates of their effects on survey accuracy for the particular geographic location and wellbore path under consideration. The complexity of the problem and the need to complete wells with a minimum of fuss has led to the current empirical guidelines on non-magnetic collar and spacing requirements. These are based on simplified, "worst case" assumptions and experience. This is the common sense approach for field operations. The rewards for a better understanding of the magnetic properties in a drilling assembly are high. Not only will it be possible to verify "worst case" assumptions, but it will also be possible to analyze surveys in retrospect as well possible to analyze surveys in retrospect as well as in advance of drilling. The above has obvious implications, for example, in the drilling of relief wells. Although qualitative support is often present in field results, good numerical data to test the theory is hard to find, since the survey device is deliberately positioned so as to minimize the effects we are now seeking to measure. However, the analysis presented is one example of a case where the magnetometers of an orientation probe were close enough to a mud motor assembly and far enough from the heavy weight drill pipe above; that the analysis is simplified. Also in this example, the effects of casing and of geological sources were apparent. In addition to the field results, a procedure is described to accurately determine the quantities involved under controlled conditions. Now that the problem is more clearly understood, a limited number of such measurements should provide good data to apply to the general case. THEORY The theory is founded upon the basis that we are dealing with the phenomenon of induced magnetism, i.e., the steel sections of the drilling assembly will become magnetized by the presence of the earth's field. For purposes of presence of the earth's field. For purposes of calculation, this can be treated as the appearance of magnetic poles of the magnitudes mu and ml on the ends of the steel sections.